GEL US Equity☆

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 New York Stock Exchange, or NYSE, under the ticker symbol “GEL.” We are (i) a provider of an integrated suite of midstream services (primarily transportation, storage, sulfur removal, blending, terminaling and processing) for a large area of the Gulf of Mexico and the Gulf Coast region of the crude oil and natural gas industry and (ii) one of the leading producers in the world of natural soda ash. We provide an integrated suite of services to refiners, crude oil and natural gas producers, and industrial and commercial enterprises and have a diverse portfolio of assets, including pipelines, offshore hub and junction platforms, refinery-related plants, storage tanks and terminals, railcars, rail unloading facilities, barges and other vessels, and trucks. The other core focus of our business is our trona and trona-based exploring, mining, processing, producing, marketing, logistics and selling business based in Wyoming (our “Alkali Business”). Our Alkali Business mines and processes trona from which it produces natural soda ash, also known as sodium carbonate (Na2CO3), a basic building block for a number of ubiquitous products, including flat glass, container glass, dry detergent, lithium hydroxide and lithium carbonate (which are key inputs in the production of lithium batteries) and a variety of chemicals and other industrial products, and has been operating for approximately 75 years.

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

•Overview of 2023 Results

•Recent Developments and Initiatives

•Results of Operations

•Other Consolidated Results

•Financial Measures

•Liquidity and Capital Resources

•Guarantor Summarized Financial Information

•Critical Accounting Estimates

•Recent Accounting Pronouncements

Overview of 2023 Results

We reported Net Income Attributable to Genesis Energy, L.P. of $117.7 million in 2023 compared to Net Income Attributable to Genesis Energy, L.P. of $75.5 million in 2022.

Net Income Attributable to Genesis Energy, L.P. in 2023 was impacted by: (i) an increase in operating income associated with our reportable segments primarily due to increased volumes and activity in our offshore pipeline transportation segment and higher day rates in our marine transportation segment (see “Results of Operations” below for additional details on our individual segments); (ii) a decrease in depreciation, depletion and amortization expense of $16.0 million (see “Results of Operations” below for additional details); and (iii) an increase in our equity in earnings of equity investees of $12.0 million. Additionally, we had a decrease in income attributable to our redeemable noncontrolling interests of $30.4 million as the associated outstanding preferred units held at a subsidiary of our Alkali Business (our “Alkali Holdings preferred units,” which are further discussed in Note 12 to our Consolidated Financial Statements in Item 8) were redeemed during 2022.

These increases were partially offset by a gain on sale of assets of $40.0 million (of which $8.0 million was attributable to our noncontrolling interests) in 2022 associated with the sale of our 80% owned Independence Hub platform and an increase to interest expense of $18.5 million during 2023 (see “Results of Operations” below for additional details). Additionally, 2023 included a net unrealized loss of $36.7 million from the valuation of our commodity derivative transactions (excluding fair value hedges) compared to a net unrealized gain of $5.7 million during 2022.

Cash flows from operating activities were $521.1 million for the 2023 period compared to $334.4 million for 2022. This increase was primarily attributable to higher Segment Margin reported during 2023 (inclusive of $32.0 million of distributions received net to us from the sale of the Independence Hub platform asset, which is included in Segment Margin and a cash flow from investing activities in 2022 on the Condensed Consolidated Statement of Cash Flows) and positive changes in our working capital requirements during 2023.

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Available Cash before Reserves (as defined below in “Financial Measures”) decreased $1.4 million in 2023 to $351.2 million as compared to 2022 Available Cash before Reserves of $352.6 million, primarily due to the following items: i) an increase in distributions to preferred unitholders of $11.8 million; ii) an increase in interest expense of $18.5 million; iii) an increase in maintenance capital utilized of $10.3 million; iv) an increase in corporate general and administrative expenses of $8.0 million; and v) a decrease in income related to cancellation of debt of $8.6 million., as we repurchased and extinguished certain of our senior unsecured notes during 2022 This was almost fully offset by our increase in Segment Margin, which is further discussed below in “Results from Operations.” See “Financial Measures” below for additional information on Available Cash before Reserves.

Segment Margin was $827.1 million in 2023, an increase of $57.0 million as compared to 2022. We currently manage our businesses through four divisions that constitute our reportable segments - offshore pipeline transportation, soda and sulfur services, marine transportation and onshore facilities and transportation. A more detailed discussion of our segment results and other costs is included below in “Results of Operations”.

Distributions to Unitholders

On February 14, 2024, we paid a distribution of $0.15 per common unit related to the fourth quarter of 2023.

With respect to our Class A Convertible Preferred Units, we declared a quarterly cash distribution of $0.9473 per unit (or $3.789 on an annualized basis). These distributions were paid on February 14, 2024 to unitholders holders of record at the close of business January 31, 2024.

Recent Developments and Initiatives

Our primary objectives are to generate and grow stable free cash flows and continue to deleverage our balance sheet, while never wavering from our commitment to safe and responsible operations, as well as continue to advance and integrate our sustainability program. We believe the following are important to meet our objectives:

•New and increased volumes on our existing offshore assets in the Gulf of Mexico through long-term contracted commercial opportunities that require minimal to no additional investment from us. This includes a full ramp up in volumes from the Argos FPS, which achieved first production in April 2023, and from the King’s Quay FPS and the Spruance development, both of which achieved first production in 2022.

•New incremental volumes from long-term contracted offshore commercial opportunities in the Gulf of Mexico, including the Shenandoah development, which will tie into our SYNC pipeline and further downstream to our CHOPS pipeline, and the Salamanca FPS, which will tie into our existing SEKCO pipeline for further transportation downstream to our existing pipeline network. These developments and their associated volumes are currently expected to come online in late 2024 and 2025.

•Increased capacity for soda ash production from our original Granger facility and its approximately 500,000 tons of annual production, which came back online on January 1, 2023, and our GOP, which reached substantial completion and achieved first production in the fourth quarter of 2023 and is expected to ramp up to its 750,000 incremental tons of annual production in 2024, bringing total pro forma annual production capacity to approximately 4.8 million tons.

•We continue to have a significant amount of available borrowing capacity under our senior secured credit facility, which will allow us, when combined with our increasing cash flow from operations as discussed above, to fund our high return capital projects, which will provide future cash flows to continue to further deleverage our balance sheet.

Offshore Growth Commitments and Capital Projects

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 that have a combined production capacity of approximately 160,000 barrels per day. In conjunction with these agreements, we are expanding the current capacity of the CHOPS pipeline and constructing a new 100% owned, approximately 105-mile, 20” diameter crude oil pipeline, the SYNC pipeline, to connect one of the developments to our existing asset footprint in the Gulf of Mexico. We plan to complete the construction in line with the producers’ plan for first oil achievement, which is currently expected in late 2024 or 2025. Additionally, in 2023, we entered into several additional definitive agreements with existing producers to further commit additional volumes transported on our 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 senior secured credit agreement throughout the construction period.

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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, 2023 increased $388.0 million, or 14%, from the year ended December 31, 2022, and our costs and expenses (excluding the gain on sale of assets in 2022) increased $333.6 million, or 13%, between the two periods, with a net increase to operating income (excluding the gain on sale of assets in 2022) of $54.4 million. The increase in our operating income during 2023 is primarily attributable to the increase in our reported Segment Margin primarily as a result of increased volumes and activity in our offshore pipeline transportation segment and increased utilization and day rates in our marine transportation segment, as well as lower depreciation, depletion and amortization during 2023. These increases were offset by a net unrealized loss of $36.7 million in 2023 as compared to a net unrealized gain of $5.7 million during 2022 from the valuation of our commodity derivative transactions (excluding fair value hedges).

A substantial portion of our revenues and costs are derived from the purchase and sale of crude oil in our crude oil marketing business, which is included in our onshore facilities and transportation segment, revenues and costs associated with our Alkali Business, which is included in our soda and sulfur services segment, and revenues and costs associated with our offshore pipeline transportation segment. We describe, in more detail, the impact on revenues and costs for each of our businesses 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 18% to $77.58 per barrel in 2023 as compared to $94.90 per barrel in 2022. We would expect changes in crude oil prices to continue to proportionately affect our revenues and costs attributable to our purchase and sale of crude oil and petroleum products, producing minimal direct impact on Segment Margin, Net income (loss) and Available Cash before Reserves. We have limited our direct commodity price exposure in our crude oil and petroleum products 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 net impact on our Segment Margin. However, we do have some indirect exposure to certain changes in prices for oil and petroleum products, 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 previous section above entitled “Risks Related to Our Business”.

