GEL US Equity☆

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

Introduction

We are a growth-oriented master limited partnership 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.

A core part of our focus is in the midstream sector of the crude oil and natural gas industry in the Gulf of Mexico and the Gulf Coast region of the United States. 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.

Our offshore crude oil and natural gas pipeline transportation and handling operations in the Gulf of Mexico focus on providing a suite of services primarily to integrated and large independent energy companies who make intensive capital investments (often in excess of a billion dollars) to develop large-reservoir, long-lived crude oil and natural gas properties. We provide services to one of the most active drilling and development regions in the U.S. (the Gulf of Mexico), a producing region representing approximately 15% of the crude oil production in the U.S. during 2021. Our onshore-based refinery-centric operations located primarily in the Gulf Coast region of the U.S. focus on providing a suite of services primarily to refiners, which includes our sulfur removal services, transportation, storage, and other handling services. Our onshore-based operations occur upstream of, at, and downstream of refinery complexes. Upstream of refineries, we aggregate, purchase, gather and transport crude oil, which we sell to refiners, as well as perform other handling activities. Within refineries, we provide services to assist in sulfur removal/balancing requirements. Downstream of refineries, we provide transportation services as well as market outlets for finished refined petroleum products and certain refining by-products.

The other core focus of our business is 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. Our Alkali Business has a diverse customer base in the United States, Canada, the European Community, the European Free Trade Area and the South African Customs Union with many long-term relationships. It has been operating for over 70 years and has an estimated remaining reserve life (based on 2021 production) of over 100 years.

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

•Overview of 2021 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

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Overview of 2021 Results

We reported Net Loss Attributable to Genesis Energy, L.P. of $165.1 million in 2021 compared to Net Loss Attributable to Genesis Energy, L.P. of $416.7 million in 2020.

Net Loss Attributable to Genesis Energy, L.P. in 2020 was negatively impacted by impairment expense of

$280.8 million primarily associated with the rail logistics assets included within our onshore facilities and transportation segment and a loss on sale of assets of $22.0 million. Net Loss Attributable to Genesis Energy, L.P. in 2021 was impacted, relative to 2020, by higher segment margin of $10.3 million and higher non-cash revenues of approximately $25.4 million primarily within our onshore facilities and transportation and offshore pipeline transportation segments as a result of how we recognize revenue in accordance with GAAP on certain contracts.

These increases were partially offset by the following during 2021: (i) higher interest expense of $23.9 million; (ii) higher depreciation, depletion, and amortization expense of $14.4 million; (iii) higher general and administrative costs of $4.3 million; and (iv) lower equity in earnings of equity investees of $6.1 million primarily due to lower volumes on our Poseidon oil pipeline. See “Other Costs, Interest, and Income Taxes” below for additional discussion regarding the changes to interest expense, depreciation depletion and amortization, and general and administrative costs. Additionally, 2021 includes an unrealized (non-cash) loss from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units of $30.8 million compared to an unrealized (non-cash) loss of $0.9 million in 2020 recorded within “Other expense, net.” “Other expense, net” in 2020 also includes a loss on the extinguishment of our 2022 and 2023 Notes of approximately $32.0 million partially offset by cancellation of debt income of $27.3 million from the repurchase of certain of our senior unsecured notes on the open market throughout the year. Lastly, we allocated net income to our noncontrolling interest holders of $27.0 million during 2021 as compared to $16.4 million during 2020.

Cash flows from operating activities were $338.0 million for the 2021 period compared to $296.7 million for 2020. This increase was primarily attributable to higher segment margin reported during 2021.

Available Cash before Reserves (as defined below in “Financial Measures”) decreased $51.4 million in 2021 to $203.9 million as compared to 2020 Available Cash before Reserves of $255.3 million, primarily due to higher interest expense of $23.9 million, higher maintenance capital utilized of $12.3 million, and 2020 including cancellation of debt income of $27.3 million. These decreases were partially offset by an increase in segment margin of $10.3 million during 2021 further discussed below in “Results from Operations.” See “Financial Measures” below for additional information on Available Cash before Reserves.

Segment Margin was $617.7 million in 2021, an increase of $10.3 million as compared to 2020. We currently manage our businesses through four divisions that constitute our reportable segments - offshore pipeline transportation, sodium 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, 2022, we paid a distribution of $0.15 per unit related to the fourth quarter of 2021.

With respect to our Class A Convertible Preferred Units, we declared a quarterly cash distribution of $0.7374 per preferred unit (or $2.9496 on an annualized basis) for each preferred unit held of record. These distributions were paid on February 14, 2022 to unitholders holders of record at the close of business January 31, 2022.

Recent Developments and Initiatives

Our primary objectives continue to be to generate and grow stable cash flows and deleverage our balance sheet, while maintaining financial flexibility and never wavering from our commitment to safe and responsible operations. We believe we are well positioned to do this as a result of the following strategies and initiatives:

•the long-term contracted commercial opportunities in the Gulf of Mexico, which are scheduled for first production in the first half of 2022, that will provide significant incremental volumes on our offshore pipeline transportation assets with existing connectivity and available capacity, which require minimal to no additional investment from us;

•the normalization and recovery of soda ash markets from the declines in 2020, including both price and volume recovery;

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•the increased capacity for soda ash production in 2023 with the expectation to bring the original Granger facility production back online in the first quarter of 2023 and further increased production capacity from our Granger Optimization Project, which is scheduled to begin first production in the second half of 2023;

•the sale of a 36% minority equity interest in CHOPS for gross proceeds of approximately $418 million, which represents a premium relative to the proportionate carrying value of CHOPS at the transaction date; and

•our recent debt transactions, including the repayment of the $300 million outstanding under the Term Loan under our new credit agreement, and the renewal and extension of the maturity on our senior secured credit facility to mature in 2024 with a current maximum revolving borrowing capacity of $650 million.

These developments and initiatives are discussed in more detail below.

