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, terminalling 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 crude oil and natural gas producers, refiners, and industrial and commercial enterprises and have a diverse portfolio of assets, including pipelines, offshore hub and junction platforms, refinery-related plants, storage tanks and terminals, railcars, rail unloading facilities, barges and other vessels, and trucks.
Our offshore Gulf of Mexico crude oil and natural gas pipeline transportation and handling operations 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 numerous 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 2020. 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 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 2020 production) of over 100 years.
Included in Management’s Discussion and Analysis are the following sections:
•Overview of 2020 Results
•Recent Developments and Initiatives
•Results of Operations
•Other Consolidated Results
•Financial Measures
•Liquidity and Capital Resources
•Guarantor Summarized Financial Information
•Commitments and Off-Balance Sheet Arrangements
•Critical Accounting Policies and Estimates
•Recent Accounting Pronouncements
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Overview of 2020 Results
We reported Net Loss Attributable to Genesis Energy, L.P. of $416.7 million in 2020 compared to Net Income Attributable to Genesis Energy, L.P. of $96.0 million in 2019.
Net Loss Attributable to Genesis Energy, L.P. in 2020 was negatively impacted, relative to 2019, by: (i) impairment expense of $280.8 million primarily associated with the rail logistics assets included within our onshore facilities and transportation segment; (ii) lower segment margin of $105.8 million, which is inclusive of approximately $59 million of incremental cash receipts received in 2020 and included in 2020's segment margin, associated with principal repayments on our direct financing lease and the proceeds received from the sale of our Free State pipeline; (iii) lower non-cash revenues of $49.3 million within our offshore pipeline transportation and onshore facilities and transportation segments as a result of how we recognize revenue in accordance with GAAP on certain contracts; (iv) a loss on the extinguishment of our 2022 and 2023 Notes during 2020 of approximately $32 million recorded in other income (expense); (v) a loss on sale of assets of $22.0 million; and (vi) net income attributable to our redeemable noncontrolling interests of $16.1 million during 2020 as compared to $2.2 million in 2019. Additionally, 2019 included positive changes in estimated abandonment costs for certain of our non-operating offshore gas assets of $15.7 million (which was recorded within "offshore pipeline transportation operating costs" in the Condensed Consolidated Statements of Operations).
These decreases were partially offset by (i) lower depreciation, depletion and amortization expense of $24.5 million during 2020 primarily due to lower depreciation expense on our rail logistics assets as they were impaired during the second quarter of 2020; (ii) cancellation of debt income of $27.3 million recorded in other income (expense) from the repurchase of certain of our senior unsecured notes on the open market during 2020; (iii) lower interest expense of $9.7 million during 2020; and (iv) higher equity in earnings of equity investees of $7.5 million during 2020 primarily due to increased volumes on our 64% owned Poseidon oil pipeline.
Cash flow from operating activities was $296.7 million for the 2020 period compared to $382.3 million for 2019. This decrease was primarily attributable to lower segment margin reported during 2020.
Available Cash before Reserves (as defined below in "Financial Measures") decreased $104.2 million in 2020 to $255.3 million as compared to 2019 Available Cash before Reserves of $359.5 million, primarily due to lower reported segment margin in 2020. See "Financial Measures" below for additional information on Available Cash before Reserves.
Segment Margin was $607.5 million in 2020, a decrease of $105.8 million as compared to 2019. See "Results from Operations" below for discussion on our individual segments.
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 12, 2021, we paid a distribution of $0.15 per unit related to the fourth quarter of 2020.
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 12, 2021 to unitholders holders of record at the close of business January 29, 2021.
Recent Developments and Initiatives
Our primary objective continues to be to generate and grow stable cash flows and de-leverage our balance sheet, while 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 initiatives:
•the new long-term contracted commercial opportunities that will provide significant incremental volumes on our already constructed offshore pipeline transportation assets that require minimal to no additional investment from us;
•the expected normalization of soda ash markets over time, including demand and price recovery;
•our minimal expected growth capital expenditures for the foreseeable future with the exception of our Granger Optimization Project (which can be fully funded externally, subject to compliance with the covenants contained in our agreements with GSO) discussed in more detail below;
•the continued realization, in 2021 and beyond, of our cost saving initiatives implemented in mid-2020 (discussed in more detail below) and the reduction of our distribution to common unitholders beginning in the first quarter of 2020;
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•the disposition and early monetization of our non-core legacy CO2 business discussed in more detail below; and
•our recent debt transactions, which effectively refinanced our senior notes with the nearest maturities and lowered our overall outstanding indebtedness.
Granger Production Facility Expansion
On September 23, 2019, we announced the Granger Optimization Project. We entered into agreements with GSO for the purchase of up to a total of $350,000,000 of preferred units (or 350,000 preferred units) in Alkali Holdings. The proceeds we receive from GSO will fund up to 100% of the anticipated cost of the Granger Optimization Project. The Alkali Holdings preferred unitholders receive PIK distributions in lieu of cash distributions during the anticipated construction period.
On April 14, 2020, we entered into an amendment to our agreements with GSO to, among other things, extend the construction timeline of the Granger Optimization Project by one year. The extended completion date of the project is currently anticipated to be near the end of 2023. In consideration for the amendment, we issued 1,750 Alkali Holdings preferred units to GSO, which was accounted for as issuance costs. As part of the amendment, the total commitment of GSO was increased to, subject to compliance with the covenants contained in our agreements with GSO, up to $351,750,000 of preferred units (or 351,750 preferred units) in Alkali Holdings. As of December 31, 2020, there are 141,249 Alkali Holdings preferred units outstanding.
CO2 Assets
On October 30, 2020, we reached an agreement with a subsidiary of Denbury Inc. to transfer to it the ownership of our remaining CO2 assets, including the North East Jackson Dome ("NEJD") and Free State pipelines. As a part of the agreement, we will receive total consideration of $92.5 million, of which $22.5 million was paid in the fourth quarter of 2020 upon execution of the agreements, and the remaining $70 million will be paid in equal installments during each quarter of 2021. Refer to Note 4 and Note 7 for additional discussion.
Credit Facility Amendments
On March 25, 2020, we amended our credit agreement. This amendment, among other things, (i) sets the maximum Consolidated Senior Secured Leverage Ratio (as defined in the credit agreement) at 3.25 to 1.00 throughout the remaining term of the facility, and (ii) allows us to purchase certain of our outstanding senior unsecured notes, subject to certain customary conditions.
