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 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 and a variety of chemicals and other industrial products, and has been operating for over 70 years.

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

•Overview of 2022 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 2022 Results

We reported Net Income Attributable to Genesis Energy, L.P. of $75.5 million in 2022 compared to Net Loss Attributable to Genesis Energy, L.P. of $165.1 million in 2021.

Net Income Attributable to Genesis Energy, L.P. in 2022 was impacted by: (i) an increase in segment margin of $152.3 million compared to 2021 (which was inclusive of $70.0 million in cash receipts associated with our previously owned NEJD pipeline not included in operating income, see “Results of Operations” below for additional details on the results of our operating segments); (ii) a decrease in depreciation, depletion and amortization expense of $13.5 million and a decrease in interest expense of $7.6 million (see “Results of Operations” below for additional details); and (iii) cancellation of debt income of $8.6 million from the repurchase of certain of our senior unsecured notes on the open market throughout 2022, which is recorded in “Other expense, net.” Additionally, we incurred an unrealized (non-cash) loss from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units of $18.6 million in 2022 compared to an unrealized (non-cash) loss of $30.9 million in 2021 recorded within “Other expense, net.” These increases were partially offset by higher net income that we attributed to our noncontrolling interests during 2022 as a result of the sale of our 36% interest in our CHOPS pipeline in the fourth quarter of 2021.

Cash flows from operating activities were $334.4 million for the 2022 period compared to $338.0 million for 2021. This decrease was primarily attributable to the 2021 period including $70.0 million in cash receipts associated with our previously owned NEJD pipeline and is included in cash flows from operating activities and changes in our working capital requirements. These were offset by higher segment margin reported during 2022.

Available Cash before Reserves (as defined below in “Financial Measures”) increased $148.7 million in 2022 to $352.6 million as compared to 2021 Available Cash before Reserves of $203.9 million, primarily due to an 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 $770.1 million in 2022, an increase of $152.3 million as compared to 2021. We currently manage our businesses through four divisions that constitute our reportable segments - offshore pipeline transportation, sodium

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minerals and sulfur services, onshore facilities and transportation and marine 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, 2023, we paid a distribution of $0.15 per common unit related to the fourth quarter of 2022.

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, 2023 to unitholders holders of record at the close of business January 31, 2023.

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 Environmental, Social and Governance (“ESG”) 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, including volumes from the Argos (scheduled for first production in 2023) and King’s Quay (which achieved first oil in the second quarter of 2022 and has ramped to in excess of 100,000 barrels of oil equivalent per day) floating production systems.

•New volumes from long-term contracted offshore commercial opportunities in the Gulf of Mexico, including the Shenandoah development, which will tie into our SYNC pipeline (which is currently under construction) and further downstream to our CHOPS pipeline (which we are currently in the process of expanding the capacity of), and the Salamanca floating production system, which will tie into our existing SEKCO pipeline for further transportation downstream to our existing pipeline network. These developments and their associated volumes are expected to come online in late 2024 and 2025.

•Increased capacity for soda ash production by bringing the original Granger facility and its approximately 500,000 tons of annual production back online on January 1, 2023 and investing into our Granger Optimization Project, which is scheduled to begin first production in the second half of 2023 and ramp up to its design capacity of 750,000 tons per year over the subsequent nine to twelve months.

•The continued increase in demand for soda ash (including its anticipated participation in the energy transition).

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 free cash flow from operations as discussed above, to fund our high return capital projects, including our Granger Optimization Project, our SYNC pipeline and the expansion of our existing CHOPS pipeline (all of which are further discussed below), 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 expect to spend total gross capital expenditures of approximately $650 million (or approximately $550 million net to our ownership interests) to: (i) expand the current capacity of the CHOPS pipeline; and (ii) construct 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 the achievement of first oil production, which is currently expected in late 2024 or 2025. 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 facility throughout the construction period.

Granger Production Facility Expansion

On September 23, 2019, we announced the Granger Optimization Project along with the issuance of the Alkali Holdings preferred units. The anticipated completion date of the GOP is the second half of 2023 and the expansion is expected to increase our production at the Granger facilities by approximately 750,000 tons per year while also reducing our fixed cost per ton of production.

The proceeds received from the issuance of our Alkali Holdings preferred units assisted in the funding of the anticipated cost of the GOP. During the fourth quarter of 2021, we made the decision to fund the remaining construction costs

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required to complete the GOP through a combination of our internally generated free cash flows and availability under our senior secured credit facility, and subsequently, as noted above, redeemed the outstanding Alkali Holdings preferred units.