Granger Optimization Project

On September 23, 2019, we announced the Granger Optimization Project. We entered into agreements with BXC for the purchase of up to a total of $350 million of preferred units (or 350,000 preferred units) in Alkali Holdings. The proceeds we receive from BXC will assist in the funding of the anticipated cost of the GOP, subject to compliance with the covenants contained in our agreements with BXC. The preferred unitholders receive PIK in lieu of cash distributions through September 2023, which represents the anticipated construction period.

On April 14, 2020, we entered into an amendment to our agreements with BXC to, among other things, extend the construction timeline of the GOP by one year, to 2023. In consideration for the amendment, we issued 1,750 Alkali Holdings preferred units to BXC, which was accounted for as issuance costs.As of December 31, 2021, there are 246,394 Alkali Holdings preferred units outstanding. During the fourth quarter of 2021, we made the decision to fund the remaining construction costs required to complete the GOP internally through a combination of our generated free cash flow and availability under our Revolving Loan.

We expect to increase capacity for soda ash production in 2023 with the expectation to bring the original Granger facility and its approximately 500,000 tons of production back online in the first quarter of 2023 and further increase production capacity from our GOP, which is scheduled to begin first production in the second half of 2023 and ramp to its design capacity of an additional 750,000 tons per year over the subsequent nine to twelve months.

Credit Facility Amendment

On April 8, 2021, we entered into our new credit agreement to replace our Fourth Amended and Restated Credit Agreement. Our new credit agreement initially provided for a $950 million senior secured credit facility, comprised of a Revolving Loan with a borrowing capacity of $650 million and a Term Loan of $300 million. Our Term Loan was paid off in full with a portion of the proceeds received from the sale of a 36% interest in CHOPS (discussed further below). The new credit agreement matures on March 15, 2024, subject to extension at our request for one additional year on up to two occasions and subject to certain conditions.

Senior Unsecured Note Transactions

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). The notes constitute an additional issuance of our existing 2027 Notes that we issued on December 17, 2020 in an aggregate principal amount of $750 million. The additional $250 million of notes have identical terms as (other than with respect to the issue price) and constitute part of the same series of the 2027 Notes. The $250 million of the 2027 Notes were issued at a premium of 103.75% plus accrued interest from December 17, 2020. We used the net proceeds from the offering for general partnership purposes, including repaying a portion of the revolving borrowings outstanding under our new credit agreement.

On December 17, 2020, we issued $750.0 million in aggregate principal amount of our 2027 Notes. That issuance generated net proceeds of approximately $737 million, net of issuance costs incurred. We used $316.5 million of the net proceeds to repay the portion of our 2023 Notes (including principal, accrued interest and tender premium) that were validly tendered, and the remaining proceeds at the time were used to repay a portion of the borrowings outstanding under our senior secured credit facility. On January 19, 2021, we redeemed the remaining principal balance outstanding on our 2023 Notes of $80.9 million in accordance with the terms and conditions of the indenture governing the 2023 Notes. We incurred a total loss of approximately $1.6 million relating to the extinguishment of our remaining 2023 Notes, inclusive of the redemption fee and the write-off of the related unamortized debt issuance costs, which is recorded in “Other expense, net” in our Unaudited Condensed Consolidated Statement of Operations for the year ended December 31, 2021.

Sale of a Minority Interest in CHOPS

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On November 17, 2021, we closed on the sale of a 36% minority equity interest in CHOPS for gross proceeds of approximately $418 million (which represents a premium relative to the proportionate carrying value of CHOPS). Proceeds from the sale, net of fees and expenses, were used to repay the full $300 million outstanding under our Term Loan and the remainder will be utilized for general partnership purposes, including our decision to internally fund the remaining capital expenditures associated with the GOP. We own 64% of CHOPS and remain the operator of the pipeline.

Covid-19 and Market Update

In March 2020, the World Health Organization categorized Covid-19 as a pandemic, and the President of the United States declared the Covid-19 outbreak a national emergency. Our operations, which fall within the energy, mining and transportation sectors, are considered critical and essential by the Department of Homeland Security's Cybersecurity and Infrastructure Security Agency and we have continued to operate our assets during this pandemic.

We have a designated internal management team to provide resources, updates, and support to our entire workforce during this pandemic, while maintaining a focus to ensure the safety and well-being of our employees, the families of our employees, and the communities in which our businesses operate. We will continue to act in the best interests of our employees, stakeholders, customers, partners, and suppliers and make any necessary changes as required by federal, state, or local authorities as we continue to actively monitor the situation.

Covid-19 has caused continued volatility in commodity prices due to, among other things, reduced industrial activity and travel demand, varying worldwide restrictions, and the timing of the re-opening of economies throughout the last two years that are expected to continue in the near future. Additionally, actions taken by the Organization of the Petroleum Exporting Countries (OPEC) and other oil exporting nations beginning in early March 2020 caused additional volatility in the price of oil and gas. While we have seen continued recovery in commodity prices since the beginning of the pandemic, primarily due to

economies re-opening over time, there is still an element of volatility that we expect to continue at least for the near-term and

possibly longer, due to the continued uncertainty of the pandemic, which could further negatively impact oil, natural gas, petroleum products and industrial products.

Due to the economic effects from commodity price volatility and Covid-19, demand and volumes throughout our businesses were negatively impacted beginning in the second quarter of 2020. Additionally, during 2020, our businesses were negatively impacted by lower refinery utilization, crude differentials, supply and demand imbalances in our Alkali Business, and an unprecedented hurricane season. However, we began to see economic recovery across a majority of our asset footprint as we exited 2020, which continued throughout 2021. Specifically, during 2021, oil and natural gas prices have seen a recovery from the lows experienced in 2020 and our offshore pipeline transportation segment experienced volumes at its normal run rate as we resumed normal operations on our CHOPS pipeline. Additionally, our Alkali Business has continued to see volume demand recovery and continued pricing recovery on our ANSAC export volumes.

We will continue to monitor the market environment and will evaluate whether additional triggering events would indicate possible impairments of long-lived assets, intangible assets and goodwill. Management’s estimates are based on numerous assumptions about future operations and market conditions, which we believe to be reasonable but are inherently uncertain. The uncertainties underlying our assumptions could cause our estimates to differ significantly from actual results, including with respect to the duration and severity of the Covid-19 pandemic. In the current volatile economic environment and to the extent conditions deteriorate, we may identify triggering events that may require future evaluations of the recoverability of the carrying value of our long-lived assets, intangible assets and goodwill, which could result in impairment charges that could be material to our results of operations.