On July 24, 2020, we further amended our credit agreement. The amendment increases our Consolidated Leverage Ratio from 5.50X to 5.75X from September 30, 2020 through March 31, 2021, after which time it reverts back to 5.50X for the remaining term of the agreement. Additionally, it decreases our Consolidated Interest Coverage Ratio from 3.0X to 2.75X from September 30, 2020 through March 31, 2021, after which time it reverts back to 3.0X for the remaining term of the agreement.
Senior Unsecured Note Transactions
On January 16, 2020, we issued $750.0 million in aggregate principal amount of our 2028 Notes. That issuance generated net proceeds of approximately $736.7 million, net of issuance costs incurred. The net proceeds were used to purchase $554.8 million of our existing 2022 Notes, including the related accrued interest and tender premium on those notes, and the remaining proceeds at the time were used to repay a portion of the borrowings outstanding under our revolving credit facility. On January 17, 2020 we called for redemption the remaining $222.1 million of our 2022 Notes, and they were redeemed on February 16, 2020.
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 revolving credit facility. On January 19, 2021 we redeemed the remaining principal of $80.9 million of our 2023 Notes in accordance with the terms and conditions of the indenture governing the 2023 Notes.
During the year ended December 31, 2020, we repurchased $153.6 million of certain of our senior unsecured notes on the open market and recorded cancellation of debt income of $27.3 million, which allowed us to reduce our overall indebtedness and associated interest charges.
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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 commodity prices to decline due to, among other things, reduced industrial activity and travel demand 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 significant declines and volatility in the price of oil and gas. These low and volatile commodity prices are expected to continue at least for the near-term and possibly longer, reflecting fears of a global recession and potential further global economic damage from Covid-19, including factory shutdowns, travel bans, closings of schools and stores, and cancellations of conventions and similar events, resulting in, among other things, reduced fuel demand, lower manufacturing activity, and high inventories of oil, natural gas, and petroleum products, which could further negatively impact oil, natural gas, and petroleum products and industrial products.
Due to the economic effects from commodity prices and Covid-19, demand and volumes throughout our businesses were negatively impacted beginning in the second quarter of 2020. As a result of lower current demand and the outlook for our crude-by-rail logistics assets, and rail becoming an uneconomic means of transportation for producers to get crude oil to their refineries, we identified a triggering event and subsequently recognized a non-cash impairment charge associated with these assets in our onshore facilities and transportation segment during 2020 ( See Note 7 for additional discussion).
As we closed out the year, we believe we have begun to see a slight recovery in demand as certain regions of the United States and the world slowly begin their re-opening phases. Specifically, in our sodium minerals and sulfur services operating segment, domestic and ANSAC volume demand and NaHS demand in South America have shown signs of recovery which we expect to continue into 2021.
In addition to Covid-19, we experienced several major weather disruptions, including Tropical Storm Cristobal and Hurricanes Laura, Marco, Delta and Zeta, which caused significant downtime and damage to certain of our assets in the Gulf of Mexico causing an increase to our operating costs in our offshore pipeline transportation segment.
Although the potential future limitations and impact of Covid-19 are still unknown at this time, and although we tend to experience less demand for certain of our services and products when commodity prices decrease significantly over extended periods of time (and we expect a similar impact on demand when global restrictions are in place limiting the economy and industrial product use), 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 de-leveraging our balance sheet as further explained above.
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 further deteriorate, we may identify additional 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 further impairment charges that could be material to our results of operations.
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.
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Revenues, Costs and Expenses
Our revenues for the year ended December 31, 2020 decreased $656.2 million, or 26%, from the year ended December 31, 2019, and our costs and expenses (excluding loss on sale of assets and impairment expense in 2020) decreased $440.4 million, or 20%, between the two periods, with a net change to operating income (loss) of $215.8 million.
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, and revenues and costs associated with our Alkali Business, which is included in our sodium minerals and sulfur services segment. The decrease in our revenues and costs between 2020 and 2019 is primarily attributable to: (i) decreases in crude oil and petroleum product prices, and to an extent, sales volumes; and (ii) lower sales volumes in our sodium minerals and sulfur services segment due to lower economic and market demand as a result of Covid-19 and lower contractual export pricing in our Alkali Business. Additionally, our offshore pipeline transportation segment experienced lower volumes and revenue due to several named weather events, which impacted our assets in the Gulf of Mexico during 2020, and also resulted in increased operating expenses due to the costs incurred to perform the required inspections and analysis on our assets. Depreciation, depletion, and amortization expense was $24.5 million lower during 2020 as compared to 2019 primarily due to lower depreciation expense associated with our rail logistics assets, as they were impaired during the second quarter of 2020. We describe, in more detail, the impact on revenues and costs for each of our businesses below.
As it relates to our crude oil marketing business, the average closing prices for West Texas Intermediate crude oil on the New York Mercantile Exchange ("NYMEX") decreased approximately 31% to $39.40 in 2020 as compared to $56.96 per barrel in 2019. 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 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. Typically, our selling prices for volumes sold internationally and through ANSAC are contracted for the
current year (in a majority of cases, annually) in the prior December and January of the current year, 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 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 2020,
as noted above, we had negative effects to our revenues (with a lesser impact to costs) due to lower sales volumes and
lower export pricing of soda ash during 2020 as a result of lower economic and market demand. For additional information, see our segment-by-segment analysis below.
In addition to our crude oil marketing business and Alkali Business discussed above, we continue to operate in our other core businesses, including: (i) our offshore Gulf of Mexico crude oil and natural gas pipeline transportation and handling operations, focusing on integrated and large independent energy companies who make intensive capital investments (often in excess of a billion dollars) to develop numerous large reservoir, long-lived crude oil and natural gas properties; (ii) our sulfur services business; and (iii) 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 97% of the volumes transported on our onshore crude pipelines, and refiners contract for approximately 80% of the use of our inland barges, which are used primarily to transport intermediate refined products (not crude oil) between refining complexes. 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
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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 relatively low commodity price environments. Given these facts, we do not expect changes in commodity prices to impact our Net Income, 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.
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 and amortization, impairment expense and loss on sale of assets, interest 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, 2020 Compared with Year Ended December 31, 2019
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 39,973 54,108
Offshore pipeline operating costs, excluding non-cash expenses (70,644) (69,561)
Offshore pipeline transportation Segment Margin $ 270,078 $ 320,023
Volumetric Data 100% basis:
Crude oil pipelines (average barrels/day unless otherwise noted):
Natural gas transportation volumes (MMBtus/d) 324,395 400,770
Volumetric Data net to our ownership interest (4):
Crude oil pipelines (average barrels/day unless otherwise noted):
Natural gas transportation volumes (MMBtus/d) 106,781 152,388
(1)Offshore pipeline transportation Segment Margin includes distributions received from our offshore pipeline joint ventures accounted for under the equity method of accounting in 2020 and 2019, respectively.