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, 2022 increased $663.5 million, or 31%, from the year ended December 31, 2021, and our costs and expenses (excluding the gain on sale of assets in 2022) increased $464.2 million, or 23%, between the two periods, with a net increase to operating income (loss) of $199.3 million. The increase in our operating income during 2022 is primarily attributable to increased volumes and pricing within our sodium minerals and sulfur services segment and increased utilization and day rates in our marine transportation segment, as well as lower depreciation, depletion and amortization during 2022.

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 sodium minerals 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”) increased approximately 39% to $94.90 per barrel in 2022 as compared to $68.14 per barrel in 2021. 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 and to ANSAC 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. 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, costs include activities associated with mining and extracting trona ore, including energy costs and employee compensation. In our Alkali Business, during 2022, as noted above, we had positive effects to our revenues compared to 2021 (with a lesser impact to costs) due to favorable export pricing of soda ash and higher sales volumes as a result of increased economic and market demand. 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

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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 contract for approximately 90% of the revenues from our marine inland barges, which are used primarily to 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 sodium minerals and sulfur services, offshore pipeline 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, 2022 Compared with Year Ended December 31, 2021

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 46,660 41,776

Distributions from unrestricted subsidiaries(2) 32,000 —

Offshore pipeline transportation Segment Margin $ 363,373 $ 317,560

Volumetric Data 100% basis:

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

Natural gas transportation volumes (MMBtus/day) 343,347 345,870

Volumetric Data net to our ownership interest(4):

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

Natural gas transportation volumes (MMBtus/day) 108,908 107,417

(1)Offshore pipeline transportation Segment Margin includes distributions received from our offshore pipeline joint ventures accounted for under the equity method of accounting in 2022 and 2021, 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, including changes in ownership interest, multiplied by the relevant throughput over the given year.

(5)On November 17, 2021, we divested a 36% minority interest in our CHOPS pipeline. The volumes for 2021 represent our 100% ownership during 2021 through November 16, 2021 and our 64% ownership from November 17, 2021 through December 31, 2021.

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Offshore Pipeline Transportation Segment Margin for 2022 increased $45.8 million, or 14%, from 2021, primarily due to (i) distributions received from one of our unrestricted subsidiaries, Independence Hub LLC, of $32 million, net to our interest, for the sale of our 80% owned platform asset, and (ii) increased crude oil and natural gas activity, primarily from first oil achieved at the King’s Quay FPS on April 12, 2022, which supports volumes from the Khaleesi, Mormont and Samurai field developments, succeeded by a ramp up in production that has reached 100,000 barrels of oil equivalent per day. The King’s Quay FPS is life-of-lease dedicated to our 100% owned crude oil and natural gas lateral pipelines and further downstream to our 64% owned Poseidon and CHOPS crude oil systems and our 25.67% owned Nautilus natural gas system for ultimate delivery to shore. Additionally, our 2022 segment margin benefited from our minimum volume commitments associated with the Argos FPS, which will handle production from the Mad Dog 2 field development and is anticipated to come online in the middle part of 2023. These increases were partially offset by an increased level of operational downtime during 2022 that was primarily a result of unplanned operational maintenance associated with one of our lateral pipelines that also impacted volumes on our main pipeline downstream of it in the first quarter of 2022, and a period of unplanned producer downtime at numerous fields connected to our pipeline infrastructure in the fourth quarter of 2022, which returned to normal operations by the end of the year. Lastly, the 2022 period was impacted, relative to the 2021 period, by our decrease in ownership of CHOPS, as we sold a 36% minority interest on November 17, 2021.

Sodium Minerals and Sulfur Services Segment

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

Year Ended December 31,

Volumes sold :

NaOH (caustic soda) volumes (DST sold) 90,876 84,278

Revenues (in thousands):

NaHS revenues, excluding non-cash revenues $ 183,966 $ 128,959

Total segment revenues, excluding non-cash revenues(1) $ 1,162,601 $ 871,986

Average index price for NaOH per DST(2) $ 1,118 $ 787

(1)Totals are for external revenues and costs prior to intercompany elimination upon consolidation.

(2)Source: IHS Chemical.

Sodium minerals and sulfur services Segment Margin for 2022 increased $139.9 million, or 84%, from 2021. This increase is primarily due to more favorable export and domestic pricing and higher sales volumes in our Alkali Business and higher NaHS sales volumes in our refinery services business during 2022. In our Alkali Business, we have continued to see strong demand improvement and growth as a result of the global economic recovery and the continued application of soda ash in everyday end use products, including solar panels, and in the production of lithium carbonate and lithium hydroxide, which are some of the building blocks of lithium batteries that are expected to play a large role in the anticipated energy transition. This continued demand, combined with flat or even slightly declining supply of soda ash in the near term, has tightened the overall supply and demand balance and created a higher price environment for our tons and increased contribution to Segment Margin during 2022. We expect our weighted average sales price for 2023 to exceed 2022 prices. Additionally, we successfully restarted our original Granger production facility on January 1, 2023 and are still on schedule to complete our Granger Optimization Project in the second half of 2023, which represents an incremental 750,000 tons of annual production that we

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anticipate to ramp up. In our refinery services business, we had an increase in NaHS sales volumes and the corresponding pricing of these sales volumes in 2022 due to an increase in demand from our mining customers as a result of the continued global economic recovery and the use of NaHS in the mining of copper, which is used in products that are a key part of the anticipated energy transition.