Although the ultimate impacts of Covid-19 are still unknown at this time, we believe the fundamentals of our core businesses continue to remain strong and, given the current industry environment and capital market behavior, we have continued our focus on deleveraging our balance sheet as further explained above.

Results of Operations

In the discussions that follow, we will focus on our revenues, expenses and Net income (loss), 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, 2021 increased $300.8 million, or 16%, from the year ended December 31, 2020, and our costs and expenses (excluding the loss on sale of assets and impairment expense in 2020) increased $282.0 million, or 16%, between the two periods, with a net increase to operating income (loss) of $18.8 million. The increase in our operating income during 2021 is primarily attributable to increased volumes and pricing within our sodium minerals and sulfur services segment and increased volumes in our offshore pipeline transportation segment. These increases were partially offset

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by lower rail unload and onshore pipeline volumes in our onshore facilities and transportation segment and lower day rates in in our marine transportation segment, primarily associated with our inland barge operation and our M/T American Phoenix tanker, as well as higher depreciation, depletion and amortization and general and administrative expenses during 2021.

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 73% to $68.14 in 2021 as compared to $39.40 per barrel in 2020. 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, 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 selling prices are contracted at various times throughout the year and for different durations. Our selling prices for volumes sold internationally and through 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 and economic growth. Positive or negative changes to our revenue, through fluctuations in sales volumes or selling 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 2021, as noted above, we had positive effects to our revenues (with a lesser impact to costs) due to higher sales volumes and more favorable export pricing of soda ash relative to 2020 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 the Gulf Coast, unlike the lighter crude oil and condensates produced from numerous onshore shale plays. 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 Gulf of Mexico crude oil and natural gas 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

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volumes transported on our onshore crude pipelines, and refiners contract for approximately 80% 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, impairment expense and loss 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, 2021 Compared with Year Ended December 31, 2020

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 41,776 39,973

Offshore pipeline transportation Segment Margin $ 317,560 $ 270,078

Volumetric Data 100% basis:

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

Natural gas transportation volumes (MMBtus/day) 345,870 324,395

Volumetric Data net to our ownership interest(4):

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

Natural gas transportation volumes (MMBtus/day) 107,417 106,781

(1)Offshore pipeline transportation Segment Margin includes distributions received from our offshore pipeline joint ventures accounted for under the equity method of accounting in 2021 and 2020, respectively.

(2)Our CHOPS pipeline was out of service from August 26, 2020 to February 4, 2021 and had no volumes during this period due to damage at a junction platform that the CHOPS pipeline goes up and over. We were able to divert all volumes during this period onto our 64% owned Poseidon oil pipeline.

(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.

Offshore Pipeline Transportation Segment Margin for 2021 increased $47.5 million, or 18%, from 2020, primarily due to higher overall volumes on our crude oil and natural gas pipeline systems due to less unplanned downtime in 2021 and the

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impact on 2020 of incremental operating costs as a result of the named storms that impacted our business, which are further discussed below.

During 2020, our offshore pipeline transportation segment experienced an unprecedented period of unplanned downtime and interruption from Tropical Storm Cristobal and Hurricanes Laura, Marco, Delta and Zeta as a result of producers shutting in and us taking the necessary safety precautions to remove all personnel from the platforms that we operate and maintain. In addition to the majority of our assets being shut in, our CHOPS pipeline, although not damaged, was out of service from August 26, 2020 until February 4, 2021, at which time it resumed service, due to damage at a junction platform that the CHOPS pipeline goes up and over. Additionally and as a result of these events, we incurred incremental operating expenses during 2020 related to certain regulatory inspections and analyses performed to ensure our assets were safe to return to service. While we experienced downtime from named storms in 2021, particularly Hurricane Ida, the impact to our results in the period was not as significant as the events during 2020 and storms in 2021 did not damage any of our infrastructure in the Gulf of Mexico. In addition to our increased overall volumes as a result of less downtime in 2021, we also transported higher volumes on our 100% owned SEKCO pipeline as a result of increased production activity from the Buckskin and Lucius fields, which are fully dedicated to SEKCO pipeline and further downstream to Poseidon pipeline.

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) 84,278 77,274

Revenues (in thousands):

NaHS revenues, excluding non-cash revenues $ 128,959 $ 115,797

Total segment revenues, excluding non-cash revenues(1) $ 871,986 $ 797,616

Average index price for NaOH per DST(2) $ 787 $ 674

(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 2021 increased $36.7 million, or 28%, from 2020. This increase is primarily due to higher volumes and more favorable export and domestic pricing in our Alkali Business during 2021 and higher NaHS volumes in our refinery services business. During 2020, volume demand in our Alkali Business was significantly impacted by the worldwide economic shutdowns and uncertainty from the Covid-19 pandemic. As economies have continued to open up and reduce restrictions, we have seen demand recovery in 2021, both domestically and internationally through ANSAC, and we produced at a high rate (including selling out of production during the year) at our Westvaco facility during 2021. Our increased demand and more favorable pricing during 2021 were partially offset by lower sales volumes at our Granger facility, as it was put in cold standby during the second half of 2020 and had no production during 2021. We plan to bring our Granger facility and its approximate 500,000 tons of annual production back online during the first quarter of 2023, which is anticipated to be several months before the completion of the GOP, as a result of the expected continued improvement in market conditions, including export pricing, through 2022 and into 2023. In our refinery services business, we reported higher NaHS volumes in 2021 primarily due to improved demand for our domestic pulp and paper

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customer base that was negatively impacted in 2020 as a result of the timing of spring turnarounds and outages due to the Covid-19 pandemic. This was partially offset by lower demand from our mining customers, primarily in Peru.

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, 2021:

•facilitating the transportation of crude oil from producers to refineries and from owned and third party terminals to refiners via pipelines;

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

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

•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; and

•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.

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.