(2)Our 100% owned CHOPS pipeline was out of service from August 26, 2020 to December 31, 2020 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 2020 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.
Offshore Pipeline Transportation Segment Margin for 2020 decreased $49.9 million, or 16%, from 2019, primarily due to lower overall volumes on our crude oil and natural gas pipeline systems and a relative increase in operating costs. During 2020, our Gulf of Mexico assets experienced a significant amount of unplanned maintenance downtime from certain fields connected to our assets and interruption from Tropical Storm Cristobal and Hurricanes Laura, Marco, Delta and Zeta as a result of producers shutting in during the storm and us taking the necessary precautions to remove all personnel from the platform assets that we operate and maintain. In addition to the majority of our assets being shut in, our 100% owned CHOPS pipeline,
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although not damaged, has been out of service since August 26, 2020 due to damage at a junction platform that the CHOPS pipeline goes up and over. We were able to successfully divert all CHOPS barrels to our 64% owned and operated Poseidon oil pipeline system, but continued to incur our fixed costs associated with the CHOPS pipeline. On February 4, 2021, we placed the CHOPS pipeline back into service upon the installation of a bypass that allows our pipeline to operate around the junction platform. We incurred approximately $8 million of incremental operating costs in 2020 as a result of our continued regulatory inspections to analyze damage associated with our assets from the previously named weather events. In addition to this unplanned downtime and interruption, we also experienced our normal planned downtime, which, at times during 2020, was extended due to the economic environment. Lastly, our 2019 segment margin included volumes and margin contribution from one of our non-core gas pipelines that was abandoned near the end of 2019.
These decreases were partially offset by increased volumes flowing from the Buckskin and Hadrian North
production fields in 2020 (which had first oil towards the end of the second quarter of 2019), which is fully dedicated to our
100% owned SEKCO pipeline, and further downstream, our 64% owned Poseidon oil pipeline system.
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 (dry short tons sold) 77,274 78,927
Revenues (in thousands):
NaHS revenues, excluding non-cash revenues $ 115,797 $ 148,812
Total segment revenues, excluding non-cash revenues (1) $ 797,616 $ 1,031,303
Average index price for NaOH per DST (2) $ 674 $ 692
(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 2020 decreased $93.8 million, or 42%, from 2019. This decrease is primarily due to lower volumes and lower export pricing in our Alkali Business and lower NaHS volumes in our refinery services business. During 2020, our Alkali Business was negatively impacted by lower demand for our soda ash volumes, primarily in the second and third quarters, as a result of economic shutdowns amidst the uncertainty from the Covid-19 pandemic. In response to this we made the decision to put our Granger facility, which has an annual production capacity of 500,000 short tons, in cold standby. We began to see increased volume demand for soda ash as we exited the third quarter and throughout the fourth quarter of 2020, including selling out of 100% of the production from our Westvaco facility in the fourth quarter, and expect this trend to continue into 2021. These lower soda ash volumes during 2020 were coupled with lower export pricing due to supply and demand imbalances that existed at the time of our re-contracting phase in December 2019 and January 2020. We expect that both domestic and export prices in 2021 will be marginally lower than those we experienced this year. In our refinery services business, we experienced a decline in NaHS volumes during 2020 due to lower demand from our mining customers in South America as a result of customer shut-ins, primarily in Peru, due to the spread of
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Covid-19. This decline was coupled with lower demand from certain of our domestic mining and pulp and paper customers throughout the year ended December 31, 2020.
Onshore Facilities and Transportation Segment
Our onshore facilities and transportation segment utilizes an integrated set of pipelines and terminals, as well as trucks, railcars, 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 United States Gulf Coast crude oil market. In addition, we utilize our railcar and trucking fleets that support 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, 2020:
•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, railcars 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 $ 439,338 $ 747,619
Crude oil and CO2 pipeline tariffs and revenues 58,249 69,418
Volumetric Data (average barrels/day unless otherwise noted):
Onshore crude oil pipelines:
CO2 pipeline (average Mcf/day):
Total crude oil and petroleum products sales 27,073 31,681
(1)2020 includes cash payments received from our NEJD pipeline of $48.0 million 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. 2019 includes cash payments received from our NEJD pipeline of $8.4 million not included in income.
(2)Total daily volume for the years ended December 31, 2020 and 2019 include 26,708 and 51,267 barrels per 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 increased $35.8 million, or 32% , in 2020 as compared to 2019. The increase is primarily due to: (i) 2020 including approximately $36 million of higher cash receipts compared to 2019 associated with our direct financing lease due to the acceleration of principal payments from our customer and (ii) distributions of $22.5 million received in the fourth quarter from the sale of our Free State pipeline. These increases were partially offset by lower volumes across our asset footprint in Louisiana, including our Baton Rouge corridor assets and our Raceland rail facility. During 2020, as a result of lower crude oil prices and the tightening of the differential of Western Canadian Select (WCS) to the Gulf Coast, crude-by-rail became an uneconomic mode of transportation for producers for a majority of the year. Lastly, our 2019 Segment Margin includes the receipt of a cash payment of $10 million associated with the resolution of a crude oil supply agreement.
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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 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 77.8 % 96.8 %
Offshore Barge Utilization 95.4 % 94.6 %
(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 2020 increased $2.1 million, or 4%, from 2019. During 2020, in our offshore barge operation, we benefited from the continual improving rates in the spot and short term markets coupled with increased utilization relative to 2019. This was partially offset by lower utilization and day rates in our inland business. We expect to see continued pressure on our utilization, and to an extent, the spot rates in our inland business as Midwest and Gulf Coast refineries continue to lower their utilization rates to better align with overall demand as a result of Covid-19 and the current operating environment. Additionally, the five year contract associated with our M/T American Phoenix tanker ended on September 30, 2020. We have re-contracted the tanker beginning in the fourth quarter of 2020 at a lower rate and shorter term. 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 (1,420) 3,948
Total general and administrative expenses $ 56,920 $ 52,687
Total general and administrative expenses increased $4.2 million between 2020 and 2019. The increase is primarily due to the effects of a one-time charge of approximately $13 million related to certain severance and restructuring expenses incurred during the second quarter of 2020. This was partially offset by lower long-term incentive compensation expense due to the effect of changes in assumptions used to value our outstanding awards and lower third party costs associated with business development activities and growth projects during 2020, as 2019 included costs associated with the closing of our financing transaction for the Granger Optimization Project.