As it relates to our Alkali Business, our revenues are derived from the extraction of trona, as well as the activities surrounding the processing and sale of natural soda ash and other alkali specialty products, including sodium sesquicarbonate (S-Carb) and sodium bicarbonate (Bicarb), and are a function of our selling prices and volume sold. We sell our products to an industry-diverse and worldwide customer base. Our sales prices are contracted at various times throughout the year and for different durations. Our sales prices for volumes sold internationally are contracted for the current year either annually in the prior year or periodically throughout the current year (often quarterly), and our volumes priced and sold domestically are contracted at various times and can be of varying durations, often multi-year terms. The majority of our volumes sold internationally are sold through ANSAC, which became a wholly owned subsidiary of our Alkali Business on January 1, 2023 as we became the sole member of it at that time. ANSAC promotes export sales of U.S. produced soda ash utilizing its logistical asset and marketing capabilities. During the year ended December 31, 2023, in addition to the volumes supplied by our operations and sold by ANSAC, ANSAC continued to receive a level of soda ash supply from certain former members to sell internationally, which is expected to continue in some capacity for at least the next several years. As a result of consolidating the results of ANSAC beginning on January 1, 2023, the sale of the soda ash volumes by ANSAC that were supplied by non-members are included in our consolidated results and have a proportionate effect to our revenues and costs, with little to no direct impact to our reported Segment Margin, Net income (loss) and Available Cash before Reserves. We will continue to report the sales volumes of soda ash included in the operating results table for our soda and sulfur services segment shown below as we have historically reported them for comparability purposes and due to the minimal impact these incremental sales volumes from ANSAC have on our reported Segment Margin, Net income (loss) and Available Cash before Reserves. Our sales volumes can fluctuate from period to period and are dependent upon many factors, of which the main drivers are the global market, customer demand, economic growth, and our ability to produce soda ash. Positive or negative changes to our revenue, through fluctuations in sales volumes or sales prices, can have a direct impact to Segment Margin, Net income (loss) and Available Cash before Reserves as these fluctuations have a lesser impact to operating costs due to the fact that a portion of our costs are fixed in nature. Our costs, some of which are variable in nature and others are fixed in nature, relate primarily to the processing and producing of soda ash (and other alkali specialty products) and marketing and selling activities. In addition,

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costs include activities associated with mining and extracting trona ore, including energy costs and employee compensation. In our Alkali Business, during 2023, as noted above, we had positive effects to our revenues compared to 2022 (with a lesser impact to costs) due to slightly higher domestic and export pricing of soda ash and higher sales volumes. For additional information, see our segment-by-segment analysis below.

Our offshore Gulf of Mexico crude oil and natural gas pipeline transportation and handling operations focus on 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. Our revenues are primarily derived from the fees, typically on a per barrel basis, we charge to transport and deliver commodities (or reserve capacity on our infrastructure in some cases) downstream to other pipelines or refineries along the Gulf Coast. The shippers on our offshore pipelines are mostly integrated and large independent energy companies whose production is ideally suited for the vast majority of refineries along the Gulf Coast. Their large-reservoir properties and the related pipelines and other infrastructure needed to develop them are capital intensive and yet, we believe, economically viable, in most cases, even in volatile commodity price environments. Costs include activities associated with employee compensation and benefits, the maintenance of our pipelines and pipeline related infrastructure, marketing, and other variable type expenses associated with operating the business. We do not expect changes in commodity prices to impact our Net income (loss), Available Cash before Reserves or Segment Margin derived from our offshore Gulf of Mexico 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 and petroleum products.

In addition to our crude oil marketing business, Alkali Business and offshore pipeline transportation and handling operations discussed above, we continue to operate in our other core businesses, including our sulfur services business and our onshore-based refinery-centric operations located primarily in the Gulf Coast region of the U.S., which focus on providing a suite of services primarily to refiners. Refiners are the shippers of approximately 98% of the volumes transported on our onshore crude pipelines, and refiners account for approximately 90% of the revenues from our marine transportation segment during 2023, where we primarily transport intermediate refined products (not crude oil) between refining complexes.

Additionally, changes in certain of our operating costs between the respective periods, such as those associated with our soda and sulfur services, 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, depletion and amortization, gain on sale of assets, interest expense and income taxes.

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)

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Year Ended December 31, 2023 Compared with Year Ended December 31, 2022

Offshore Pipeline Transportation Segment

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

Year Ended December 31,

(in thousands)

Offshore natural gas pipeline revenue, excluding non-cash revenues 59,408 46,660

Distributions from unrestricted subsidiaries(2) — 32,000

Offshore pipeline transportation Segment Margin $ 406,672 $ 363,373

Volumetric Data 100% basis:

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

Natural gas transportation volumes (MMBtus/day) 401,976 343,347

Volumetric Data net to our ownership interest(4):

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

Natural gas transportation volumes (MMBtus/day) 113,848 108,908

(1)Offshore pipeline transportation Segment Margin includes distributions received from our offshore pipeline joint ventures accounted for under the equity method of accounting in 2023 and 2022, respectively.

(2)Offshore pipeline transportation Segment Margin in 2022 includes distributions received from one of our unrestricted subsidiaries, Independence Hub LLC, of $32.0 million associated with the sale of our 80% owned platform asset.

(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.

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Offshore Pipeline Transportation Segment Margin for 2023 increased $43.3 million, or 12%, from 2022, primarily due to increased crude oil and natural gas activity, primarily from volumes associated with the King’s Quay FPS, as first oil production was achieved during 2022, and the Argos FPS, which achieved first oil production in the second quarter of 2023. The 2023 period benefited from a full year of volumes from King’s Quay, including its ramp up in production to levels reaching approximately 130,000 barrels of oil equivalent per day during 2023. The King’s Quay FPS supports volumes from the Khaleesi, Mormont, and Samurai field developments and is life of lease dedicated to our 100% owned crude oil and natural gas lateral pipelines and further downstream to our 64% owned Poseidon pipeline and 64% owned CHOPS pipeline and our 25.67% owned Nautilus natural gas system for ultimate delivery to shore. The Argos FPS, which supports BP’s operated Mad Dog 2 field development, achieved production levels of approximately 90,000 barrels of oil per day in 2023, with 100% of the volumes flowing through our 64% owned and operated CHOPS pipeline for ultimate delivery to shore. We expect to continue to benefit from King’s Quay FPS and Argos FPS volumes during 2024 and over their anticipated production profiles. In addition to these developments, activity in and around our Gulf of Mexico asset base continues to be robust, including incremental in-field drilling at existing fields that tie into our infrastructure. Lastly, 2023 had less overall downtime as compared to 2022, which was primarily a result of no weather-related events during the year. These increases were offset by distributions received from one of our unrestricted subsidiaries, Independence Hub LLC, of $32.0 million from the sale of its platform asset in 2022.

Soda and Sulfur Services Segment

Operating results for our soda and sulfur services segment were as follows:

Year Ended December 31,

Volumes sold :

NaOH (caustic soda) volumes (DST sold) 78,272 90,876

Revenues (in thousands):

NaHS revenues, excluding non-cash revenues $ 148,899 $ 183,966

Average index price for NaOH per DST(3) $ 1,057 $ 1,118

(1)Sales volumes represent soda ash volumes that are produced and supplied by our Alkali Business and excludes any alkali specialty products. See discussion above in “Results of Operations — Revenues and Costs and Expenses” regarding revenues associated with our Alkali Business.

(2)Revenues in 2023 include sales by ANSAC that were not produced and supplied by our Alkali Business that are included in our consolidated revenues. See discussion above in “Results of Operations — Revenues and Costs and Expenses” regarding revenues associated with our Alkali Business.

(3)Source: IHS Chemical.