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, 2022:

•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 $ 890,719 $ 651,097

Crude oil and CO2 pipeline tariffs and revenues 31,822 35,303

Distributions from unrestricted subsidiaries not included in income(1) — 70,000

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

Onshore crude oil pipelines:

Total crude oil and petroleum products sales 24,643 24,239

(1)2021 includes total cash payments received from our previously owned NEJD pipeline of $70.0 million not included in income, which is defined as unrestricted subsidiaries under our senior secured credit agreement.

(2)Total daily volumes for the years ended December 31, 2022 and 2021 include 28,850 and 32,526 Bbls/day, respectively, of intermediate refined products and 53,459 and 55,363 Bbls/day, respectively, of crude oil associated with our Port of Baton Rouge Terminal pipelines.

(3)Includes total barrels for unloading at all rail facilities.

Segment Margin for our onshore facilities and transportation segment decreased $65.1 million, or 66% , in 2022 as compared to 2021. The decrease is primarily due to 2021 including cash receipts of $70 million associated with our previously owned NEJD pipeline. This decrease was partially offset by higher volumes on our Texas pipeline during 2022, which is a destination point for various grades of crude oil produced in the Gulf of Mexico including those transported on our 64% owned CHOPS pipeline.

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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 98.6 % 81.9 %

Offshore Barge Utilization 96.9 % 95.9 %

(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 2022 increased $31.6 million, or 92%, from 2021. This increase is primarily attributable to higher utilization rates, which exited the year at 100% in both our inland and offshore fleets, and higher day rates, including the M/T American Phoenix, during 2022. Demand for our barge services to move intermediate and refined products has increased throughout 2022 due to the recovery of refinery utilization rates as well as the lack of new supply of similar type vessels (primarily due to higher construction costs) as well as the retirement of older vessels in the market. These factors have also contributed to an overall increase in spot and term rates for our services. These increases were partially offset by the M/T American Phoenix. While the M/T American Phoenix had higher day rates throughout 2022 relative to 2021, its contribution to our segment margin was negatively impacted as it went into a planned mandatory regulatory dry-dock from July 21, 2022 through September 16, 2022. Upon completion of the dry-dock, the M/T American Phoenix went back on hire and is currently under contract through the end of 2023 with an investment grade customer at a more favorable rate than 2022.

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 8,279 4,748

Total general and administrative expenses $ 66,598 $ 61,185

Total general and administrative expenses increased $5.4 million between 2022 and 2021. The increase is primarily due to higher costs associated with our long-term incentive compensation plan as a result of the assumptions used to value our outstanding awards and higher corporate general and administrative costs during 2022.

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Depreciation, depletion and amortization expense

Year Ended December 31,

(in thousands)

Total depreciation, depletion and amortization expense $ 296,205 $ 309,746

Total depreciation, depletion and amortization expense decreased $13.5 million between 2022 and 2021. The decrease in depreciation and depletion expense is primarily attributable to the acceleration of depreciation on certain of our asset retirement obligation assets during 2021 as a result of updates to the estimated timing and costs associated with certain of our non-core offshore natural gas assets.

Interest expense, net

Year Ended December 31,

(in thousands)

Interest expense, Alkali senior secured notes 15,811 —

Amortization of debt issuance costs, premium and discount 8,479 9,452

Net interest expense decreased $7.6 million between 2022 and 2021 primarily due to a decrease in interest expense associated with our senior secured credit facility and an increase in capitalized interest. The decrease in interest expense on our senior secured credit facility is due to a lower outstanding balance throughout 2022 as a result of: (i) the proceeds we received from the additional issuance of $250 million in aggregate principal of our 2027 Notes in April 2021; (ii) the proceeds from the sale of a noncontrolling interest in our CHOPS pipeline in November 2021; and (iii) the proceeds we received from the issuance of our Alkali senior secured notes in May 2022 in excess of the funds used to redeem our Alkali Holdings preferred units, all of which were used to pay down the outstanding balance under our senior secured credit facility. Additionally, we had higher capitalized interest during 2022 as a result of our increased capital expenditures associated with the GOP and our offshore growth capital construction projects, both of which are being funded internally.

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, 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 “Loss (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.