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Depreciation, depletion, and amortization expense
Year Ended December 31,
(in thousands)
Amortization of CO2 volumetric production payments — 889
Total depreciation, depletion and amortization expense $ 295,322 $ 319,806
Total depreciation, depletion, and amortization expense decreased $24.5 million between 2020 and 2019. This decrease is primarily due to lower depreciation expense in 2020 associated with our rail logistics assets as they were impaired during the second quarter of 2020. Additionally, our contract intangible associated with the M/T American Phoenix became fully amortized on September 30, 2020, which resulted in lower overall amortization expense in 2020.
Impairment Expense and Loss on sale of assets
During the year ended December 31, 2020, we recorded impairment expense of approximately $277 million associated with the rail logistics assets included within our onshore facilities and transportation segment. We also recorded approximately $4 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 a future use within our operations. See Note 7 for additional discussion.
During the year ended December 31, 2020, we recorded a loss on sale of assets of approximately $22 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 and discount 9,499 10,766
Net interest expense decreased $9.7 million between 2020 and 2019, primarily due to a lower interest rate on our revolving credit facility during the period. The decline in our interest rate during 2020 is due to the decrease in LIBOR rates during the period, which is one of the main drivers of interest expense on our credit facility. Additionally, we repurchased a total of $153.6 million of our senior unsecured notes on the open market during 2020 for a gain of $27.3 million, which reduced our overall outstanding indebtedness and related interest expense during the year.
These decreases were partially offset by higher interest expense on our senior unsecured notes and lower capitalized interest during 2020. On January 16, 2020, we issued our $750 million 2028 Notes that accrue interest at 7.75%, and we purchased and extinguished $527.9 million of our $750 million 2022 Notes that accrued interest at 6.75% on January 15, 2020 through a tender offer and we redeemed the remaining $222.1 million of our 2022 Notes on February 16, 2020. On December 17, 2020, we issued our $750 million 2027 Notes that accrue interest at 8%, and we purchased and extinguished $308.8 million of our outstanding 2023 Notes that accrued interest at 6%.
Other Consolidated Results
Net loss for the year ended December 31, 2020 included an unrealized loss on the valuation of our embedded derivative associated with our Class A Convertible Preferred Units of $0.9 million compared to an unrealized loss of $9.0 million for the year ended December 31, 2019. Those amounts are included in other income (expense) in the Consolidated Statement of Operations.
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A discussion of the operating results for the year ended December 31, 2019 compared with the year ended December 31, 2018 has been omitted from this Form 10-K. This discussion can be found within our previously filed 2019 Form 10-K, which was filed with the SEC on February 27, 2020.
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 Segment Margin to net income (loss) 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, after eliminating gain or loss on sale of assets, plus or minus applicable Select Items. 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 Segment Margin to net income (loss) 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
(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.
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We define Available Cash before Reserves (“Available Cash before Reserves”) as net income(loss) before interest, taxes, depreciation and amortization (including impairment, write-offs, accretion and similar items) after eliminating other non-cash revenues, expenses, gains, losses and charges (including any loss on asset dispositions), plus or minus certain other select items that we view as not indicative of our core operating results (collectively, “Select Items”), as adjusted for certain items, the most significant of which in the relevant reporting periods have been the sum of maintenance capital utilized, 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
Certain non-cash items:
Loss on debt extinguishment(3) 31,730 —
II. Applicable only to Available Cash before Reserves
Equity compensation adjustments — (137)
(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) 2020 includes cash payments received from our NEJD pipeline of $48.0 million 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. 2019 includes cash payments received from our NEJD pipeline of $8.4 million not included in income.
(3) 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.
(4) Represents the net effect of adding distributions from equity investees and deducting earnings of equity investees net to us.
(5) Represents all Select Items applicable to Segment Margin.
(6) Represents transaction costs relating to certain merger, acquisition, transition and financing transactions incurred in advance of acquisition.
(7) 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 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.
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Maintenance Capital Requirements
MAINTENANCE CAPITAL EXPENDITURES
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 have been (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, 2020 and 2019 was as follows:
Year Ended December 31,
(in thousands)
Net income (loss) attributable to Genesis Energy, L.P. $ (416,678) $ 95,999
Depreciation, depletion, amortization, and accretion 302,602 308,115
Loss on sale of assets 22,045 —
Distributions to preferred unitholders (74,736) (62,190)
Redeemable noncontrolling interest redemption value adjustments(1) 16,113 2,233
(1) Includes distributions paid in kind and accretion adjustments on the redemption feature.
Liquidity and Capital Resources
General
As of December 31, 2020, we believe our balance sheet and liquidity position remained strong, including $1,055.2 million of borrowing capacity available, subject to compliance with our covenants, under our $1.7 billion senior secured revolving credit facility. We anticipate that our future internally-generated funds and the funds available under our credit facility will allow us to meet our ordinary course capital needs. Our primary sources of liquidity have been cash flows from operations, borrowing availability under our credit facility 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 (minimal) 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 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, 2020, we had $643.7 million borrowed under our credit facility, with $34.4 million of the borrowed amount designated as a loan under the inventory sublimit. Due to the revolving nature of loans under our credit facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date of May 9, 2022. Our credit facility does not include a “borrowing base” limitation except with respect to our inventory loans.
The total amount available for borrowings under our credit facility at December 31, 2020 was $1,055.2 million, subject to compliance with our covenants. We expect to extend and amend our Credit Agreement in 2021 prior to its maturity date.
At December 31, 2020, our long-term debt totaled $3.4 billion, consisting of $643.7 million outstanding under our credit facility (including $34.4 million borrowed under the inventory sublimit tranche), $721.0 million of our 2028 notes,
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$750.0 million of our 2027 Notes, $359.8 million of our 2026 Notes, $534.8 million of our 2025 Notes, $341.1 million of our 2024 Notes and $80.9 million of our 2023 Notes.
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.
(1) Refer to Note 23 for discussion surrounding the redemption of our remaining outstanding 2023 Notes during the first quarter of 2021.
In January 2020, we issued $750 million in aggregate principal amount of our 2028 Notes. Interest payments are due February 1 and August 1 of each year with the initial interest payment due August 1, 2020. That issuance generated net proceeds of approximately $736.7 million, net of issuance costs incurred. Of the net proceeds, $554.8 million were used to repurchase the 2022 Notes (including principal, accrued interest and tender premium) that were validly tendered in our tender offer for the 2022 Notes, and the remaining balance was used for repaying a portion of the borrowings outstanding under our revolving credit facility. On January 17, 2020 we called for redemption the remaining balance of our 2022 Notes with a redemption date of February 16, 2020.