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Soda and sulfur services Segment Margin for 2023 decreased $24.7 million, or 8%, from 2022. This decrease is primarily attributable to lower NaHS and caustic soda sales volumes and pricing in our sulfur services business which was partially offset by higher soda ash sales volumes and slightly higher domestic and export pricing in our Alkali Business during 2023. We successfully restarted our original Granger production facility on January 1, 2023 and ramped up the production to its original nameplate capacity of approximately 500,000 tons on an annual basis during 2023. We also reached substantial completion and achieved first production from the GOP in the fourth quarter of 2023 and anticipate ramping up to the expected 750,000 incremental tons of annual production in 2024. Additionally, we had higher pricing on our domestic and export sales in 2023 due to a strong supply and demand balance in the first half of the year, which weakened in the second half of the year as a result of new global supply entering the market and a slower than anticipated re-opening of China’s economy. We expect this volatility to continue into 2024.

In our sulfur services business, we experienced lower than expected production during 2023 due to multiple factors, including a slower than expected ramp up in production from the completion of a major turnaround at one of our largest host refineries in the fourth quarter of 2022, unplanned operational and weather-related outages at several of our host refineries during the second quarter of 2023 (which returned to normal operations later in 2023), and lower production from a host refinery that partially converted its facility into a renewable diesel facility in the fourth quarter of 2022. In addition, we have experienced continued pressure on demand primarily in South America, which has negatively impacted sales volumes and pricing. In comparison, during 2022, we experienced robust NaHS sales volumes and prices due to an increase in demand from our mining customers, primarily in South America, and due to our ability to leverage our multi-faceted supply and terminal sites in our sulfur services business to capitalize on incremental spot volumes as certain of our competitors experienced one-off supply challenges.

Marine Transportation Segment

Within our marine transportation segment, we own a fleet of 91 barges (82 inland and 9 offshore) with a combined transportation capacity of 3.2 million barrels, 42 push/tow boats (33 inland and 9 offshore), and a 330,000 barrel capacity ocean going tanker, the M/T American Phoenix. Operating results for our marine transportation segment were as follows:

Year Ended December 31,

Revenues (in thousands):

Fleet Utilization:(2)

Inland Barge Utilization 100.0 % 98.6 %

Offshore Barge Utilization 98.1 % 96.9 %

(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 2023 increased $44.2 million, or 67%, from 2022. This increase is primarily attributable to an increase in our overall day rates (including both spot and term) in our inland and offshore business, including the M/T American Phoenix, during 2023. The increase in our day rates is due to the continued high demand for our barge services to move intermediate and refined products as a result of strong refinery utilization rates and a lack of new supply of similar type vessels (primarily due to higher construction costs and long lead times for construction) combined with the retirement of older vessels in the market. Additionally, we entered into a new three-and-a-half-year contract on the M/T American Phoenix, which started in January 2024 with a credit-worthy counterparty at the highest day rate we have received since we first purchased the vessel in 2014.

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Onshore Facilities and Transportation Segment

Our onshore facilities and transportation segment utilizes an integrated set of pipelines and terminals, 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 and rail unloading facilities operating primarily within the U.S. Gulf Coast crude oil market. In addition, we utilize our trucking fleet that supports the purchase and sale of gathered and bulk-purchased crude oil, as well as purchased and sold refined products. Through these assets we offer our customers a full suite of services, including the following as of December 31, 2023:

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

•shipping crude oil and refined products to and from producers and refiners via trucks and pipelines;

•storing and blending of crude oil and intermediate and finished refined products;

•purchasing/selling and/or transporting 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 and selling those products (primarily fuel oil, asphalt and other heavy refined products) to wholesale markets; and

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

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.

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

Year Ended December 31,

(in thousands)

Gathering, marketing, and logistics revenue $ 699,482 $ 890,719

Crude oil pipeline tariffs and revenues 26,654 31,822

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

Onshore crude oil pipelines:

Crude oil and petroleum products sales 23,170 24,643

Rail unload volumes — 10,834

(1)Total daily volumes for the years ended December 31, 2023 and 2022 include 32,458 and 28,850 Bbls/day, respectively, of intermediate refined products and 33,019 and 53,459 Bbls/day, respectively, of crude oil associated with our Port of Baton Rouge Terminal pipelines.

Segment Margin for our onshore facilities and transportation segment decreased $5.8 million, or 17% , in 2023 as compared to 2022. The decrease is primarily due to an overall decrease in activity associated with our Baton Rouge corridor assets, specifically our rail unload and pipeline volumes, and a decrease in volumes on our Texas pipeline system during 2023.

Other Costs, Interest and Income Taxes

General and administrative expenses

Year Ended December 31,

(in thousands)

General and administrative expenses not separately identified below:

Long-term incentive based compensation plan expense 13,405 8,279

Total general and administrative expenses $ 65,779 $ 66,598

Total general and administrative expenses decreased $0.8 million between 2023 and 2022. The decrease is primarily due to lower costs associated with business development activities and growth projects as 2022 included costs associated with the issuance of our Alkali senior secured notes and related sale of the ORRI Interests, as well as costs associated with the divestiture of our previously owned Independence Hub platform. This decrease was partially offset by an increase in costs associated with our long-term incentive compensation plan as a result of the assumptions used to value our outstanding awards during 2023.

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Depreciation, depletion and amortization expense

Year Ended December 31,

(in thousands)

Total depreciation, depletion and amortization expense $ 280,189 $ 296,205

Total depreciation, depletion and amortization expense decreased $16.0 million between 2023 and 2022. This decrease is primarily attributable to 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 2022. This decrease was partially offset by an overall increase in our depreciable asset base due to our continued growth and maintenance capital expenditures and placing new assets into service subsequent to the period ended December 31, 2022.

Interest expense, net

Year Ended December 31,

(in thousands)

Interest expense, Alkali senior secured notes 24,969 15,811

Amortization of debt issuance costs, premium and discount 9,543 8,479

Net interest expense increased $18.5 million between 2023 and 2022 primarily due to an increase in interest expense associated with our senior secured credit facility, our Alkali senior secured notes (which we issued in May 2022 and incurred a full year of interest expense during 2023), and our senior unsecured notes. The increase in interest expense associated with our senior secured credit facility is primarily due to an increase in the SOFR rate, which is one of the main components of our interest rate, compared to 2022, and higher outstanding indebtedness during 2023. The increase in interest expense associated with our senior unsecured notes was primarily related to the issuance of our 2030 Notes in January 2023, which have a higher principal and interest rate than the 2024 Notes that were redeemed in January 2023.

This increase was partially offset by higher capitalized interest during 2023 as a result of our increased capital expenditures associated with the GOP and our offshore growth capital construction projects during the year.

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 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. These amounts are included within “Other expense, net” on the Consolidated Statement of Operations.

Net income for the year ended December 31, 2022 included an unrealized loss of $18.6 million from the valuation of our previously recognized embedded derivative associated with our Class A Convertible Preferred Units, and also included cancellation of debt income of $8.6 million associated with the open market repurchase and extinguishment of certain of our senior unsecured notes. Both of these amounts are included within “Other expense, net” on the Consolidated Statement of Operations. In addition, Net income for the year ended December 31, 2022 included a gain of $40.0 million recorded in “Gain on sale of asset” on the Consolidated Statement of Operations, of which $8.0 million, or 20%, is attributable to our noncontrolling interest holder, related to the sale of our Independence Hub platform to a producer group in the Gulf of Mexico for gross proceeds of $40.0 million.

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A discussion of the operating results for the year ended December 31, 2022 compared with the year ended December 31, 2021 has been omitted from this Form 10-K. This discussion can be found within our previously filed 2022 Form 10-K, which was filed with the SEC on February 24, 2023.

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 Net income (loss) attributable to Genesis Energy, L.P. 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). 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 chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Margin, segment volumes where relevant and capital investment.

A reconciliation of Net income (loss) attributable to Genesis Energy, L.P. 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

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(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, depletion 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, net interest expense, cash tax expense and cash distributions paid to our Class A convertible preferred unitholders. Although we do not necessarily consider all of our Select Items to be non-recurring, infrequent or unusual, we believe that an understanding of these Select Items is important to the evaluation of our core operating results. The most significant Select Items in the relevant reporting periods are set forth below.

Year EndedDecember 31,

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

Distributions from unrestricted subsidiaries not included in income(2) — 32,000

Certain non-cash items:

II. Applicable only to Available Cash before Reserves

(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)2022 includes $32.0 million in cash receipts associated with the sale of the Independence Hub platform by our 80% owned unrestricted subsidiary (as defined under our credit agreement), Independence Hub, LLC.