Net loss for the year ended December 31, 2021 included an unrealized loss of $30.8 million from the valuation of our embedded derivative associated with our Class A Convertible Preferred Units included in “Other expense, net” in the Consolidated Statement of Operations.

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A discussion of the operating results for the year ended December 31, 2021 compared with the year ended December 31, 2020 has been omitted from this Form 10-K. This discussion can be found within our previously filed 2021 Form 10-K, which was filed with the SEC on February 24, 2022.

Non-GAAP Financial Measures

General

To help evaluate our business, this Annual Report on Form 10-K includes the non-generally accepted accounting principle (“non-GAAP”) financial measure of Available Cash before Reserves. We also present total Segment Margin as if it were a non-GAAP measure. Our non-GAAP measures may not be comparable to similarly titled measures of other companies because such measures may include or exclude other specified items. The 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 13 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 13 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)

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. 2021 includes $70.0 million in cash receipts associated with principal repayments on our previously owned NEJD pipeline not included in income, which is defined as an unrestricted subsidiary under our credit agreement.

(3)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). 2021 includes an unrealized loss of $30.8 million from the valuation of the embedded derivative and an unrealized gain of $0.1 million from the valuation of our commodity derivatives (excluding fair value hedges).

(4)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. 2021 includes the transaction costs and write-off of the unamortized issuance costs associated with the redemption of our remaining 2023 Notes.

(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.

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

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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, 2022 and 2021 was as follows:

Year Ended December 31,

(in thousands)

Net income (loss) attributable to Genesis Energy, L.P. $ 75,457 $ (165,067)

Depreciation, depletion, amortization, and accretion 307,519 315,896

Gain on sale of assets (32,000) —

Distributions to preferred unitholders (80,052) (74,736)

Redeemable noncontrolling interest redemption value adjustments(1) 30,443 25,398

(1)Includes PIK distributions and accretion on the redemption feature attributable to each period, and valuation adjustments to the redemption feature as the associated preferred units 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, which initially provided for a $950 million senior secured credit facility, which comprised a revolving loan 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 revolving loan 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 “new credit agreement”) to replace our Fifth Amended and Restated Credit Agreement. The new credit agreement 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, unless more than $150 million of our 6.500% senior notes due 2025 remain outstanding as of June 30, 2025, in which case the new credit agreement matures on such date.

On April 22, 2021 we completed our offering of an additional $250 million in aggregate principal amount of our 2027 Notes (as defined in Note 10 to our Consolidated Financial Statements in Item 8). The additional $250 million of notes have identical terms as (other than with respect to issue price) and constitute part of the same series as our 2027 Notes and the net proceeds from this additional offering were used for general partnership purposes, including repaying a portion of the outstanding borrowings under our senior secured credit facility.

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 senior secured 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 senior secured 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.

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 with the initial interest payment due on October 15, 2023. That issuance generated net proceeds of approximately $491 million, net of issuance costs

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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 senior secured 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.

The successful completion of the above events has resulted in no scheduled maturities of our unsecured notes until 2025 and has provided us a significant amount of available borrowing capacity under our senior secured credit facility, subject to compliance with covenants, to, amongst other things, utilize for funding the remaining growth capital expenditures associated with our Granger Optimization Project 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, 2022, we believe our balance sheet and liquidity position remained strong, including $436.1 million of borrowing capacity available (which does not include our repayment of excess proceeds from the issuance of our 2030 Notes), subject to compliance with our covenants, under the $650 million revolving portion of our senior secured credit facility as of such date.

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 non-core 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 projects;

•interest payments related to outstanding debt;

•asset retirement obligations;

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

•acquisitions of assets or businesses.

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, 2022, we had $205.4 million borrowed under our senior secured credit facility, with $4.7 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, 2022 was $436.1 million, subject to compliance with our covenants. On a pro forma basis, when considering the increased borrowing capacity associated with our new credit agreement, we would have had $636.1 million available for borrowings, subject to compliance with our covenants.

At December 31, 2022, our long-term debt totaled approximately $3.5 billion, consisting of $205.4 million outstanding under our senior secured credit facility (including $4.7 million borrowed under the inventory sublimit tranche), $2.9 billion of senior unsecured notes, net and $402.4 million of Alkali senior secured notes, net, which are secured by the ORRI Interests. Our senior unsecured notes, net balance is comprised of $671.7 million of our 2028 notes, $976.3 million of our 2027 Notes, $336.8 million of our 2026 Notes, $531.6 million of our 2025 Notes, and $339.9 million of our 2024 Notes.

Future payment obligations related to our senior secured credit facility and senior unsecured notes as of December 31, 2022, including both principal and estimated interest payments, are summarized in the table below:

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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, 2022 remained outstanding through the final maturity date of March 15, 2024, and interest rates remained constant from December 31, 2022 through the maturity date.