In December 2020, we issued $750 million in aggregate principal amount of our 2027 Notes. Interest payments are due January 15 and July 15 of each year with the initial interest payment due on July 15, 2021. 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 revolving credit facility. In January 2021, we redeemed the remaining balance of our 2023 Notes in accordance with the terms and conditions of the indenture governing the 2023 Notes.
During the year ended December 31, 2020, we repurchased $153.6 million of certain of our senior unsecured notes on the open market and recorded cancellation of debt income of $27.3 million.
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.
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
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"Securities Purchase Agreement") whereby GSO 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 up to 100% of the anticipated cost of the Granger Optimization Project. On April 14, 2020, we entered into an amendment to our agreements with GSO to, among other things, extend the construction timeline of the Granger Optimization Project by one year, which we currently anticipate completing near the end of 2023. In consideration for the amendment, we issued 1,750 Alkali Holdings preferred units to GSO, 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 GSO was increased to, subject to compliance with the covenants contained in our agreements with GSO, up to $351,750,000 of preferred units (or 351,750 preferred units) in Alkali Holdings. As of December 31, 2020, there are 141,249 Alkali Holdings preferred units outstanding.
GSO 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 payment-in-kind period, all distributions must be paid in cash. In addition to the quarterly distributions paid to GSO, 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 GSO is not a "defaulting member" under the LLC Agreement, GSO has the right to a make-whole amount on the number of undrawn preferred units.
GSO 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 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, GSO 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 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.
In 2018, we implemented a universal shelf registration statement (our "2018 Shelf") on file with the SEC. Our 2018 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 2018 Shelf will expire in April 2021. We expect to file a replacement universal shelf registration statement before our 2018 Shelf expires.
Cash Flows from Operations
We generally utilize the cash flows we generate from our operations to fund our common and preferred distributions and working capital needs. Excess funds that are generated are used to repay borrowings under our 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,
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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 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 our borrowings under our 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 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 credit facility or use cash on hand to fund the deposits.
Net cash flows provided by our operating activities were $296.7 million and $382.3 million for 2020 and 2019, respectively. The decrease in operating cash flow for 2020 compared to 2019 was primarily due to lower reported segment margin during 2020.
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 credit facility, equity issuances (common and preferred units), and/or the issuance of senior unsecured notes.
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Capital Expenditures and Business and Asset Acquisitions
The following table summarizes our expenditures for fixed assets, business and other asset acquisitions 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 3,644 2,966 3,340
Growth capital expenditures:
Offshore pipeline transportation assets $ 4,608 $ 961 $ 501
Marine transportation assets — — 12,560
Onshore facilities and transportation assets 489 3,610 47,770
Capital expenditures related to equity investees — — 3,018
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 Granger Optimization Project to expand our existing Granger facility. We entered into agreements with GSO 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 GSO will fund up to 100% of the anticipated cost of the Granger Optimization Project. On April 14, 2020, we entered into an amendment to our agreements with GSO to, among other things, extend the construction timeline of the Granger Optimization Project by one year, which we currently anticipate completing near the end of 2023. We issued 1,750 Alkali Holdings preferred units to GSO in consideration for the amendment. As part of the amendment, the total commitment of GSO was increased to, subject to compliance with the covenants contained in our agreements with GSO, up to $351,750,000 of preferred units (or 351,750 preferred units) in Alkali Holdings. The Alkali Holdings preferred unitholders receive PIK distributions in lieu of cash distributions during the new anticipated construction period. As of December 31, 2020, we had issued 141,249 of preferred units to be used to fund the construction. The expansion is expected to increase our production at the Granger facility by approximately 750,000 tons per year.
Except for the Granger Optimization Project, we do not anticipate spending material growth capital expenditures on any individual projects in the foreseeable future.
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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 2020'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 credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners.
On February 12, 2021, we paid a distribution of $0.15 per unit related to the fourth quarter of 2020. 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 12, 2021 to unitholders holders of record at the close of business January 29, 2021.
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)Prior to the first quarter of 2019, all distributions on our Class A Convertible Preferred units were paid-in-kind.
(2)This distribution was paid on February 12, 2021 to unitholders of record as of January 29, 2021.
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Guarantor Summarized Financial Information
Our $2.8 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 for additional information regarding our asset sales and divestitures. Genesis NEJD Pipeline, LLC is 100% owned by Genesis Energy, L.P. The remaining non-Guarantor Subsidiaries are owned 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 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, which includes related receivable and payable balances, and the investment in and equity earnings from the non-Guarantor Subsidiaries.
Balance Sheets Genesis Energy, L.P. and Guarantor Subsidiaries
ASSETS:
LIABILITIES AND CAPITAL:(1)
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Statements of Operations Genesis Energy, L.P. and Guarantor Subsidiaries
Income (loss) before income taxes (408,717) 566
Net loss available to common unitholders (484,687) (74,589)
(1) There are no noncontrolling interests held at the Issuer or Guarantor Subsidiaries for either period presented.
Excluded from non-current assets in the table above are $95.7 million and $76.2 million of net intercompany receivables due to Genesis Energy, L.P. and the Guarantor Subsidiaries from the non-Guarantor Subsidiaries as of December 31, 2020 and December 31, 2019, respectively.
Commitments and Off-Balance Sheet Arrangements
Contractual Obligations and Commercial Commitments
In addition to our credit facility discussed above, we have contractual obligations under operating leases as well as commitments to purchase crude oil and petroleum products. The table below summarizes our obligations and commitments at December 31, 2020.
Payments Due by Period
(in thousands)
Contractual Obligations:
(1)Our credit facility allows us to repay and re-borrow funds at any time through the maturity date of May 9, 2022. We had $81 million in aggregate principal amount of our 2023 Notes that matured on May 15, 2023 for which we called for early redemption in December 2020, $341 million in aggregate principal amount of senior unsecured notes that mature on June 15, 2024 (the "2024 Notes"), $535 million in aggregate principal amount of senior unsecured notes that mature on October 1, 2025 (the"2025 Notes"), $360 million in aggregate principal amount of senior unsecured notes that mature on May 15, 2026 (the "2026 Notes"), $750 million in aggregate principal amount of our 2027 Notes that mature on January 15, 2027 and $721 million in aggregate principal amount of our 2028 Notes that mature on February 15, 2028.
(2)Interest on our long-term debt under our credit facility is at market-based rates. The interest rates on our 2023, 2024, 2025, 2026, 2027 and 2028 Notes are 6.00%, 5.625%, 6.50%, 6.25%, 8.00%, and 7.75% respectively. The amount shown for interest payments represents the amount that would be paid if the debt outstanding at December 31, 2020 under our credit facility remained outstanding through the final maturity date of May 9, 2022 and interest rates remained at the December 31, 2020 market levels through the final maturity date. Also included is the interest on our senior unsecured notes through their respective maturity dates.