In our refined products marketing operations, we supply primarily fuel oil, asphalt and other heavy refined products to wholesale markets and some end-users such as paper mills and utilities. We also provide a service to refineries by purchasing “heavier” petroleum products that are the residual fuels from gasoline production, transporting them to one of our terminals and blending them to a quality that meets the requirements of our customers.

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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 $ 651,097 $ 439,338

Crude oil and CO2 pipeline tariffs and revenues 35,303 58,249

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

Onshore crude oil pipelines:

CO2 pipeline (average Mcf/day):

Total crude oil and petroleum products sales 24,239 27,073

(1)2021 includes total cash payments received from our previously owned NEJD pipeline of $70.0 million not included in income. 2020 includes total cash payments received from our previously owned NEJD pipeline of $56.8 million, of which $48.0 million were not included in income, and distributions from our Free State pipeline of $22.5 million not included in income, both of which are defined as unrestricted subsidiaries under our senior secured credit agreement.

(2)Total daily volume for the years ended December 31, 2021 and 2020 include 32,526 and 26,708 Bbls/day respectively of intermediate refined products associated with our Port of Baton Rouge Terminal pipelines.

(3)The volumes presented for 2020 represent the average Mcf/day through October 29, 2020, after which we divested the related asset.

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

Segment Margin for our onshore facilities and transportation segment decreased $48.4 million, or 33% , in 2021 as compared to 2020. The decrease is primarily due to: (i) 2020 including $22.5 million of distributions from our Free State pipeline, which was associated with the proceeds received from our divestiture of the pipeline during the fourth quarter of 2020, as well as its contributions to segment margin for the first nine months of 2020; and (ii) lower actual volumes during 2021 and lower contracted minimum commitments with our main customer associated with our Baton Rouge corridor assets (including rail, terminal and pipeline volumes) as these commitments stepped down beginning in 2021, as well as the use of prepaid transportation credits (that built up in 2020) in 2021 by our main customer. These decreases were partially offset by higher cash receipts in 2021 of $13.2 million associated with our previously owned NEJD 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 81.9 % 77.8 %

Offshore Barge Utilization 95.9 % 95.4 %

(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 2021 decreased $25.5 million, or 42%, from 2020. This decrease is primarily attributable to lower day rates in our inland barge business during 2021 and a lower day rate associated with our M/T American Phoenix tanker. During 2021, we saw continued pressure on our inland day rates as a result of Midwest and Gulf Coast refineries running at lower utilization rates to better align with overall demand as a result of the current operating environment and uncertainty as a result of the Covid-19 pandemic. During 2020, our M/T American Phoenix received a higher day rate under its historical five-year term contract that ended on September 30, 2020 compared to its shorter term contracts it operated under during 2021. The M/T American Phoenix is currently contracted through the first quarter of 2022 with an investment grade refining company. While we began to see a positive trend to day rates as we exited 2021, we have continued to enter into short term contracts (less than a year) in both the inland and offshore markets because we believe the day rates currently being offered by the market have yet to fully recover from their cyclical lows.

Other Costs and Interest

General and administrative expenses

Year Ended December 31,

(in thousands)

General and administrative expenses not separately identified below:

Long-term incentive based compensation plan expense (benefit) 4,748 (1,420)

Total general and administrative expenses $ 61,185 $ 56,920

Total general and administrative expenses increased $4.3 million between 2021 and 2020. The increase is primarily due to an increase in third-party costs associated with business development activities and growth projects primarily related to the sale of a 36% interest in CHOPS during 2021. Additionally, we recorded higher costs associated with our long-term incentive compensation plan as a result of the assumptions used to value our outstanding awards. These increases were partially

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offset by a decrease in our corporate general and administrative costs primarily related to a charge of approximately $13 million incurred during 2020 related to certain severance and restructuring expenses.

Depreciation, depletion, and amortization expense

Year Ended December 31,

(in thousands)

Total depreciation, depletion and amortization expense $ 309,746 $ 295,322

Total depreciation, depletion, and amortization expense increased $14.4 million between 2021 and 2020. The increase in depreciation and depletion expense is primarily attributable to the acceleration of depreciation on our asset retirement obligation assets as a result of updates to the estimated timing and costs associated with certain of our non-core offshore gas assets. This increase was partially offset by lower depreciation expense associated with our rail logistics assets in 2021 as they were impaired during the second quarter of 2020, and lower amortization expense in 2021 due to our contract intangible asset associated with the M/T American Phoenix being fully amortized during the third quarter of 2020.

Impairment expense and Loss on sale of assets

During the year ended December 31, 2020, we recorded impairment expense of $277.5 million associated with the rail logistics assets included within our onshore facilities and transportation segment. We also recorded $3.3 million of impairment expense in 2020 associated with the full write-off of one of our non-core offshore gas platforms that does not have future use within our operations. We did not record impairment expense during the year ended December 31, 2021. See Note 7 to our Consolidated Financial Statements in Item 8 for additional discussion.

During the year ended December 31, 2020, we recorded a loss on sale of assets of $22.0 million associated with the divestiture of our Free State pipeline. The loss recorded represents the difference between the proceeds received and the net book value of the assets sold.

Interest expense, net

Year Ended December 31,

(in thousands)

Amortization of debt issuance costs, premium, and discount 9,452 9,499

Net interest expense increased $23.9 million between 2021 and 2020, primarily due to increased interest expense associated with our senior unsecured notes. On December 17, 2020, we issued our $750 million 2027 Notes that accrue interest at 8.00% and we purchased and extinguished the remaining principal balance of our 6.00% 2023 Notes on January 19, 2021. On April 22, 2021, we issued an additional $250 million in aggregate principal amount of notes under the same terms as our 2027 Notes. The excess proceeds received from the issuance of our 2027 Notes were used to repay borrowings on the Revolving Loan under our senior secured credit facility, which reduced interest expense associated with our senior secured credit facility. Additionally, interest expense associated with our senior secured credit facility further decreased relative to 2020 as proceeds from the sale of a 36% interest in CHOPS were used to repay the full $300 million outstanding under our Term Loan. Capitalized interest increased as a result of our decision to internally fund the remaining capital expenditures associated with the GOP beginning in the fourth quarter of 2021.