(2)Each series of senior unsecured notes is further discussed and defined in Note 10 to our Consolidated Financial Statements in Item 8.

(3)Subsequent to December 31, 2022, net proceeds from the issuance of our 2030 Notes were used to repurchase and retire our 2024 Notes, the obligations in respect of the remaining portion of 2024 Notes have been discharged, all as further discussed above.

Future payment obligations associated with our Alkali senior secured notes, as of December 31, 2022, including both estimated principal and interest payments, are summarized in the table below:

Payment Obligations Estimated Interest Payments Estimated Principal Payments

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 10 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

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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 of December 31, 2022, there are 25,336,778 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 Granger Optimization Project. On April 14, 2020, we entered into an amendment to our agreements with BXC to, among other things, extend the construction timeline of the Granger Optimization Project by one year, which we currently anticipate completing in the second half 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.

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, there were no Alkali Holdings preferred units outstanding.

See Note 11 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

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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 all within a relatively short time frame. If we did experience any differences in timing of extraction, processing and sales of this trona or Alkali products, this could impact the cash requirements for these activities in the short term.

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.

Net cash flows provided by our operating activities were $334.4 million and $338.0 million for 2022 and 2021, respectively. The decrease in operating cash flow for 2022 compared to 2021 was primarily due to our working capital requirements partially offset by the increase in our segment margin during 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.

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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 $ 6,292 $ 8,749 $ 8,715

Onshore facilities and transportation assets 2,928 4,476 3,644

Growth capital expenditures:

Marine transportation assets — — —

Onshore facilities and transportation assets — 133 489

Capital expenditures related to equity investees 10,301 352 —

(1)Growth capital expenditures in our offshore pipeline transportation segment for 2022 represent 100% of the costs incurred.

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

Growth Capital Expenditures

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. The anticipated completion date of the project is the second half of 2023. The expansion is expected to increase our production at the Granger facilities by approximately 750,000 tons per year. 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.

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 in the process of 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. 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 facility 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, which we anticipate to increase during 2023 as a result of increased offshore volumes from King’s Quay and Argos, favorable export pricing and continued demand in our Alkali business, and the restart of our original Granger facility on January 1, 2023 and our expanded Granger facility in the second half of 2023.

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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 sodium minerals 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 2022’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, 2023, we paid a distribution of $0.15 per common unit related to the fourth quarter of 2022. With respect to our Class A Convertible Preferred Units, we declared a quarterly cash distribution of $0.9473 per unit (or $3.7890 on an annualized basis). These distributions were paid on February 14, 2023 to unitholders holders of record at the close of business January 31, 2023.

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, 2023 to unitholders of record as of January 31, 2023.

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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, 2022, which are summarized below.

•We have estimated operating lease payment obligations totaling $234.6 million, of which $25.8 million is expected to be paid in 2023 (see Note 4 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 $54.1 million, of which $41.9 million is estimated to be paid in 2023. Contracts to purchase natural gas and utilities are generally at market-based prices. The estimated volumes and market prices at December 31, 2022 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. We expect to complete our Granger Optimization Project during 2023 and anticipate approximately $100 million of remaining capital expenditures. Additionally, we expect to spend approximately $400 million, which is net to our interests, over the next two years to complete the construction of our SYNC pipeline and expansion of our CHOPS pipeline. We also have current asset retirement obligations of approximately $27 million that we expect to pay in 2023. 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 $2.9 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 10 to our Consolidated Financial Statements in Item 8 for additional information regarding our consolidated debt obligations.

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

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

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On May 17, 2022, we entered into our credit agreement amendment, which designated GA ORRI and GA ORRI Holdings as unrestricted subsidiaries under our credit agreement. In addition, the credit agreement 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 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 891,909

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

(in thousands)

Net income before income taxes 29,031

Less: Accumulated distributions to Class A Convertible Preferred Units (80,052)

Net loss available to common unitholders $ (54,190)

(1)Excluded from non-current assets in the table above are $23.0 million of net intercompany receivables due to Genesis Energy, L.P. and the Guarantor Subsidiaries from the non-Guarantor Subsidiaries as of December 31, 2022.

(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 $5.1 million of sales from Guarantor Subsidiaries to non-Guarantor Subsidiaries for the year ended December 31, 2022.

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

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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 a short time period 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.

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.

Impairment of Long-Lived Assets

When events or changes in circumstances indicate that the carrying amount of a fixed asset, intangible asset, equity method investment, or right of use asset with finite lives 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 unamortized cost 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, 2022 and 2021, we did not recognize an impairment expense associated with our long-lived assets. For the year ended December 31, 2020, we recognized impairment expense of $280.8 million associated with long-lived assets (refer to Note 7 in our Consolidated Financial Statements in Item 8 for additional details).