(3)Unconditional purchase obligations include agreements to purchase goods and services that are enforceable and legally binding and specify all significant terms. Contracts to purchase crude oil, petroleum products, and other chemicals and utilities are generally at market-based prices. For purposes of this table, estimated volumes and market prices at December 31, 2020 were used to value those obligations. The actual physical volumes and settlement prices may vary from the assumptions used in the table. Uncertainties involved in these estimates include levels of production at the wellhead, changes in market prices and other conditions beyond our control.
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(4)We have entered into approximately $67 million of committed payment contracts with third parties for the Granger Optimization Project. These commitments are expected to be, subject to compliance with the covenants contained in our agreements with GSO, funded by the issuance of Alkali Holdings preferred units to GSO. We expect to incur these costs within the next three years.
(5)Represents the estimated future asset retirement obligations on a discounted basis. The recorded asset retirement obligation on our balance sheet at December 31, 2020 was $176.9 million and is further discussed in Note 7 to our Consolidated Financial Statements.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements, special purpose entities, or financing partnerships, other than as disclosed under “Contractual Obligations and Commercial Commitments” above.
Critical Accounting Policies and Estimates
The preparation of our consolidated financial statements in conformity with accounting principles generally accepted in the United States 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. Estimates and assumptions about future events and their effects cannot be determined with certainty, and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the business environment in which we operate changes. Significant accounting policies that we employ are presented in the Notes to our Consolidated Financial Statements in Item 8 (see Note 2 “Summary of Significant Accounting Policies”).
We have defined critical accounting policies and estimates as those that are most important to the portrayal of our financial results and positions. These policies require management’s judgment and often employ the use of information that is inherently uncertain. Our most critical accounting policies are discussed below.
Fair Value of Assets and Liabilities Acquired and Identification of Associated Goodwill and Intangible Assets
In conjunction with each acquisition we make, we must allocate the cost of the acquired entity to the assets and liabilities assumed based on their estimated fair values at the date of acquisition. As additional information becomes available, we may adjust the original estimates within a short time period subsequent to the acquisition. In addition, we are required to recognize intangible assets separately from goodwill. Determining the fair value of assets and liabilities acquired, as well as intangible assets that relate to such items 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 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 is not amortized but instead is periodically assessed for impairment. 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 assets (including the reserve life of our mineral leaseholds) at the time the assets are placed in service. We compute depreciation using the straight-line method based on these estimated useful lives. The actual period over which we will use the asset may differ from the assumptions we have made about the estimated useful life. We adjust the remaining useful life as we become aware of such circumstances.
Intangible assets with finite useful lives are required to be amortized over their respective estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset shall be amortized over the best estimate of its useful life. At a minimum, we will assess the useful lives and residual values of all intangible 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 including Right of Use Assets, Intangibles and Goodwill
When events or changes in circumstances indicate that the carrying amount of a fixed asset, intangible asset, or right of use assets with finite lives may not be recoverable, we review our assets for impairment. We compare the carrying value of the fixed 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 the subsequent useful life of
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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, 2020, we recognized impairment expense of $280.8 million associated with long-lived assets (refer to Note 7 for additional details). We did not record any impairments in 2019.
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. 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.
We performed a quantitative assessment as of October 1, 2020 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 2020 as the fair value far exceeded the 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. During the reporting period, the Covid-19 pandemic affected global markets and commodity prices due to continued economic uncertainty. As a result, our market capitalization decreased below the book value of our book equity for a portion of the reporting period and as of December 31, 2020 we identified an indicator of impairment. We performed our goodwill impairment assessment on October 1, 2020 for our refinery services reporting unit (which is our only reporting unit with goodwill) and concluded that the fair value exceeded the carrying value, thus no impairment was recorded. There were no changes in the market factors and estimates used to determine our fair value between October 1, 2020 and December 31, 2020 that would indicate that the results of our assessment would result in a different conclusion for our refinery services segment. Additionally, we performed our assessment of long-lived assets impairment as of December 31, 2020 and noted no additional impairments to the ones discussed above regarding our rail logistics assets in the second quarter of 2020. As a result of our analyses, no impairment of goodwill was recorded during 2020.
For additional information regarding our goodwill, see Note 9 to our Consolidated Financial Statements in Item 8.
Equity Compensation Plan Accrual
Our 2010 Long-Term Incentive Plan provides for grantees, which may include key employees and directors, to receive cash at the vesting of the phantom units equal to the average of the closing market price of our common units for the twenty trading days prior to the vesting date. Our phantom units outstanding at December 31, 2020 under this plan are comprised of service-based awards granted to our directors. At December 31, 2020, we had 165,662 phantom units outstanding and recorded a credit of $1.0 million during 2020. The liability recorded for phantom units is expected to fluctuate with the market price of our common units. At the date of vesting, any difference between the estimates recorded and the actual cash paid to the grantee will be charged to expense.
See Note 16 to our Consolidated Financial Statements in Item 8 for further discussion regarding our equity compensation plans.
Fair Value of Derivatives
The fair value of a derivative at a particular period end does not reflect the end results of a particular transaction, and will most likely not reflect the gain or loss at the conclusion of a transaction. We reflect estimates for these items 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
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traded, the estimates we use are based on indicative broker quotations or an internal valuation model. Our valuation models utilize market observable inputs such as price, volatility, correlation and other factors and may not be reflective of the price at which they can be settled due to the lack of a liquid market.
We also have embedded derivatives in our Class A Convertible Preferred Units that are accounted for as liabilities at fair value in our Consolidated Balance Sheet as of December 31, 2020. Derivatives related to the embedded derivatives in our Class A Convertible Preferred Units are valued using a model that contains inputs, including our common unit price, 30-year U.S. Treasury rates, default probabilities and timing estimates, which involve management judgment.
Liability and Contingency Accruals
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.
At December 31, 2020, we were not aware of any contingencies or liabilities that would have a material effect on our financial position, results of operations or cash flows.
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 year ended December 31, 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. As permitted by the amendment, we have early adopted the amendment and 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 for further details.
We have adopted guidance under ASC Topic 606, Revenue from Contracts with Customers, and all related ASUs (collectively "ASC 606") as of January 1, 2018 utilizing the modified retrospective method of adoption. Refer to Note 3 for further details.