Other Consolidated Results

Net loss for the year ended December 31, 2021 included an unrealized loss on the valuation of our embedded derivative associated with our Class A Convertible Preferred Units of $30.8 million compared to an unrealized loss of $0.9 million for the year ended December 31, 2020. Those amounts are included in “Other expense, net” in the Consolidated Statements of Operations.

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A discussion of the operating results for the year ended December 31, 2020 compared with the year ended December 31, 2019 has been omitted from this Form 10-K. This discussion can be found within our previously filed 2020 Form 10-K, which was filed with the SEC on March 1, 2021.

Financial Measures

Overview

This Annual Report on Form 10-K includes the financial measure of Available Cash before Reserves, which is a “non-GAAP” measure because it is not contemplated by or referenced in generally accepted accounting principles in the United States of America (GAAP). 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 GAAP. A reconciliation of Net income (loss) to Segment Margin is included in our segment disclosures 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 has 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), and eliminating any gain or loss on sale of assets. 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) to Segment Margin is included in our segment disclosures 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 and cash tax expense. 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)2021 includes $70.0 million in cash receipts associated with principal repayments on our previously owned NEJD pipeline not included in income. 2020 includes cash payments received from our NEJD pipeline of $48.0 million not included in income and distributions from our previously owned Free State pipeline of $22.5 million, both of which are defined as unrestricted subsidiaries under our senior secured credit agreement.

(3)2021 includes an unrealized loss of $30.8 million from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units and 2020 includes an unrealized loss of $0.9 million from the valuation of this embedded derivative.

(4)2021 includes the transaction costs and write-off of the unamortized issuance costs associated with the redemption of our remaining 2023 Notes. 2020 includes transaction costs associated with the tender and redemption of our 2022 Notes and tender of our 2023 Notes, along with the write-off of the associated unamortized issuance costs and discount associated with the previously held 2022 Notes.

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

(6)Represents all Select Items applicable to Segment Margin.

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

(8)Represents Select Items applicable to Available Cash before Reserves.

Disclosure Format Relating to Maintenance Capital

We use a modified format relating to maintenance capital requirements because our maintenance capital expenditures vary materially in nature (discretionary vs. non-discretionary), timing and amount from time to time. We believe that, without

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such modified disclosure, such changes in our maintenance capital expenditures could be confusing and potentially misleading to users of our financial information, particularly in the context of the nature and purposes of our Available Cash before Reserves measure. Our modified disclosure format provides those users with information in the form of our maintenance capital utilized measure (which we deduct to arrive at Available Cash before Reserves). Our maintenance capital utilized measure constitutes a proxy for non-discretionary maintenance capital expenditures and it takes into consideration the relationship among maintenance capital expenditures, operating expenses and depreciation from period to period.

Maintenance Capital Requirements

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

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

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

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

Maintenance capital utilized

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

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

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Available Cash before Reserves for the years ended December 31, 2021 and 2020 was as follows:

Year Ended December 31,

(in thousands)

Net loss attributable to Genesis Energy, L.P. $ (165,067) $ (416,678)

Depreciation, depletion, amortization, and accretion 315,896 302,602

Loss on sale of assets — 22,045

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

Redeemable noncontrolling interest redemption value adjustments(1) 25,398 16,113

(1) Includes distributions paid-in-kind and accretion adjustments on the redemption feature.

Liquidity and Capital Resources

General

As of December 31, 2021, we believe our balance sheet and liquidity position remained strong, including $599.7 million of borrowing capacity available, subject to compliance with our covenants, under our $650 million senior secured credit facility. 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 notes.

Our primary cash requirements consist of:

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

•routine operating expenses;

•capital growth and maintenance projects;

•acquisitions of assets or businesses;

•interest payments related to outstanding debt;

•asset retirement obligations; and

•quarterly cash distributions to our preferred and common unitholders.

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, 2021, we had $49.0 million borrowed under our senior secured credit facility, with $9.7 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 March 15, 2024. The total amount available for borrowings under our senior secured credit facility at December 31, 2021 was $599.7 million, subject to compliance with our covenants.

At December 31, 2021, our long-term debt totaled approximately $3.0 billion, consisting of $49.0 million outstanding under our senior secured credit facility (including $9.7 million borrowed under the inventory sublimit tranche), $721.0 million

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of our 2028 notes, $1,000.0 million of our 2027 Notes, $359.8 million of our 2026 Notes, $534.8 million of our 2025 Notes, and $341.1 million of our 2024 Notes.

Future payment obligations related to our long-term debt as of December 31, 2021, including both principal and estimated interest payments, are summarized in the table below:

Interest Rate Maturity Date Principal Estimated Annual Interest Payable

(in thousands)

(1)Amounts shown above for estimated interest payments represent the amounts that would be paid on an annual basis if the debt outstanding at December 31, 2021 under our Revolving Loan remained outstanding through the final maturity date of March 15, 2024, and interest rates remained constant from December 31, 2021 through the maturity date.

We have the right to redeem each of our series of 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 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.

On December 17, 2020, we issued $750.0 million in aggregate principal amount of our 2027 Notes. That issuance generated net proceeds of approximately $737 million, net of issuance costs incurred. We used $316.5 million of the net proceeds to repay the portion of our 2023 Notes (including principal, accrued interest and tender premium) that were validly tendered, and the remaining proceeds at the time were used to repay a portion of the borrowings outstanding under our senior secured credit facility. On January 19, 2021, we redeemed the remaining principal balance outstanding on our 2023 Notes of $80.9 million in accordance with the terms and conditions of the indenture governing the 2023 Notes. We incurred a total loss of $1.6 million relating to the redemption extinguishment of our remaining 2023 Notes, inclusive of the redemption fee and the write-off of the related unamortized debt issuance costs, which is recorded in “Other expense, net” in our Consolidated Statement of Operations for the year ended December 31, 2021.