(3)2023 includes an unrealized loss of $36.7 million from the valuation of our commodity derivatives transactions (excluding fair value hedges). 2022 includes an unrealized loss of $18.6 million from the valuation of our previously recorded embedded derivative associated with our Class A Convertible Preferred Units and an unrealized gain of $24.3 million from the valuation of our commodity derivatives transactions (excluding fair value hedges).

(4)2023 includes the write-off of the unamortized issuance costs and tender premium fees associated with the repurchase and extinguishment of our 2024 Notes and 2025 Notes. 2022 includes the write-off of the unamortized issuance costs associated with the repurchase and extinguishment of certain of our senior unsecured notes during the year.

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

(6)Represents transaction costs relating to certain merger, acquisition, divestiture, transition and financing transactions incurred in advance of the associated transaction.

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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.

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.

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Available Cash before Reserves for the years ended December 31, 2023 and 2022 was as follows:

Year Ended December 31,

(in thousands)

Net income attributable to Genesis Energy, L.P. $ 117,720 $ 75,457

Income tax expense (benefit) (19) 3,169

Depreciation, depletion, amortization, and accretion 291,731 307,519

Gain on sale of assets — (32,000)

Distributions to preferred unitholders (91,837) (80,052)

Redeemable noncontrolling interest redemption value adjustments(2) — 30,443

(1)Maintenance capital expenditures in 2023 and 2022 were $125.0 million and $132.5 million, respectively. Our maintenance capital expenditures are principally associated with our alkali and marine transportation businesses.

(2)The 2022 period includes PIK distributions, accretion and valuation adjustments on the redemption feature associated with our preferred units, which were redeemed during the year ended December 31, 2022.

Liquidity and Capital Resources

General

On April 8, 2021, we entered into our Fifth Amended and Restated Credit Agreement (the “old credit agreement”), which initially provided for a $950 million senior secured credit facility, which was comprised of a revolving senior secured credit facility (the “old revolving credit facility”) with a borrowing capacity of $650 million and a term loan with a borrowing capacity of $300 million, with the ability to increase the aggregate size of the old revolving credit facility by an additional $200 million subject to lender consent and certain other customary conditions. Our term loan was paid off in full on November 17, 2021 with a portion of the gross proceeds of $418 million received from the sale of a 36% minority interest in CHOPS. On February 17, 2023, we entered into the Sixth Amended and Restated Credit Agreement (our “credit agreement”) to replace our old credit agreement. Our credit agreement provides for a $850 million senior secured revolving credit facility that matures on February 13, 2026, subject to extension at our request for one additional year on up to two occasions and subject to certain conditions.

On April 29, 2022, we received $40 million, or $32 million net to our ownership interests, for the sale of our 80% owned Independence Hub platform which allowed us to repay a portion of the borrowings outstanding under our old revolving credit facility and further increase our borrowing capacity.

On May 17, 2022, Genesis Energy, L.P., through its newly created indirect unrestricted subsidiary, GA ORRI, issued $425 million principal amount of our 5.875% Alkali senior secured notes due 2042 to certain institutional investors, secured by GA ORRI’s fifty-year 10% limited term overriding royalty interest in substantially all of the Company’s Alkali Business trona mineral leases. The issuance generated net proceeds of $408 million, net of the issuance discount of $17 million. We make quarterly interest payments on our Alkali senior secured notes until March 2024, at which time we begin making quarterly principal and interest payments through the maturity date. We used a portion of net proceeds from the issuance to fully redeem the outstanding Alkali Holdings preferred units and utilized the remainder to repay a portion of the outstanding borrowings under our old revolving credit facility. The redemption of our Alkali Holdings preferred units, which carried an implied interest rate of 12-13%, and the issuance of our Alkali senior secured notes with a coupon rate of 5.875%, has allowed us to simplify our capital structure and lower our cost of capital, provide us additional flexibility under our senior secured credit facility, and remove any risk of refinancing our Alkali Holdings preferred units that were initially due in 2026.

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On January 25, 2023, we issued $500 million in aggregate principal amount of our 8.875% senior unsecured notes due April 15, 2030 (the “2030 Notes”); interest payments are due April 15 and October 15 of each year. That issuance generated net proceeds of approximately $491 million, net of issuance costs incurred. The net proceeds were used to purchase approximately $316 million of our existing 2024 Notes, including the related accrued interest and tender premium and fees on those notes that were tendered in the tender offer that ended January 24, 2023 and the remaining proceeds at the time were used to repay a portion of the borrowings outstanding under our old revolving credit facility and for general partnership purposes. On January 26, 2023, we issued a notice of redemption for the remaining principal of approximately $25 million of our 2024 Notes, and discharged the indebtedness with respect to the 2024 Notes on February 14, 2023 by depositing the redemption amount with the trustee of the 2024 Notes for redemption of the 2024 Notes on February 25, 2023, all in accordance with the terms and conditions of the indenture governing the 2024 Notes.

On April 3, 2023, July 3, 2023 and October 2, 2023, we entered into purchase agreements with the Class A Convertible Preferred unitholders whereby we redeemed a total of 2,224,860 Class A Convertible Preferred Units at an average purchase price of $33.71 per unit. The redemption 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.

In an effort to return capital to our investors, we announced 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 will be reviewed no later than December 31, 2024 and may be suspended or discontinued at any time prior thereto. 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. During 2023, we repurchased and canceled a total of 114,900 Class A Common Units at an average price of approximately $9.09 per unit for a total purchase price of $1.0 million, including commissions, which is reflected as a reduction to the carrying value of our “Partners’ Capital - Common unitholders” on our Condensed Consolidated Balance Sheet as of December 31, 2023. We anticipate funding any future repurchase activity with a portion of our cash flows from operations and liquidity available under our senior secured credit facility.

On December 7, 2023, we issued $600.0 million in aggregate principal amount of our 8.25% senior unsecured notes due January 15, 2029 (the “2029 Notes). Interest payments are due January 15 and July 15 of each year with the initial interest payment due on July 15, 2024. The issuance of our 2029 Notes generated net proceeds of approximately $583 million, after deducting the underwriters’ discount and payment of offering expenses. The net proceeds were used to purchase approximately $514 million of our senior unsecured notes due October 1, 2025 (the “2025 Notes”) and pay the related accrued interest and tender premium and fees on those notes that were tendered in the tender offer that ended December 6, 2023. On December 8, 2023, we issued a notice of redemption for the remaining principal of approximately $21 million of our 2025 Notes, and discharged the indebtedness with respect to the 2025 Notes on December 28, 2023 by depositing the redemption amount with the trustee of the 2025 Notes for redemption of the 2025 Notes, all in accordance with the terms and conditions of the indenture governing the 2025 Notes.

The successful completion of the above events has resulted in no scheduled maturities of our senior unsecured notes until 2026 and has provided us a significant amount of available borrowing capacity under our senior secured credit facility, subject to compliance with covenants in the credit agreement, to, amongst other things, utilize for funding the remaining growth capital expenditures associated with our GOP and our offshore growth projects discussed earlier. Additionally, these events have allowed us to simplify our capital structure and eliminate our highest interest rate instrument, the Alkali Holdings preferred units.

As of December 31, 2023, we believe our balance sheet and liquidity position remained strong, including $547.2 million of borrowing capacity available under our $850.0 million senior secured credit facility, as of such date, 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 historically been cash flows from operations, borrowing availability under our senior secured credit facility, proceeds from the sale of assets, the creation of strategic arrangements to share capital costs through joint ventures or strategic alliances, and the proceeds from issuances of equity (common and preferred) and senior unsecured or secured notes.

Our primary cash requirements consist of:

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

•routine operating expenses;

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

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•interest payments related to outstanding debt;

•asset retirement obligations;

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

•acquisitions of assets or businesses.

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, 2023, we had $298.3 million borrowed under our senior secured credit facility, with $19.3 million of the borrowed amount 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, 2023 was $547.2 million, subject to compliance with covenants in the credit agreement.