Goodwill represents the excess of the purchase prices we paid for certain businesses over their respective fair values. We do not amortize goodwill; however, we evaluate, and test if necessary, our goodwill (at the reporting unit level) for impairment on October 1 of each fiscal year, and more frequently, if indicators of impairment are present.

We may perform a qualitative assessment of relevant events and circumstances about the likelihood of goodwill impairment. If it is deemed more likely than not the fair value of the reporting unit is less than its carrying amount, we calculate the fair value of the reporting unit. Otherwise, further testing is not required. We may also elect to exercise our unconditional option to bypass this qualitative assessment, in which case we would also calculate the fair value of the reporting unit. The qualitative assessment is based on reviewing the totality of several factors, including macroeconomic conditions, industry and market considerations, cost factors, overall financial performance, other entity specific events (for example, changes in management) or other events such as selling or disposing of a 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

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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, 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, 2022.

For additional information regarding our goodwill, see Note 9 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.

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 11 and Note 18 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.

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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, 2022, 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, 2022 and 2021 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 $11.2 million during 2022 in accumulated other comprehensive income (loss) 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.

Recent Accounting Pronouncements

Recently Issued and Recently Adopted

In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848), which provides expedients and exceptions for accounting treatment of contracts which are affected by the anticipated discontinuation of the London InterBank Offered Rate (“LIBOR”) and other rates resulting from rate reform that are entered into on or before December 31, 2022. Contract terms that are modified due to the replacement of a reference rate are not required to be remeasured or reassessed under relevant accounting standards. On May 17, 2022, we entered into our Second Amendment and Consent to the credit agreement (defined in Note 10 to our Consolidated Financial Statements in Item 8), which among other things, replaced our existing LIBOR rate based borrowings with the Term SOFR rate, which is based on the Secured Overnight Financing Rate (“SOFR”) borrowings. The impact to our senior secured credit facility and related interest expense upon transition to SOFR did not have a material impact on our Consolidated Financial Statements for the year ended December 31, 2022. Refer to Note 10 in our Consolidated Financial Statements in Item 8 for more details.

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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 and (ii) interest rate risk. We use various derivative instruments primarily to manage commodity price risk. Our risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring our derivative positions, as well as our physical volumes, grades, locations, and delivery schedules. We do not acquire and hold futures contracts or other derivatives for the purpose of speculating on price changes. The following discussion addresses each 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 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 futures, swaps, and options. 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, 2022 we had entered into derivative instruments that will settle between January 2023 and March 2023.

•Natural Gas — We utilize natural gas derivatives to hedge commodity price risk inherent in our sodium minerals and sulfur services segment. 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 various instruments including futures, swaps, and options. As of December 31, 2022 we had entered into derivative instruments that will settle between January 2023 and December 2023.

The accounting treatment for our commodity derivatives is discussed further in Note 18 to our Consolidated Financial Statements in Item 8.

The table below presents information about our open commodity derivative contracts at December 31, 2022. Notional amounts in barrels or MMBtu, 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 or MMBtu multiplied by the December 31, 2022 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 340 MMBtu $ 0.03 $ 9 $ (9) $ —

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

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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.

As noted above, on May 17, 2022, we entered into our Second Amendment and Consent to the credit agreement, which among other things, replaced our existing LIBOR rate based borrowings with the Term SOFR rate. The impact to our senior secured credit facility and related interest expense upon transition to SOFR did not have a material impact on our Consolidated Financial Statements for the year ended December 31, 2022. Obligations under our senior secured credit facility bear interest at the 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, 2022, we had $205.4 million of debt outstanding under our senior secured credit facility. A 10% change in the SOFR rate would have resulted in an immaterial impact to Net income for the year ended December 31, 2022.

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 11 and Note 18 to our Consolidated Financial Statements in Item 8 for further discussion of our Class A Convertible Preferred Units and embedded derivatives.

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 and internal controls designed to ensure that information required to be disclosed in our filings under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. As described in our Quarterly Report on Form 10-Q for the period ended June 30, 2022, management identified a material weakness in our internal control over financial reporting during the quarter ended June 30, 2022. The Company implemented measures in an effort to remediate the material weakness and enhance the Company’s accounting and review processes during the three months ended September 30, 2022, which included the following actions: (i) implementing additional review procedures; and (ii) participating in various continuing education courses associated with the review of revenue contracts. As of December 31, 2022, management believes that the measures described above have remediated the material weakness identified during the quarter ended June 30, 2022.