On April 8, 2021, we entered into our new credit agreement to replace our Fourth Amended and Restated Credit Agreement. Our new credit agreement provides for a $950 million senior secured credit facility, comprised of the Revolving Loan with a borrowing capacity of $650 million and the Term Loan with a borrowing capacity of $300 million. Our Term Loan was paid off in full on November 17, 2021 with a portion of the proceeds received from the sale of a 36% minority interest in CHOPS. The new credit agreement matures on March 15, 2024, subject to extension at our request for one additional year on up to two occasions and subject to certain conditions.

On April 22, 2021, we completed our offering of an additional $250 million in aggregate principal amount of our 2027 Notes. The notes constitute an additional issuance of our existing 2027 Notes that we issued on December 17, 2020 in an aggregate principal amount of $750 million. The additional $250 million of notes have identical terms (other than with respect to the issue price) as and constitute part of the same series of the 2027 Notes. The $250 million of the 2027 Notes were issued at a premium of 103.75% plus accrued interest from December 17, 2020. We used the net proceeds from the offering for general partnership purposes, including repaying a portion of the revolving borrowings outstanding under our new credit agreement.

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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 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.

Each of our Class A Convertible Preferred Units accumulate 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), subject to certain adjustments. 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, 2021, 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 $55,000,000 of preferred units (or 55,000 preferred units) and committed to purchase, during a three-year commitment period, up to a total of $350,000,000 of preferred units (or 350,000 preferred units) in Alkali Holdings. Alkali Holdings will use 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 $351,750,000 of preferred units (or 351,750 preferred units) in Alkali Holdings. As of December 31, 2021, there are 246,394 Alkali Holdings preferred units outstanding.

BXC has the right to a quarterly distribution equal to 10% per annum on the liquidation preference of each preferred unit. The liquidation preference is defined as one thousand dollars per preferred unit, plus any accrued and unpaid distributions (including as a result of any distributions paid-in-kind). Distributions are payable quarterly within 45 days after the end of the fiscal quarter. Distributions may be paid in-kind in lieu of cash distributions during the first 48 months following the September 23, 2019 initial closing date. Subsequent to the PIK period, all distributions must be paid in cash. In addition to the quarterly distributions paid to BXC, Alkali Holdings will distribute all of its distributable cash to the Partnership each quarter, which is equal to all cash and cash equivalents in the operating accounts of Alkali Holdings less cash reserves and a minimum $5 million cash balance to be maintained for working capital needs.

From time to time after we have drawn at least $251,750,000, we have 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 are being redeemed, we have not drawn at least $251,750,000, and BXC is not a “defaulting member” under the LLC Agreement, BXC has the right to a make-whole amount on the number of undrawn preferred units.

BXC is obligated to purchase a minimum of $251,750,000 of preferred units unless certain customary closing conditions are not satisfied, including the existence of a triggering event or a material uncured breach of the Securities Purchase Agreement by Alkali Holdings. A triggering event would occur if Alkali Holdings fails to pay cash distributions subsequent to the paid-in-kind period, fails to redeem preferred units when required to by a change of control event, or if any preferred units remain outstanding on the six and a half year anniversary date, amongst other events. The preferred units must be redeemed, in whole or in part, following certain change of control events, fundamental changes, or the liquidation, winding up, or dissolution of Alkali Holdings and, as applicable, the Partnership. If such an event were to occur, the preferred units would rank senior to

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Alkali Holdings common units and any class or series of equity of Alkali Holdings established after the issuance of the preferred units.

At any time following the six and a half year anniversary of the Securities Purchase Agreement, or following the occurrence of certain triggering events, if the preferred units issued and outstanding have not been redeemed in full for cash, BXC has the right to gain control of the board of Alkali Holdings and effectuate a monetization event using its reasonable good faith efforts to maximize the consideration received to the holders of our common units, including the sale of Alkali Holdings (including all of its equity or assets and all of its equity in its subsidiaries), the proceeds of which would first be used to redeem the preferred units at the Base Preferred Return prior to any distribution to us.

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.

Cash Flows from Operations

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

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

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

In our Alkali Business, we typically extract trona from our mining facilities, process into soda ash and other alkali products, and deliver and sell to our customers 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, we may be required to deposit margin funds with the NYMEX 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 $338.0 million and $296.7 million for 2021 and 2020, respectively. The increase in operating cash flow for 2021 compared to 2020 was primarily due to an increase in reported segment margin during 2021.

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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 notes, and/or the creation of strategic arrangements to share capital costs through joint ventures or strategic alliances.

Capital Expenditures for Fixed and Intangible Assets and Equity Investees

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

Years Ended December 31,

(in thousands)

Capital expenditures for fixed and intangible assets:

Maintenance capital expenditures:

Onshore facilities and transportation assets 4,476 3,644 2,966

Growth capital expenditures:

Offshore pipeline transportation assets $ 41,445 $ 4,608 $ 961

Marine transportation assets — — —

Onshore facilities and transportation assets 133 489 3,610

Capital expenditures related to equity investees 352 — —

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. We entered into agreements with BXC for the purchase of up to a total of $350,000,000 of preferred units (or 350,000 preferred units) of Alkali Holdings. The proceeds we receive from BXC will 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. As part of the amendment, the total commitment of BXC was increased to, subject to compliance with the covenants contained in our agreements with BXC, up to $351,750,000 of preferred units (or 351,750 preferred units) in Alkali Holdings. As of December 31, 2021, we had issued 246,394 of preferred units to BXC. The expansion is expected to increase our production at the Granger facility by approximately 750,000 tons per year. During the fourth quarter of 2021, we made the decision to internally fund the remaining capital expenditures associated with the GOP utilizing the available borrowing capacity under our Revolving Loan and free cash flow.

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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 2021’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, 2022, we paid a distribution of $0.15 per unit related to the fourth quarter of 2021. With respect to our Class A Convertible Preferred Units, we have declared a quarterly cash distribution of $0.7374 per preferred unit (or $2.9496 on an annualized basis) for each preferred unit held of record. These distributions were paid on February 14, 2022 to unitholders holders of record at the close of business January 31, 2022.

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, 2022 to unitholders of record as of January 31, 2022.

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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, 2021, which are summarized below.