At December 31, 2023, our long-term debt totaled approximately $3.8 billion, consisting of $298.3 million outstanding under our senior secured credit facility (including $19.3 million borrowed under the inventory sublimit tranche), $3.1 billion of senior unsecured notes, and $425.0 million of Alkali senior secured notes (of which $11.6 million is current), which are secured by the ORRI Interests. Our senior unsecured notes balance is comprised of $339.3 million of our 2026 Notes, $981.2 million of our 2027 Notes, $679.4 million of our 2028 Notes, $600.0 million of our 2029 Notes, and $500.0 million of our 2030 Notes.

Future payment obligations related to our senior secured credit facility and senior unsecured notes as of December 31, 2023, including both principal and estimated interest payments, are summarized in the table below:

Interest Rate Maturity Date Principal Estimated Annual Interest Payable

(in thousands)

(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, 2023 remained outstanding for the year ended December 31, 2024, and interest rates remained constant.

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

Future payment obligations associated with our Alkali senior secured notes, as of December 31, 2023, including both estimated principal and interest payments, are summarized in the table below:

Payment Obligations Estimated Interest Payments Estimated Principal Payments

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

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

Class A Convertible Preferred Units

On September 1, 2017, we sold $750 million of Class A Convertible Preferred Units in a private placement, comprised of 22,249,494 units for a cash purchase price per unit of $33.71 (subject to certain adjustments, the “Issue Price”) to two initial purchasers. Our general partner executed an amendment to our partnership agreement in connection therewith, which, among other things, authorized and established the rights and preferences of our Class A Convertible Preferred Units. Our Class A Convertible Preferred Units are a new class of security that ranks 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.

Our Class A Convertible Preferred Units contained a distribution Rate Reset Election (as defined in Note 11), which was elected by the holders of the Class A Convertible Preferred Units on September 29, 2022 (the “election date”). From the date of issuance through the election date, each of our Class A Convertible Preferred Units accumulated quarterly distribution amounts in arrears at an annual rate of 8.75% (or $2.9496), yielding a quarterly rate of 2.1875% (or $0.7374). On the election date, the holders of the Class A Convertible Preferred Units elected to reset the rate to 11.24%, yielding a quarterly distribution of $0.9473 per preferred unit beginning with the fourth quarter of 2022.

With respect to any quarter ending on or prior to March 1, 2019, we exercised our option to pay the holders of our Class A Convertible Preferred Units the applicable distribution in additional Class A Convertible Preferred Units equal the product of (i) the number of then outstanding Class A Convertible Preferred Units and (ii) the quarterly rate. For all subsequent periods ending after March 1, 2019, we have paid and will pay all distribution amounts in respect of our Class A Convertible Preferred Units in cash. As noted above, we redeemed a total of 2,224,860 Class A Convertible Preferred Units during 2023 and, as of December 31, 2023, there were 23,111,918 Class A Convertible Preferred Units outstanding.

Redeemable Noncontrolling interests

On September 23, 2019, we, through a subsidiary, Alkali Holdings, entered into an amended and restated Limited Liability Company Agreement of Alkali Holdings (the “LLC Agreement”) and a Securities Purchase Agreement (the “Securities Purchase Agreement”) whereby BXC purchased $55.0 million of preferred units (or 55,000 preferred units) and committed to purchase, during a three-year commitment period, up to a total of $350.0 million of preferred units (or 350,000 preferred units) in Alkali Holdings. Alkali Holdings utilized the net proceeds from the preferred units to fund a portion of the anticipated cost of the GOP. On April 14, 2020, we entered into an amendment to our agreements with BXC to, among other things, extend the construction timeline of the GOP by one year, which we substantially completed in the fourth quarter of 2023. In consideration for the amendment, we issued 1,750 Alkali Holdings preferred units to BXC, which was accounted for as issuance costs. As part of the amendment, the commitment period was increased to four years, and the total commitment of BXC was increased to, subject to compliance with the covenants contained in our agreements with BXC, up to $351.8 million of preferred units (or 351,750 preferred units) in Alkali Holdings.

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From time to time after we had drawn at least $251.8 million, we had the option to redeem the outstanding preferred units in whole for cash at a price equal to the initial $1,000 per preferred unit purchase price, plus no less than the greater of a predetermined fixed internal rate of return amount or a multiple of invested capital metric, net of cash distributions paid to date (“Base Preferred Return”). Additionally, if all outstanding preferred units were redeemed, we had not drawn at least $251.8 million, and BXC was not a “defaulting member” under the LLC Agreement, BXC had the right to a make-whole amount on the number of undrawn preferred units.

On May 17, 2022 (the “Redemption Date”), we fully redeemed the 251,750 outstanding Alkali Holdings preferred units a Base Preferred Return Amount of $288.6 million utilizing a portion of the proceeds we received from the issuance of our Alkali senior secured notes. As of December 31, 2022 and 2023, there were no Alkali Holdings preferred units outstanding.

See Note 12 to our Consolidated Financial Statements in Item 8 for additional information regarding our mezzanine capital.

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 “2021 Shelf”) on file with the SEC which we filed on April 19, 2021 to replace our previous universal shelf registration statement that expired on April 20, 2021. Our 2021 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 2021 Shelf is set to expire in April 2024. We expect to file a replacement universal shelf registration statement before our 2021 Shelf expires.

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.

In our petroleum products activities, we buy products and typically either move those products to one of our storage facilities for further blending or sell those products within days of our purchase. The cash requirements for these activities can result in short term increases and decreases in the borrowings under our senior secured credit facility.

In our Alkali Business, we typically extract trona from our mining facilities, process into soda ash and other alkali products, and deliver and sell to our customers domestically and internationally. When we experience any differences in timing between the extraction, processing and sales of this trona or Alkali products, including the logistics and transportation to our customers, the cash requirements for these activities in the short term can be affected.

The storage of our inventory of crude oil, petroleum products and alkali 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 (or pay for extraction and processing activities in the case of alkali products), we borrow under our senior secured credit facility (or use cash on hand) to pay for the crude oil or petroleum products (or extraction/processing of alkali 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, petroleum products or alkali 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.

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Net cash flows provided by our operating activities were $521.1 million and $334.4 million for 2023 and 2022, respectively. The increase in operating cash flow for 2023 compared to 2022 was primarily attributable to higher Segment Margin reported during 2023, a gain on sale of assets of $40.0 million in 2022 associated with the sale of our 80% owned Independence Hub platform, of which $8.0 million was attributable to our noncontrolling interests and $32.0 million that is included in Segment Margin but is considered a cash inflow from investing activities, and changes in our working capital requirements.

See Note 16in our Consolidated Financial Statements in Item 8 for information regarding changes in components of operating assets and liabilities during the years ended December 31, 2023 and 2022.

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:

Years Ended December 31,

(in thousands)

Capital expenditures for fixed and intangible assets:

Maintenance capital expenditures:

Offshore pipeline transportation assets $ 5,748 $ 6,292 $ 8,749

Onshore facilities and transportation assets 5,927 2,928 4,476

Growth capital expenditures:

Marine transportation assets 9,038 — —

Onshore facilities and transportation assets 12,765 — 133

Capital expenditures related to equity investees 4,489 10,301 352

(1)Growth capital expenditures in our offshore pipeline transportation segment for 2023 and 2022 represent 100% of the costs incurred, including those funded by our noncontrolling interest holder (see further discussion below in “Growth Capital Expenditures”).

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.

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Growth Capital Expenditures

On September 23, 2019, we announced the GOP along with the issuance of the Alkali Holdings preferred units, which were anticipated to fund up to the total estimated cost of the GOP. During the fourth quarter of 2021, we made the decision to fund the remaining capital expenditures associated with the GOP internally in lieu of issuing additional Alkali Holdings preferred units. We reached substantial completion and achieved first production from the GOP during the fourth quarter of 2023 and expect production to ramp up to its incremental design capacity of 750,000 on an annual basis in 2024.

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 that have a combined production capacity of approximately 160,000 barrels per day. In conjunction with these agreements, we are expanding the current capacity of our 64% owned CHOPS pipeline and constructing a new 100% owned, approximately 105 mile, 20” diameter crude oil pipeline, the SYNC pipeline, to connect one of the developments to our existing asset footprint in the Gulf of Mexico. We plan to complete the construction in line with the producers’ plan for first oil achievement, which is currently expected in late 2024 or 2025. Additionally, in 2023, we entered into several additional definitive agreements with existing producers to further commit additional volumes transported on our 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 throughout the construction period.