Our chief executive officer and chief financial officer, with the participation of our management, have evaluated our disclosure controls and procedures as of the end of the period covered by this Annual Report on Form 10-K and have determined that such disclosure controls and procedures are effective in providing assurance of the timely recording, processing, summarizing and reporting of information, and in accumulation and communication to management on a timely basis material information relating to us (including our consolidated subsidiaries) required to be disclosed in this Annual Report on Form 10-K.

Changes in Internal Controls over Financial Reporting

Except as noted above, there have been no changes in internal control over financial reporting during the quarter ended December 31, 2022 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Management’s Report on Internal Control over Financial Reporting

Management of the Partnership is responsible for establishing and maintaining effective internal control over financial reporting as defined in Rules 13a-15(f) under the Securities Exchange Act of 1934. The Partnership’s internal control over financial reporting is designed to provide reasonable assurance to the Partnership’s management and board of directors regarding the preparation and fair presentation of published financial statements.

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, 2022. In making this assessment, management used the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). Based on our assessment, we believe that, as of December 31, 2022, the Partnership’s internal control over financial reporting is effective based on those criteria.

Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, our management included a report of their assessment of the design and effectiveness of our internal controls over financial reporting as part of this Annual Report on Form 10-K for the fiscal year ended December 31, 2022. Ernst & Young 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. Ernst & Young’s attestation report on the Partnership’s internal control over financial reporting 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 11.1% of our Class A Common Units and 77.0% of our Class B Common Units, for a combined ownership percentage of 11.1% 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.

Presently, our board of directors believes that, because Mr. 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

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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.

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 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.”

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

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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, or 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) 988-1965.

Directors and Executive Officers

Set forth below is certain information concerning our directors and executive officers, effective as of February 24, 2023.

Name Age Position

Grant E. Sims 67 Director, Chairman of the Board, and Chief Executive Officer

Conrad P. Albert 76 Director

James E. Davison 85 Director

James E. Davison, Jr. 56 Director

Sharilyn S. Gasaway 54 Director

Kenneth M. Jastrow II 75 Director

Jack T. Taylor 71 Director

Robert V. Deere 68 Chief Financial Officer

Edward T. Flynn 64 Executive Vice President

Kristen O. Jesulaitis 53 Chief Legal Officer and Senior Vice President

Ryan S. Sims 39 Senior Vice President

Garland G. Gaspard 68 Senior Vice President

Karen N. Pape 64 Senior Vice President and Controller

Richard R. Alexander 47 Vice President

William S. Goloway 62 Vice President

Chad A. Landry 59 Vice President

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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. 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. 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. 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.

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.

Robert V. Deere has served as Chief Financial Officer of our general partner since October 2008. 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, Genesis Alkali since we acquired that business from Tronox Ltd. in September 2017 (where he also previously served as Executive Vice President). Prior to joining Tronox, Mr. Flynn served as President of FMC Minerals. He was previously President of FMC’s Industrial Chemicals Group. Mr. Flynn is a member of the Board of Directors and Chairman of the Board for ANSAC.

Kristen O. Jesulaitis serves as Chief Legal Officer and Senior Vice President. Since joining Genesis in July 2011, Ms. Jesulaitis has been responsible for overseeing all legal matters of the Company, including acquisitions and commercial

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transactions, compliance and regulatory affairs, corporate governance, finance, and securities. Prior to joining Genesis, Ms. Jesulaitis 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 Senior Vice President of our general partner since March 2019. Mr. Sims served as Vice President from January 2017 to March 2019. Mr. Sims joined Genesis in 2011 and is responsible for our finance, planning, corporate development, and investor relations functions. He has also previously been responsible for the operational and commercial aspects of our rail and terminals businesses. Prior to joining Genesis, Mr. Sims spent six years in the investment banking industry. Mr. Sims is the son of Grant E. Sims, our Chairman and Chief Executive Officer.

Garland G. Gaspard has served as Senior Vice President of our general partner since January 2017 and is responsible for the operational aspects of our onshore and offshore pipelines, 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 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.

Karen N. Pape has served as Senior Vice President and Controller of our general partner since July 2007 and served as Vice President and Controller from May 2002 until July 2007.

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 S. Goloway has served as Vice President of our general partner since January 2017. Mr. Goloway has been responsible for the commercial aspects of our offshore Gulf of Mexico assets from the time we acquired these offshore assets from Enterprise Products in 2015. Prior to this acquisition, Mr. Goloway served in various roles within the offshore group at Enterprise Products since 2005.

Chad A. Landry has served as Vice President of our general partner since January 2017. Mr. Landry joined Genesis in 2013 and since that time has been responsible for all operational and commercial aspects of our sodium minerals and sulfur services segment. Prior to joining Genesis, he spent 14 years at Axiall Corporation (Georgia Gulf), most recently as Vice President - Chlor-Alkali & Vinyls.