•We have estimated operating lease payment obligations totaling $248.5 million, of which $28.9 million is expected to be paid in 2022 (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 $164.1 million, of which $147.9 million is estimated to be paid in 2022. Contracts to purchase crude oil, petroleum products, and other chemicals and utilities are generally at market-based prices.The estimated volumes and market prices at December 31, 2021 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 from contractual obligations associated with certain of our growth capital projects (including our GOP) of approximately $150-200 million in 2022. Additionally, we have current asset retirement obligations of approximately $36 million that we expect to pay in 2022. These requirements are expected to be funded primarily with free cash flow generated from our operations and availability under our Revolving Loan.

Guarantor Summarized Financial Information

Our $3.0 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 the subsidiaries that hold our Alkali Business (collectively, the “Alkali Subsidiaries”), Genesis Free State Pipeline, LLC, Genesis NEJD Pipeline, LLC, and certain other subsidiaries. The assets owned by Genesis Free State Pipeline, LLC were sold on October 30, 2020 and the ownership of Genesis NEJD Pipeline LLC's pipeline was transferred on October 30, 2020. See Note 7 to our Consolidated Financial Statements in Item 8 for additional information regarding our asset sales. Genesis NEJD Pipeline, LLC is 100% owned by Genesis Energy, L.P. The remaining non-Guarantor Subsidiaries are owned, directly or indirectly, by Genesis Crude Oil, L.P., a Guarantor Subsidiary. The Guarantor Subsidiaries largely own the assets that we use to operate our business other than our Alkali 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 except, in the case of Alkali Holdings and Genesis Energy, L.P., to the extent agreed to in the services agreement between the Partnership and Alkali Holdings dated as of September 23, 2019. Genesis Energy Finance Corporation has no independent assets or operations. 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.

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.

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

(in thousands, except unit amount)

ASSETS:

LIABILITIES AND CAPITAL:(2)

Class A Convertible Preferred Units 790,115

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

(in thousands)

Net loss before income taxes (171,308)

Less: Accumulated distributions to Class A Convertible Preferred Units (74,736)

Net loss available to common unitholders $ (247,703)

(1)Excluded from non-current assets in the table above are $36.7 million of net intercompany receivables due to Genesis Energy, L.P. and the Guarantor Subsidiaries from the non-Guarantor Subsidiaries as of December 31, 2021.

(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 $5.5 million of sales from Guarantor Subsidiaries to non-Guarantor Subsidiaries for the year ended December 31, 2021.

Critical Accounting Estimates

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

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

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

In conjunction with each acquisition we make, we must allocate the cost of the acquired entity to the assets and liabilities assumed based on their estimated fair values at the date of acquisition. As additional information becomes available, we may adjust the original estimates within 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

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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 year ended December 31, 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 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 quantitative assessment as of October 1, 2021 for our refinery services reporting unit, which is the only reporting unit as of our assessment date that has goodwill. No impairment was recorded in our refinery services reporting unit during 2021 as the fair value far exceeded the carrying value. Additionally, when performing sensitivity analyses to the significant inputs in the fair value, including the discount rate and assumptions related to the future cash flows, a 10% change in these assumptions did not impact of our overall conclusion surrounding the valuation of our goodwill.

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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, and the 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 also have an embedded derivative associated with our Class A Convertible Preferred Units that is accounted for as a liability at fair value in our Consolidated Balance Sheets as of December 31, 2021 and 2020. The fair value of the embedded derivative associated with our Class A Convertible Preferred Units is estimated using a Monte Carlo simulation approach that contains 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 involve management judgment. During the year ended December 31, 2021, we recorded unrealized losses of $30.8 million associated with fair value changes of the embedded derivative associated with our Class A convertible Preferred Unit that were primarily driven by fluctuations in the discount yield from period to period. A significant increase or decrease in these inputs could materially affect 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 cause a decrease or an increase to the fair value of our embedded derivative of approximately $10 million and $13 million, respectively.

Liability and Contingency Accruals and Asset Retirement Obligations

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

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

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

At December 31, 2021, 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 2021, 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 natural gas assets of approximately $36 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, 2021 and 2020 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

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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 $3.1 million during 2021, primarily as a result of the discount rate utilized to calculate our benefit obligation increasing from 3.06% at December 31, 2020 to 3.27% at December 31, 2021.

Recent Accounting Pronouncements

Recently Issued and Recently Adopted

We have adopted the guidance under ASC Topic 326 Financial Instruments - Credit Losses (“ASC 326”), as of January 1, 2020. The standard changed the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities are required to use a new forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. We have assessed our receivables for expected losses by considering current and historical information pertaining to our trade accounts and existing contract assets. Our assessment resulted in an immaterial impact to consolidated financial statements as of the adoption date and for the years ended December 31, 2021 and 2020.

During the first quarter of 2020, the SEC amended the financial disclosure requirements for guarantors and issuers of guaranteed securities registered or being registered in Rule 3-10 of Regulation S-X to go in effect January 4, 2021. The amendment simplifies the disclosure requirements and permits the amended disclosures to be provided outside the footnotes in audited annual or unaudited interim consolidated financial statements in all filings. We have included the required summarized financial information in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.

We have adopted guidance under ASC Topic 842, Lease Accounting (“ASC 842”), as of January 1, 2019 utilizing the modified retrospective method of adoption. Additionally, we elected to implement the practical expedients that pertain to easements, separation of lease components, and the package of practical expedients, which among other things, allows us to carry over previous lease conclusions reached under ASC 840. As a result of adopting the new lease standard, we recorded an operating lease right of use asset of approximately $209 million with a corresponding lease liability as of the transition date. Refer to Note 4 in our Consolidated Financial Statements in Item 8 for further details, including the activity during 2021 and 2021 relating to our associated leases.

In January 2017, the FASB issued guidance to simplify the goodwill impairment testing at annual or interim periods. The guidance eliminates Step 2 from the goodwill impairment testing process, and any identified impairment charge would be simplified to be the difference between the carrying value and fair value of a reporting unit, but would not exceed the total amount of goodwill allocated to the reporting unit in question. The guidance is effective for annual reporting periods, and interim periods therein, beginning after December 15, 2019. We elected to early adopt this standard as of January 1, 2017. Refer to Note 9 in our Consolidated Financial Statements in Item 8 for further information.