We plan to fund our estimated growth capital expenditures utilizing the available borrowing capacity under our senior secured credit facility and our recurring cash flows generated from operations.

Maintenance Capital Expenditures

Maintenance capital expenditures incurred primarily relate to our marine transportation segment to replace and upgrade certain equipment associated with our vessels and in our Alkali Business, which is included in our soda and sulfur services segment, due to the costs to maintain our related equipment and facilities. Additionally, our offshore transportation 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 2023’s expenditures dependent upon the timing of when we incur certain costs. See previous 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

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 14, 2024, we paid a distribution of $0.15 per common unit related to the fourth quarter of 2023. 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 14, 2024 to unitholders holders of record at the close of business January 31, 2024.

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

(1)This distribution was paid on February 14, 2024 to unitholders of record as of January 31, 2024.

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, 2023, which are summarized below.

•We have estimated operating lease payment obligations totaling $425.1 million, of which $47.7 million is expected to be paid in 2024 (see Note 5 to our Consolidated Financial Statements in Item 8 for details on our lease obligations).

•We have unconditional purchase obligations from agreements to purchase goods and services that are enforceable and legally binding and specify all significant terms. The estimated total for our unconditional purchase obligations is $25.3 million, of which $13.1 million is estimated to be paid in 2024. Contracts to purchase natural gas and utilities are generally at market-based prices. The estimated volumes and market prices at December 31, 2023 were used to value those obligations. The actual physical volumes and settlement prices may vary due to uncertainties involved in these estimates which include levels of production at the wellhead, changes in market prices and other conditions beyond our control.

•We have estimated cash requirements associated with our growth capital spending program, which we anticipate to be approximately $275.0 million to $300.0 million to complete our ongoing projects over the next 18 months. We also have current asset retirement obligations of approximately $27 million that we expect to pay in 2024. These requirements are expected to be funded primarily with free cash flow generated from our operations and availability under our senior secured credit facility.

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 all of Genesis Energy, L.P.’s current and future 100% owned domestic subsidiaries (the “Guarantor Subsidiaries”), except GA ORRI and GA ORRI Holdings and certain other subsidiaries. The remaining 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. As a general rule, the assets and credit of our unrestricted subsidiaries are not available to satisfy the debts of Genesis Energy, L.P., Genesis Energy Finance Corporation or the Guarantor Subsidiaries, and the liabilities of our unrestricted subsidiaries do not constitute obligations of Genesis Energy, L.P., Genesis Energy Finance Corporation or the Guarantor Subsidiaries. See Note 11 to our Consolidated Financial Statements in Item 8 for additional information regarding our consolidated debt obligations.

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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.

On May 17, 2022, we entered into an amendment to our old credit agreement, which designated GA ORRI and GA ORRI Holdings as unrestricted subsidiaries under our credit agreement. In addition, the amendment re-designatedGenesis Alkali Holdings Company LLC, Genesis Alkali Holdings, LLC, Genesis Alkali, LLC and Genesis Alkali Wyoming, LP (the subsidiary entities that own our Alkali Business, other than the ORRI Interests) as restricted entities and guarantors of our old credit agreement. On May 17, 2022, we designated GA ORRI and GA ORRI Holdings as unrestricted subsidiaries and reclassified the entities that originally held our Alkali Business as restricted subsidiaries under the indentures governing our senior unsecured notes. The Alkali Business was historically presented as non-guarantor subsidiaries and because of such designation are now presented as guarantor subsidiaries. The changes made did not impact the Company’s previously reported consolidated net operating results, financial position, or cash flows.

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

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

(in thousands)

ASSETS:

LIABILITIES AND CAPITAL:(2)

Class A Convertible Preferred Units 813,589

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

(in thousands)

Net income before income taxes 92,879

Net income available to common unitholders $ 2,172

(1)Excluded from non-current assets in the table above are net intercompany receivables of $48.9 million that are owed to Genesis Energy, L.P. and the Guarantor Subsidiaries from the non-Guarantor Subsidiaries as of December 31, 2023.

(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 $2.8 million of sales from Guarantor Subsidiaries to non-Guarantor Subsidiaries for the year ended December 31, 2023.

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.

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.

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On January 1, 2023, we became the sole member of ANSAC and assumed 100% of the voting rights of the entity, and it became a wholly owned subsidiary of Genesis. We determined that ANSAC met the definition of a business and we accounted for our acquisition of ANSAC as a business combination. We have reflected the financial results of ANSAC within our soda and sulfur services segment from the date of acquisition, January 1, 2023. The purchase price has been allocated to the assets acquired and the liabilities assumed based on their respective fair values. There was no consideration transferred as a result of becoming the sole member of ANSAC. The assets acquired include inventories principally related to finished goods (soda ash), fixed assets primarily related to leasehold improvements at the leased facility that supports our logistics operations, an intangible asset related to our assets supporting our logistical and marketing footprint, right of use assets and our corresponding lease liabilities, primarily associated with our right to use certain assets to store and load finished goods, the vessels we utilize to ship finished goods to distributors and end users, as well as office space. Our leasehold improvements and intangible asset both have an estimated useful life of ten years, which is consistent with the term of our primary lease facilitating our logistics operations.

Depreciation, Amortization and Depletion of Long-Lived Assets and Intangibles

In order to calculate depreciation, depletion and amortization we must estimate the useful lives of our fixed and intangible assets (including the reserve life of our mineral leaseholds) 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.

We compute depletion using the units of production method using actual production and our estimated reserve life. The actual reserve life may differ from the assumptions we have made about the estimated reserve life.

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 Note9 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. For the years ended December 31, 2023, 2022 and 2021, we did not recognize an impairment expense associated with our long-lived assets.

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.

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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.

The determination of a reporting unit’s fair value is 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) long-term growth rates for cash flows beyond the discrete forecast period, (iii) appropriate discount rates and (iv) estimates of the cash flow multiples to apply in estimating the market value of our reporting units. Changes in these estimates could have a significant impact on fair value. If the fair value of the reporting unit (including its inherent goodwill) is less than its carrying value, a charge to earnings may be required to reduce the carrying value of goodwill to its implied 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. We 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 is the comparison of our market capitalization to our book equity to determine if there is an indicator of impairment.

We performed a qualitative assessment as of October 1, 2023 and 2022 for our refinery services reporting unit, which is the only reporting unit as of our assessment date that has goodwill. 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 and 2022.

We performed a quantitative assessment as of October 1, 2021 for our refinery services reporting unit, which is the only reporting unit as of our assessment date that has goodwill. No impairment was recorded in our refinery services reporting unit during 2021 as the fair value far exceeded the carrying value. Additionally, when performing sensitivity analyses to the significant inputs in the fair value, including the discount rate and assumptions related to the future cash flows, a 10% change in these assumptions did not impact of our overall conclusion surrounding the valuation of our goodwill.

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.

Fair Value of Derivatives

We reflect estimates for the fair value of our derivatives based on our internal records and information from third parties. We have commodity and other derivatives that are accounted for as assets and liabilities at fair value in our Consolidated Balance Sheets. The valuations of our derivatives that are exchange traded are based on market prices on the applicable exchange on the last day of the period. For our derivatives that are not exchange-traded, the estimates we use are based on indicative broker quotations. Changes in these estimates could cause a material change to our financial results.

We identified a feature within our Class A Convertible Preferred Units that was required to be bifurcated and recorded as an embedded derivative measured at fair value. Our final valuation of the embedded derivative occurred on September 29, 2022, which is when the feature within the Class A Convertible Preferred Units that required bifurcation and fair value measurement no longer existed. On September 29, 2022, the fair value of the liability associated with the embedded derivative was reclassified to mezzanine equity.

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The fair value of the embedded derivative associated with our Class A Convertible Preferred Units was estimated using a Monte Carlo simulation approach that contained inputs, including our common unit price relative to the issuance price, dividend yield, discount yield, equity volatility, 30-year U.S. Treasury rates, and default and redemption probabilities and timing estimates, which involved management judgment.