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, 2022.

Compensation Discussion and Analysis

Named Executive Officers

Our NEOs for 2022 were:

•Grant E. Sims, Chief Executive Officer;

•Robert V. Deere, Chief Financial Officer;

•Edward T. Flynn, Executive Vice President;

•Kristen O. Jesulaitis, Chief Legal Officer and Senior Vice President; and

•Garland G. Gaspard, Senior 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, or Meridian, as its independent compensation adviser for 2022. 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 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 adviser, 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 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 2022, 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.

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

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analysis of peer data and information disclosed in our peer companies’ public filings, but did not determine or recommend the amount of compensation.

The peer group used for this market analysis in 2022 consisted of the following 14 companies in the energy industry: Plains All American Pipeline, L.P., Targa Resources Corp., DCP Midstream, LP, Equitrans Midstream Corporation, EnLink Midstream, LLC, Magellan Midstream Partners, L.P., 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:

•encourage our executives to build and operate the partnership in a way that is aligned with our common and preferred unitholders’ interests, focusing on growing total unitholder returns and growing the asset base with an emphasis on maintaining a focus on the long-term stability of the enterprise so as to not promote inappropriate risk taking;

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

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

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

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

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

The amount of compensation contingent on performance is a significant percentage of total compensation, therefore ensuring that business decisions and actions lead to the long-term growth and sustainability of the organization. Our bonus plan (including annual and retention bonuses) is driven by the generation of Available Cash before Reserves (as defined in Item. 7 “Management's Discussion and Analysis of Financial Condition and Results of Operations-Financial Measures”) which is an important metric of value for our unitholders, and our safety record, with the goal of retention of key employees and NEOs. Our long-term incentive plan is also linked to our generation of Available Cash before Reserves,our sustainabilityand safety record, as well as the partnership’s ConsolidatedLeverage ratio (as defined in its senior secured credit facility agreement).

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Elements of Our Compensation Program and Compensation Decisions for 2022

The primary elements of our compensation program are a combination of annual cash and long-term incentive-based compensation. For the year ended December 31, 2022, the elements of our compensation program for the NEOs consisted of an annual base salary, discretionary annual bonus awards, and awards under our long-term incentive compensation program.

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

Base Salaries

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

In April 2022, the G&C Committee reviewed the assessments of market levels of compensation developed by Meridian in conjunction with a discussion of individual performance and responsibilities. As a result of this review and taking into account current market conditions, the G&C Committee approved an increase in Mr. Sims’ 2022 base salary to $800,000, representing an increase of 23.1%. This is Mr. Sims’ first increase in base salary since 2018. The base salaries of Mr. Deere and Mr. Flynn remained the same from 2021 at $450,000 and $500,000, respectively. The G&C Committee also approved an increase in Ms. Jesulaitis’ base salary to $450,000, an increase of 12.5%, and an increase in Mr. Gaspard’s base salary to $375,000, an increase of 10.3%, as a result of this review, current market conditions, and their respective levels of responsibility.

Bonuses

Our NEOs typically participate in a bonus program, or the Bonus Plan, in which a majority of company employees participate. As designed by the G&C Committee, each NEO has an annual bonus target based on a stated percentage of his or her base salary. The targeted amount for the NEOs is established based on the analysis of market practices of the peer group and consideration of the level of salary and targeted long-term incentives for each NEO. Based on the G&C Committee's

subjective review of 2022 operational and financial performance, in the context of total NEO compensation, a discretionary

bonus was granted to Mr. Flynn in the amount of $885,000 associated with the performance of the Alkali Business. This bonus

will be paid in March 2023, contingent on Mr. Flynn’s employment on the payment date. Further, it was determined by the

G&C Committee that each NEO will be considered for a retention bonus for 2022, as further discussed below.

Our NEOs may participate in a retention bonus program for which certain key employees, managers and officers are eligible. These retention bonuses are discretionary and are awarded based on individual and company performance with the goal of retaining key employees.In 2022, Mr. Sims was granted a retention bonus of $1,000,000, Ms. Jesulaitis was granted a retention bonus of $550,000, Mr. Flynn was granted a retention bonus of $500,000, Mr. Gaspard was granted a retention bonus of $375,000 and Mr. Deere was granted a retention bonus of $300,000, to be paid in four equal installments at the following dates: September 2023, December 2023, March 2024, and June 2024, contingent upon continued employment at those dates.

We believe that these retention bonuses are an appropriate mechanism to incentivize key executives to remain with us so that we may benefit from their experience in the industry and other competitive opportunities available to them. Over the long term, the G&C committee intends to continue performance-based cash incentives as a cornerstone of our executive pay program.

Long-Term Incentive Compensation