In March 2017, the FASB issued ASU 2017-07, Compensation-Retirement Benefits (Topic 715). ASU 2017-07 requires employers to separate the service cost component from the other components of net benefit cost in the period. The new standard requires the other components of net benefit costs (excluding service costs), be reclassified to "Other expense" from "General and administrative." We adopted this standard as of January 1, 2018. This standard is applied retrospectively. The effect was not material to our financial statements for any of the annual periods presented.
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
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interim periods therein, beginning after December 15, 2019. We elected to early adopt this standard as of January 1, 2017. See Note 9 for further information.
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Item 7a. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to various market risks, primarily related to volatility in crude oil and petroleum products prices, soda ash prices, NaHS and NaOH prices, natural gas prices and interest rates. Our policy is to purchase only commodity products for which we have a market, and to structure our sales and purchase contracts so that price fluctuations for those products do not materially affect the Segment Margin we receive. We do not acquire and hold futures contracts or other derivative products for the purpose of speculating on price changes.
Our primary price risk relates to the effect of crude oil and petroleum products price fluctuations on our inventories and the fluctuations each month in grade and location differentials and their effect on future contractual commitments. Our risk management policies are designed to monitor our physical volumes, grades and delivery schedules to ensure our hedging activities address the market risks that are inherent in our gathering and marketing activities.
We utilize NYMEX commodity based futures contracts and option contracts to hedge our exposure to these market price fluctuations as needed. All of our open commodity price risk derivatives at December 31, 2020 were categorized as non-trading. On December 31, 2020 we had entered into NYMEX future contracts that will settle between February and May 2021 and NYMEX options contracts that settled during January 2021.
Our Alkali Business relies on natural gas to generate heat and power for operations. We use a combination of commodity price swap contracts and future purchase contracts to manage our exposure to fluctuations in natural gas prices. The swap contracts fix the basis differential between NYMEX Henry Hub and NW Rocky Mountain posted prices. As of December 31, 2020 we had entered into NYMEX future contracts and over the counter swap contracts that will settle between January and June 2021.
This accounting treatment is discussed further in Note 18 to our Consolidated Financial Statements. We believe our hedging activities have been successful in helping to mitigate these risks.
The table below presents information about our open commodity derivative contracts at December 31, 2020. Notional amounts in barrels or gallons, 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 gallons multiplied by the December 31, 2020 quoted market prices. All of the hedge positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the table below.
Futures and Swap Contracts
Sell (Short) Contracts:
Buy (Long) Contracts:
Option Contracts
Written Contracts:
Purchased Contracts:
We manage our risks of volatility in NaOH prices by indexing prices for the sale of NaHS to the market price for NaOH in most of our contracts. Given the competitive advantages associated with our naturally produced soda ash as
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previously discussed (relative to that which is synthetically produced), we believe this somewhat mitigates market risk within our Alkali Business.
We are also exposed to market risks due to the floating interest rates on our 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, 2020, we had $643.7 million of debt outstanding under our credit facility. Due to the significant decline in the LIBOR rate during 2020, a 10% change in LIBOR would have resulted in an immaterial impact to net income(loss) for the year ended December 31, 2020.
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 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.
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, 2020. 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, 2020, 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, 2020. 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 &
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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 approximately 10.8% of our Class A Common Units and 77.0% of our Class B Common Units, for a combined ownership percentage of 10.8% 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 directors of our board of directors, will facilitate teamwork and communication between the non-management directors and
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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 and compliance with legal and regulatory requirements and our risk management policy relating to our hedging program. The governance, compensation and business development committee assists our board of directors with risk management relating to our compensation policies and programs.
Our board of directors believes that it is important to align (when practical) the interests of the members of our board of directors and certain of our officers with the interests of our long-term stakeholders. Our board of directors has adopted certain policies to further promote that alignment of interests. For example, among other things, our policies prohibit our directors and officers from (i) buying, selling or engaging in transactions with respect to our common units while they are aware of material non-public information and (ii) engaging in short sales of our securities. Certain of our directors and/or officers own substantial amounts of our units, some of which are pledged, including being held in broker margin accounts. See Item 12. "Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters."
Audit Committee
The audit committee of our board of directors generally oversees our accounting policies and financial reporting and the audit of our financial statements. The audit committee assists our board of directors in its oversight of the quality and integrity of our financial statements and our compliance with legal and regulatory requirements. Our independent registered public accounting firm is given unrestricted access to the audit committee. Our board of directors has determined that the members of the audit committee meet the independence and experience standards established by NYSE and the Securities Exchange Act of 1934, as amended. In accordance with the NYSE rules and the Securities Exchange Act of 1934, as amended, our board of directors has named three of its members to serve on the audit committee—Sharilyn S. Gasaway, Conrad P. Albert and Jack T. Taylor. Ms. Gasaway is the chairperson. Our board of directors believes that Ms. Gasaway and Mr. Taylor qualify
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as audit committee financial experts as such term is used in the rules and regulations of the SEC. The charter of the audit committee is available on our website (www.genesisenergy.com) free of charge. Each member of the audit committee is an independent director under NYSE rules.
Governance, Compensation and Business Development Committee
The governance, compensation and business development committee, or G&C Committee, of our board of directors generally (i) monitors compliance with corporate governance guidelines, (ii) reviews and makes recommendations regarding board and committee composition, structure, size, compensation and related matters, and (iii) oversees compensation plans and compensation decisions for our employees. All the members of our board of directors, other than our CEO, serve as members of the G&C Committee. Mr. Jastrow is the chairperson. The charter of the G&C Committee is available on our website (www.genesisenergy.com) free of charge.
Conflicts Committee
To the extent requested by our board of directors, a conflicts committee of our board of directors would be appointed to review specific matters in connection with the resolution of conflicts of interest and potential conflicts of interest between any of our affiliates and us. If a specific review is requested by our board of directors, our conflicts committee would be formed by our Board and would be comprised solely of independent directors. See Item 13. “Certain Relationships and Related Transactions, and Director Independence—Review or Special Approval of Material Transactions with Related Persons.”
Executive Sessions of Non-Management Directors
Our board of directors holds executive sessions in which non-management directors meet without any members of management present in connection with regular board meetings. The purpose of these executive sessions is to promote open and candid discussion among the non-management directors. Mr. Jastrow, as the lead independent director, serves as the presiding director at those executive sessions. In accordance with NYSE rules, interested parties can communicate directly with non-management directors by mail in care of the General Counsel and Secretary or in care of the chairperson of the audit committee at 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 (800) 826-6762.
Directors and Executive Officers
Set forth below is certain information concerning our directors and executive officers, effective as of March 1, 2021.