During the years ended December 31, 2022 and 2021, we recorded unrealized losses of $18.6 million and $30.8 million, respectively, associated with fair value changes of the embedded derivative. Changes in the fair value estimate during 2022 were primarily driven by the election of the rate reset, which increased the distribution rate from 8.75% to 11.24%, and changes in the fair value estimate during 2021 were primarily driven by fluctuations in the discount yield from period to period. A significant increase or decrease in these inputs could have materially affected our fair value estimate, resulting in impacts to our Consolidated Financial Statements. For example, a 10% increase or decrease in the volatility used in the calculation could have caused a decrease or an increase to the fair value of our embedded derivative of approximately $8 million or $11 million, respectively as of September 29, 2022.

For additional information regarding the Class A Convertible Preferred Units and the associated embedded derivative, see Note 12 and Note 19 to our Consolidated Financial Statements in Item 8.

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.

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, 2023, 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 2022, 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 $11 million. We could have impacts to our future earnings based on the actual costs we incur relative to our estimated costs.

Employee Benefits

We sponsor a defined benefit pension plan for union-only employees of our Alkali Business. We recognize the net funded status of the pension plan under GAAP as a net liability, included within “Other long-term liabilities” as of December 31, 2023 and 2022 on our Consolidated Balance Sheets. The funded status represents the difference between the fair value of the pension plan’s assets and the estimated benefit obligation of the plan. The benefit obligation represents the present value of the estimated future benefits we expect to pay to plan participants based on serviceat the end of each period. The benefit obligation and plan assets are measured at the end of each year, or more frequently, upon the occurrence of a significant event, such as a settlement or curtailment. We utilize actuarial valuations to measure our funded status in the plan, which include assumptions such as discount rates, expected long-term rate of return on our plan assets, the timing of our contributions and payments, employee headcount and compensation changes, amongst others. Significant changes to certain of these assumptions can have a material impact to our financial statements. We recognized an actuarial gain of $1.8 million during 2023 primarily due to the difference between the actual and expected return on our plan assets during the year partially offset by a decrease in the discount rate utilized to calculate our benefit obligation from 5.33% at December 31, 2022 to 5.16% at December 31, 2023. We recognized an actuarial gain of $11.2 million during 2022 in accumulated other comprehensive income primarily as a result of an increase to the discount rate utilized to calculate our benefit obligation from 3.27% at December 31, 2021 to 5.33% at December 31, 2022. The impact of the increase in our discount rate was partially offset as a result of an actuarial loss recognized due to the difference between the actual and expected return on our plan assets during 2022.

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Item 7a. Quantitative and Qualitative Disclosures About Market Risk

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

Commodity Price Risk

We use derivative instruments to hedge price risk associated with the following commodities:

•Crude Oil and Petroleum Products — We utilize crude oil and petroleum product derivatives to hedge commodity price risk, including crude oil, fuel oil and other petroleum products, inherent in our onshore facilities and transportation segment. Our objectives for these derivatives include hedging fixed price purchase and sales, crude inventories, and basis differentials. We manage these exposures with various instruments including exchange-traded futures, options and swap contracts. Our risk management policies are designed to monitor our physical volumes, grades and delivery schedules to ensure our hedging activities address the market risks inherent in our gathering and marketing activities. As of December 31, 2023 we had entered into derivative instruments that will settle between January 2024 and April 2024.

•Natural Gas — We utilize natural gas derivatives to hedge commodity price risk inherent in our Alkali Business. Our objectives for these derivatives include hedging anticipated purchases of natural gas used by our Alkali Business to generate heat and power for operations. We manage these exposures with a combination of commodity price swap contracts, futures and option contracts. As of December 31, 2023 we had entered into derivative instruments that will settle between January 2024 and December 2025.

Fuel and Freight Price Risk

•Forward Freight Hedges — ANSAC is exposed to fluctuations in freight rates for vessels used to transport soda ash to our international customers. We use exchange-traded or over-the-counter futures, swaps and options to hedge future freight rates for forecasted shipments. As of December 31, 2023 we did not have any open derivative positions related to vessel freight.

•Bunker Fuel Hedges — ANSAC is exposed to fluctuations in the price of bunker fuel consumed by vessels used to transport soda ash to our international customers. We use exchange-traded or over-the-counter futures, swaps and options to hedge bunker fuel prices for forecasted shipments. As of December 31, 2023 we had entered into derivative instruments that will settle between January 2024 and December 2024.

•Rail Fuel Surcharge Hedges — ANSAC enters into rail transport agreements that require us to pay rail fuel surcharges based on changes in the U.S. On-Highway Diesel Fuel Price published by the U.S. Department of Energy (“DOE”). We use exchange-traded or over-the-counter futures, swaps and options to hedge fluctuations in the fuel price. As of December 31, 2023 we had entered into derivative instruments that will settle between January 2024 and August 2024.

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

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The table below presents information about our open derivative contracts at December 31, 2023. Notional amounts in barrels, MMBtu, gallons (“Gal”), or metric tons (“MT”), the weighted average contract price, total contract amount and total fair value amount in U.S. dollars of our open positions are presented below. Fair values were determined by using the notional amount in barrels, MMBtu, gallons, or metric tons multiplied by the December 31, 2023 quoted market prices. The table does not include offsetting physical exposures hedged by our derivative contracts.

Futures and Swap Contracts

Sell (Short) Contracts:

Buy (Long) Contracts:

Option Contracts

Written Contracts:

Purchased Contracts:

Natural Gas MMBtu 30 MMBtu $ 0.02 $ 1 $ (1) $ —

We manage our risks of volatility in NaOH prices by indexing prices for the sale of NaHS to the market price for NaOH in most of our contracts. Given the competitive advantages associated with our naturally produced soda ash as previously discussed (relative to that which is synthetically produced), we believe this somewhat mitigates market risk within our Alkali Business.

Interest Rate Risk

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

Obligations under our senior secured credit facility bear interest at the Term SOFR rate or alternate base rate (which approximates the prime rate), at our option, plus the applicable margin. We have not historically hedged our interest rates. On December 31, 2023, we had $298.3 million of debt outstanding under our senior secured credit facility. A 10% change in the Term SOFR rate would have resulted in an immaterial impact to Net income for the year ended December 31, 2023.

The Preferred Distribution Rate Reset Election associated with our Class A Convertible Preferred Units represented a feature that was required to be bifurcated from the related host contract, the preferred unit purchase agreement, and accounted for as an embedded derivative recorded at fair value in our Consolidated Balance Sheets. Our final valuation of the embedded derivative occurred on September 29, 2022, which is the date at which the feature within the Class A Convertible Preferred Units that required bifurcation and fair value measurement no longer existed. On September 29, 2022, the fair value of the liability associated with the embedded derivative was reclassified to mezzanine equity. The valuation model utilized for this embedded derivative contained inputs including our common unit price relative to the issuance price, the current dividend yield, the discount yield (which was adjusted periodically for changed associated with the industry’s credit markets), equity volatility, default probabilities, U.S. treasury rates, and timing estimates to ultimately calculate the fair value of our Class A Convertible Preferred Units with and without the Preferred Distribution Rate Reset Option. See Note 12 and Note 19 to our Consolidated Financial Statements in Item 8 for further discussion of our Class A Convertible Preferred Units and embedded derivatives.

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Item 8. Financial Statements and Supplementary Data

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

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

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in the reports that we file or submit under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and communicated to our management, including our chief executive officer and chief financial officer to allow timely decisions regarding required disclosures. Our chief executive officer and chief financial officer, with the participation of our management, have evaluated our disclosure controls and procedures as of December 31, 2023 and have concluded that such disclosure controls and procedures are effective to provide reasonable assurance that information is recorded, processed, summarized, and reported within the time periods specified in the Commission’s rules and forms and that such information is accumulated and communicated to management, including our chief executive officer and chief financial officer to allow for timely decisions regarding required disclosures in this Annual Report on Form 10-K.

Changes in Internal Controls over Financial Reporting

There were no changes during the fiscal quarter ended December 31, 2023 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control over Financial Reporting

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

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

Management assessed the effectiveness of the partnership’s internal control over financial reporting as of December 31, 2023. In making this assessment, management used the criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment as of December 31, 2023, management has concluded the partnership’s internal control over financial reporting is effective based on those criteria.

In January 2023, we became the sole member of ANSAC and accounted for it as a business combination. We excluded ANSAC from the scope of our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2023. ANSAC accounted for approximately 27% of our consolidated revenues for the year ended December 31, 2023 and approximately 5% of our total consolidated assets at December 31, 2023.