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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, 2021 we had entered into derivative instruments that will settle between January 2022 and February 2022.

•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, 2021 we had entered into derivative instruments that will settle between January 2022 and December 2022.

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, 2021. 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, 2021 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:

Crude Oil Bbl 3 Bbl $ 1.76 $ 5 $ (4) $ 1

Natural Gas MMBtu 150 MMBtu $ 0.06 $ 9 $ (8) $ 1

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

Interest Rate Risk

We are also exposed to market risks due to the floating interest rates on our senior secured credit facility. Obligations under our senior secured credit facility bear interest at the LIBOR 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, 2021, we had $49.0 million of debt outstanding under our senior secured credit facility. Due to the significant decline in the LIBOR rate which began in 2020 and continued in 2021, a 10% change in LIBOR would have resulted in an immaterial impact to Net income (loss) for the year ended December 31, 2021.

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 LIBOR and other rates resulting from rate reform. The Alternative Reference Rates Committee, a group of market participants convened under the auspices of the U.S. Federal Reserve Board and other U.S. regulators, has recommended the Secured Overnight Financing Rate (“SOFR”), calculated based on repurchase agreements backed by treasury securities, as its recommended alternative benchmark rate to replace LIBOR. The consequences of these developments cannot be entirely predicted but may include an increase in the interest rate on our senior secured credit facility when transitioning from LIBOR to SOFR, which may have an adverse effect on our financial condition, operating results or cash flows.

The Preferred Distribution Rate Reset Election of our Class A Convertible Preferred Units is an embedded derivative that must be bifurcated from the related host contract, the preferred unit purchase agreement, and recorded at fair value in our Consolidated Balance Sheets. The valuation model utilized for this embedded derivative contains inputs including our common unit price, U.S. treasury rates and dividend yields to ultimately calculate the fair value of our Class A Convertible Preferred Units with and without the Preferred Distribution Rate Reset Option. See Note 18 to our Consolidated Financial Statements in Item 8 for a discussion of 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. 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

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

Management’s Report on Internal Control over Financial Reporting

Management of the Partnership is responsible for establishing and maintaining 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.

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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, 2021. 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, 2021, 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, 2021. 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 11.0% of our Class A Common Units and 77.0% of our Class B Common Units, for a combined ownership percentage of 11.0% of total Common Units. Pursuant to its unitholder rights agreement, the Davison family is entitled to elect up to three of our directors based on its members’ collective ownership percentage of our outstanding common units: (i) with 15% or more ownership, they have the right to appoint three directors, (ii) with less than 15% ownership but more than 10%, they have the right to appoint two directors, and (iii) with less than 10% ownership, they have the right to appoint one director. That unitholder rights agreement also provides that, so long as the Davison family has the right to elect three directors thereunder, our board of directors cannot have more than 11 directors without the Davison family’s consent. In addition to their rights under that unitholder rights agreement, if the members of the Davison family act as a group, they have the ability to elect at least a majority of our directors because they own a majority of our Class B units.

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

Our board of directors currently consists of Sharilyn S. Gasaway, James E. Davison, James E. Davison, Jr., Kenneth M. Jastrow II, Conrad P. Albert, Jack T. Taylor and Mr. 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, attributable to any period ending after March 1, 2019.

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

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and Jack T. Taylor. Ms. Gasaway is the chairperson. Our board of directors believes that Ms. Gasaway and Mr. Taylor qualify as audit committee financial experts as such term is used in the rules and regulations of the SEC. The charter of the audit committee is available on our website (www.genesisenergy.com) free of charge. Each member of the audit committee is an independent director under NYSE rules.

Governance, Compensation and Business Development Committee

The governance, compensation and business development committee, 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 919 Milam, Suite 2100, 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.

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Directors and Executive Officers

Set forth below is certain information concerning our directors and executive officers, effective as of February 24, 2022.

Name Age Position

Grant E. Sims 66 Director, Chairman of the Board, and Chief Executive Officer

Conrad P. Albert 75 Director

James E. Davison 84 Director

James E. Davison, Jr. 55 Director

Sharilyn S. Gasaway 53 Director

Kenneth M. Jastrow II 74 Director

Jack T. Taylor 70 Director

Robert V. Deere 67 Chief Financial Officer

Edward T. Flynn 63 Executive Vice President

Richard R. Alexander 46 Vice President

Karen N. Pape 63 Senior Vice President and Controller

Kristen O. Jesulaitis 52 General Counsel

William S. Goloway 61 Vice President

Garland G. Gaspard 67 Senior Vice President

Chad A. Landry 58 Vice President

Ryan S. Sims 38 Senior Vice President

Grant E. Sims has served as a director and Chief Executive Officer of our general partner since August 2006 and Chairman of the Board of our general partner since October 2012. Mr. 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 master limited partnership. 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

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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.

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.

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.

Kristen O. Jesulaitis has served as our General Counsel since July 2011. She is responsible for all legal functions of Genesis, including acquisitions and commercial transactions, compliance and regulatory affairs, corporate governance, securities, and finance. 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.

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.

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.

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.

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.

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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, 2021.

Compensation Discussion and Analysis

Named Executive Officers

Our NEOs for 2021 were:

•Grant E. Sims, Chief Executive Officer;

•Robert V. Deere, Chief Financial Officer;

•Edward T. Flynn, Executive Vice President;

•Garland G. Gaspard, Senior Vice President; and

•Kristen O. Jesulaitis, General Counsel.

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 2021. 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 such as obtaining exemptions from the “insider trading” rules under Section 16 of the Exchange Act in connection with certain acquisitions. 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 2021, 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

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regarding executive compensation plans. Meridian also developed assessments of market levels of compensation through an analysis of peer data and information disclosed in our peer companies’ public filings, but did not determine or recommend the amount of compensation.

The peer group used for this market analysis in 2021 consisted of the following 15 companies in the energy industry: Plains All American Pipeline, L.P., Targa Resources Corp., DCP Midstream, LP, Enable Midstream Partners, LP, HollyFrontier 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.