Name Age Position
Grant E. Sims 65 Director, Chairman of the Board, and Chief Executive Officer
Conrad P. Albert 74 Director
James E. Davison 83 Director
James E. Davison, Jr. 54 Director
Sharilyn S. Gasaway 52 Director
Kenneth M. Jastrow II 73 Director
Jack T. Taylor 69 Director
Robert V. Deere 66 Chief Financial Officer
Edward T. Flynn 62 Executive Vice President
Richard R. Alexander 45 Vice President
Karen N. Pape 62 Senior Vice President and Controller
Kristen O. Jesulaitis 51 General Counsel
William S. Goloway 60 Vice President
Garland G. Gaspard 66 Senior Vice President
Chad A. Landry 57 Vice President
Ryan S. Sims 37 Senior Vice President
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Grant E. Sims has served as a director and Chief Executive Officer of our general partner since August 2006 and Chairman of the Board of our general partner since October 2012. Mr. Sims was affiliated with Leviathan Gas Pipeline Partners, LP from 1992 to 1999, serving as the Chief Executive Officer and a director beginning in 1993 until he left to pursue personal interests, including investments. Leviathan (subsequently known as El Paso Energy Partners, L.P. and then GulfTerra Energy Partners, L.P.) was a NYSE listed 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 two other public companies, JB Hunt Transport Services, Inc. and Waddell and Reed Financial, Inc., serving on the audit committee of each company. Additionally, Ms. Gasaway serves on the compensation and nominating committees of JB Hunt and the nominating and corporate governance committee of Waddell and Reed. Ms. Gasaway provides our board of directors valuable business experience, risk management and financial expertise, including an understanding of the accounting, compliance and financial matters that we address on a regular basis.
Kenneth M. Jastrow II has served as a director of our general partner since March 2010 and serves as our lead independent director and the chairperson of the G&C Committee. Mr. Jastrow served as Chairman and Chief Executive Officer of Temple-Inland, Inc., a manufacturing company and the former parent of Forestar Group, from 2000 to 2007. Prior to that, Mr. Jastrow served in various roles at Temple-Inland, including President and Chief Operating Officer, Group Vice President and Chief Financial Officer. Mr. Jastrow is a director of MGIC Investment Corporation 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.
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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.
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, objectives and philosophy with respect to our Named Executive Officers (“NEOs”), for the fiscal year ended December 31, 2020.
Compensation Discussion and Analysis
Named Executive Officers
Our NEOs for 2020 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 BDO USA, LLP, or BDO, as its independent compensation adviser for 2020. 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 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 2020, the G&C Committee engaged BDO, 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 BDO pursuant to current exchange listing requirements and SEC guidance and concluded that no conflict of interest exists that would prevent BDO from serving as an independent consultant to the G&C Committee.
At the request of the G&C Committee, BDO 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. BDO 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 2020 consisted of the following 17 companies in the energy industry: Antero Midstream, Calumet Specialty Products Partners, Crestwood Energy Partners, DCP Midstream Partners, Enable Midstream Partners, EnLink Midstream, Magellan Midstream Partners, NGL Energy Partners, NuStar Energy, Plains All American Pipeline, Summit Energy Partners, Sunoco LP, Delek US Holdings, Hi-Crush Inc., HollyFrontier Corp, Targa Resources Corp, and US Silica Holdings, Inc. 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 BDO 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 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 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 performance.
We pay base salaries at levels that we feel are appropriate for the skills and qualities of the individual NEOs based on their past performance, current scope of responsibilities and future potential. The incentive-based components of each NEO’s compensation include annual cash bonus opportunities and participation in the long-term incentive program. The annual cash bonus rewards incremental operational and financial achievements required to meet investor expectations in the short-term while the long-term component focuses rewards to the long-term stability of the enterprise. Both incentive components are generally linked to base salary and are consistent in general with our understanding of market practice and with our judgment regarding each individual’s role in the organization.
As described in more detail below, we believe that the combination of base salaries, cash bonuses and long-term cash-based incentive plans provide an appropriate balance of short and long-term incentives, and alignment of the incentives for our executives, including our NEOs, with the interests of our common unitholders.
The amount of compensation contingent on performance is a significant percentage of total compensation, therefore ensuring that business decisions and actions lead to the long-term growth and sustainability of the organization. Our bonus plan (including annual and retention bonuses) is driven by the generation of Available Cash before Reserves (as defined in Item. 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations-Financial Measures") (which is an important metric of value for our unitholders) and our safety record with the goal of retention of key employees and NEOs. Our long-term incentive plan is also linked to our generation of Available Cash before Reserves and safety record, as well as the partnership's leverage ratio as defined in its senior-secured credit facility agreement.
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Elements of Our Compensation Program and Compensation Decisions for 2020
The primary elements of our compensation program are a combination of annual cash and long-term incentive-based compensation. For the year ended December 31, 2020, the elements of our compensation program for the NEOs consisted of an annual base salary and discretionary annual cash and bonus awards.
Additionally, in order to attract qualified executive personnel, we may make one-time new-hire awards of equity.
Base Salaries
We believe that base salaries should provide a fixed level of competitive pay that reflects the executive officer’s primary duties and responsibilities, and which provides a foundation for incentive opportunities and benefit levels. As discussed above, the base salaries of our NEOs are reviewed annually by the G&C Committee, taking into account recommendations from our CEO regarding NEOs other than himself. We pay base salaries at a level that we feel is appropriate for the skills and qualities of the individual NEOs based on their past performance, current scope of responsibilities and future potential. Base salaries may be adjusted to achieve what is determined to be a reasonably competitive level or to reflect promotions, the assignment of additional responsibilities, individual performance or company performance. Salaries are also periodically adjusted based on analysis of peer group practices as described above.
In April 2020, the G&C Committee reviewed the assessments of market levels of compensation developed by BDO in conjunction with a discussion of individual performance and responsibilities. As a result of and taking into account current market conditions, the 2020 base salaries of all NEOs remained the same from 2019, with the exception of Ms. Jesulaitis's base salary, which increased to $400,000 in 2020 from $375,000 in 2019 to more closely align her compensation with the increased responsibilities of her role and the significant contributions she makes to the partnership.
Bonuses
Our NEOs typically participate in a bonus program, or the Bonus Plan, in which substantially all company employees participate. As designed by the G&C Committee, each NEO has an annual bonus target based on a stated percentage of his or her base salary. The targeted amount for the NEOs is established based on the analysis of market practices of the peer group and consideration of the level of salary and targeted long-term incentives for each NEO. Based on the G&C Committee's subjective review of 2020 operational and financial performance, in the context of total NEO compensation, no performance based awards were earned by NEOs and it was determined by the G&C Committee that each NEO would instead be
considered for a retention bonus for 2020, as further discussed below.