PricewaterhouseCoopers LLP, the partnership’s independent registered public accounting firm, has issued an attestation report on the effectiveness of the partnership’s internal control over financial reporting as of December 31, 2023, as stated in their report which appears in Item 8. “Financial Statements and Supplementary Data.”

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Item 9B. Other Information

None.

Part III

Item 10. Directors, Executive Officers and Corporate Governance

Management of Genesis Energy, L.P.

We are a Delaware limited partnership. We conduct our operations and own our operating assets through our subsidiaries and joint ventures. Our general partner, Genesis Energy, LLC, a wholly-owned subsidiary that owns a non-economic general partner interest in us, has sole responsibility for conducting our business and managing our operations. It also employs most of our personnel, including executive officers. Employees of our Alkali operations are employed by our subsidiary, Genesis Alkali, LLC.

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

Collectively, members of the Davison family own 11.0% of our Class A Common Units and 77.0% of our Class B Common Units, for a combined ownership percentage of 11.0% of total Common Units. Pursuant to its unitholder rights agreement, the Davison family is entitled to elect up to three of our directors based on its members’ collective ownership percentage of our outstanding common units: (i) with 15% or more ownership, they have the right to appoint three directors, (ii) with less than 15% ownership but more than 10%, they have the right to appoint two directors, and (iii) with less than 10% ownership, they have the right to appoint one director. That unitholder rights agreement also provides that, so long as the Davison family has the right to elect three directors thereunder, our board of directors cannot have more than 11 directors without the Davison family’s consent. In addition to their rights under that unitholder rights agreement, if the members of the Davison family act as a group, they have the ability to elect at least a majority of our directors because they own a majority of our Class B units.

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

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

Board Leadership Structure and Risk Oversight

Board Leadership Structure

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

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

On September 1, 2017, we sold $750 million of Class A Convertible Preferred Units in a private placement, comprised of 22,249,494 units for a cash purchase price per unit of $33.71 (subject to certain adjustments, the “Issue Price”) to two initial purchasers. In connection with the private placement, we have granted each initial purchaser (including its applicable affiliate transferees) certain rights, including (i) the right to appoint an observer, who shall have the right to attend our board meetings for so long as an initial purchaser (including its affiliates) owns at least $200 million of our Class A Convertible Preferred Units and (ii) the right to appoint two directors to our general partner’s board of directors if (and so long as) we fail to pay in full any three quarterly distribution amounts, whether or not consecutive. As of December 31, 2023, we had 23,111,918 Class A Convertible Units outstanding.

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

Risk Oversight

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

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

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

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Audit Committee

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

Governance, Compensation and Business Development Committee

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

Conflicts Committee

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

Executive Sessions of Non-Management Directors

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

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Directors and Executive Officers

Set forth below is certain information concerning our directors and executive officers, effective as of February 23, 2024.

Name Age Position

Grant E. Sims 68 Director, Chairman of the Board, and Chief Executive Officer

Conrad P. Albert 77 Director

James E. Davison 86 Director

James E. Davison, Jr. 57 Director

Sharilyn S. Gasaway 55 Director

Kenneth M. Jastrow II 76 Director

Jack T. Taylor 72 Director

Kristen O. Jesulaitis 54 Chief Financial Officer and Chief Legal Officer

Ryan S. Sims 40 President and Chief Commercial Officer

Robert V. Deere 69 Chief Administrative Officer

Edward T. Flynn 65 Executive Vice President

Garland G. Gaspard 69 Senior Vice President

Louis V. Nicol 39 Senior Vice President and Chief Accounting Officer

Richard R. Alexander 48 Vice President

William W. Rainsberger 39 Senior Vice President

Jeffrey J. Rasmussen 57 Vice President

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

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

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

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

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

Kenneth M. Jastrow II has served as a director of our general partner since March 2010 and serves as our lead independent director and the chairperson of the G&C Committee. Mr. Jastrow served as Chairman and Chief Executive Officer of Temple-Inland, Inc., a manufacturing company and the former parent of Forestar Group, from 2000 to 2007. Prior to that, Mr. Jastrow served in various roles at Temple-Inland, including President and Chief Operating Officer, Group Vice President and Chief Financial Officer. Mr. Jastrow served as a director of MGIC Investment Corporation and a director and Director Emeritus of KB Home. Mr. Jastrow formerly served as Non-Executive Chairman of Forestar Group, Inc. Mr. Jastrow’s executive experience and service as director of other companies enable him to make valuable contributions to our board of directors and particularly well suited to be the lead independent director.

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

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

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

Robert V. Deere has served as Chief Administrative Officer of our general partner since April 2023 and served as Chief Financial Officer of our general partner from October 2008 to March 2023. Mr. Deere served as Vice President, Accounting and Reporting at Royal Dutch Shell (Shell) from 2003 through 2008.

Edward T. Flynn has served as Executive Vice President of our general partner and President of Genesis Alkali since we acquired that business from Tronox Ltd. in September 2017. Prior to joining Genesis, Mr. Flynn worked for Tronox Corporation as Executive Vice President and President of Tronox Alkali since April 2015 and was with FMC Corporation for 33 years, serving most recently as President FMC Minerals. Mr. Flynn is currently Chairman of the Board of Directors of ANSAC.

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

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

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

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

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

Common Unit Ownership by Directors and Executive Officers

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

Code of Ethics

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

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Item 11. Executive Compensation

The Compensation Discussion and Analysis below discusses our compensation process and our objectives and philosophy with respect to our Named Executive Officers (“NEOs”) for the fiscal year ended December 31, 2023.

Compensation Discussion and Analysis

Named Executive Officers

Our NEOs for 2023 were:

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

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

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

•Robert V. Deere, Chief Administrative Officer; and

•Edward T. Flynn, Executive Vice President.

Board and Governance, Compensation and Business Development Committee

Our board of directors is responsible for, and effectively determines, compensation programs applicable to our NEOs and to the board itself. Our board of directors has delegated to the G&C Committee, of which a majority of the members are “independent,” according to NYSE listing standards, the authority and responsibility to regularly analyze and evaluate our compensation policies, to determine the annual compensation of our NEOs, and to make recommendations to our board of directors with respect to such matters. As described in more detail below, the G&C Committee engaged Meridian Compensation Partners, LLC (“Meridian”), as its independent compensation consultant for 2023. As the need arises, we also utilize committees comprised solely of certain of our independent directors (i.e., the audit committee or special committees) to review and make recommendations with respect to certain matters. Because the G&C Committee is comprised of all the members of our board of directors, excluding our CEO, determinations and recommendations by the G&C Committee are effectively determinations and recommendations by our board of directors, which has approval authority for all such compensation matters. For a more detailed discussion regarding the purposes and composition of board committees, please see Item 10. “Directors, Executive Officers and Corporate Governance.”

Committee/Board Process

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

Committee/Board Approval

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

Role of Compensation Consultant and Peer Group Analysis

The G&C Committee’s charter authorizes it to retain independent compensation consultants from time to time to serve as a resource in support of its efforts to carry out certain duties. In 2023, the G&C Committee engaged Meridian, an independent compensation consultant, to assist the G&C Committee in assessing and structuring competitive compensation packages for the executive officers that are consistent with our compensation philosophy. The G&C Committee assessed the independence of Meridian pursuant to current exchange listing requirements and SEC guidance and concluded that no conflict of interest exists that would prevent Meridian from serving as an independent consultant to the G&C Committee.

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

For purposes of reviewing the compensation amounts related to 2023, Meridian performed a market analysis using a peer group that consisted of the following 14 companies in the energy industry: Plains All American Pipeline, L.P., Targa Resources Corp., HF Sinclair Corporation, Equitrans Midstream Corporation, EnLink Midstream, LLC, Magellan Midstream Partners, L.P. (subsequently acquired during 2023 by ONEOK), Delek US Holdings, Inc., NGL Energy Partners LP, NuStar Energy L.P., Sunoco LP, Crestwood Equity Partners LP, USA Compression Partners, LP, U.S. Silica Holdings, Inc. and Calumet Specialty Products Partners, L.P. These companies were selected as the compensation peer group for any or all of the following reasons:

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

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

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

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

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

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

Compensation Objectives and Philosophy

The primary objectives of our compensation program are to: