GENESIS ENERGY, L.P. Introduction
We are a growth-oriented master limited partnership formed inDelaware in 1996. Our common units are traded on theNew 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 theGulf of Mexico and theGulf 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
Our offshoreGulf 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 theU.S. - theGulf of Mexico -, a producing region representing approximately 15% of the crude oil production in theU.S. during 2020. Our onshore-based refinery-centric operations located primarily in theGulf Coast region of theU.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 inthe United States ,Canada , the European Community, the European FreeTrade Area and theSouth 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 54 -------------------------------------------------------------------------------- Table of Contents Overview of 2020 Results We reported Net Loss Attributable toGenesis Energy, L.P. of$416.7 million in 2020 compared to Net Income Attributable toGenesis Energy, L.P. of$96.0 million in 2019. Net Loss Attributable toGenesis 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
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
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 onFebruary 12, 2021 to unitholders holders of record at the close of businessJanuary 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 ourGranger 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; 55 -------------------------------------------------------------------------------- Table of Contents •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 OnSeptember 23, 2019 , we announced theGranger 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) inAlkali Holdings . The proceeds we receive from GSO will fund up to 100% of the anticipated cost of theGranger Optimization Project .The Alkali Holdings preferred unitholders receive PIK distributions in lieu of cash distributions during the anticipated construction period. OnApril 14, 2020 , we entered into an amendment to our agreements with GSO to, among other things, extend the construction timeline of theGranger 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 1,750Alkali 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) inAlkali Holdings . As ofDecember 31, 2020 , there are 141,249Alkali Holdings preferred units outstanding. CO2 Assets OnOctober 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 EastJackson 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 OnMarch 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. OnJuly 24, 2020 , we further amended our credit agreement. The amendment increases our Consolidated Leverage Ratio from 5.50X to 5.75X fromSeptember 30, 2020 throughMarch 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 fromSeptember 30, 2020 throughMarch 31, 2021 , after which time it reverts back to 3.0X for the remaining term of the agreement. Senior Unsecured Note Transactions OnJanuary 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. OnJanuary 17, 2020 we called for redemption the remaining$222.1 million of our 2022 Notes, and they were redeemed onFebruary 16, 2020 . OnDecember 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. OnJanuary 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 endedDecember 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. 56 -------------------------------------------------------------------------------- Table of Contents Covid-19 and Market Update InMarch 2020 , theWorld Health Organization categorized Covid-19 as a pandemic, and the President ofthe 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 theDepartment 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 theOrganization of the Petroleum Exporting Countries (OPEC) and other oil exporting nations beginning in earlyMarch 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 ofthe 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 inSouth 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 theGulf 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. 57 -------------------------------------------------------------------------------- Table of Contents Revenues, Costs and Expenses Our revenues for the year endedDecember 31, 2020 decreased$656.2 million , or 26%, from the year endedDecember 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 theGulf 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 theNew 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 offshoreGulf 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 theGulf Coast region of theU.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 theGulf Coast , unlike the lighter crude oil and condensates produced from 58 -------------------------------------------------------------------------------- Table of Contents 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 offshoreGulf 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,
2020 2019 2018
(in thousands)
Offshore pipeline transportation 270,078 320,023 285,014
Sodium minerals and sulfur services 130,083 223,908 260,488
Onshore facilities and transportation 147,254 111,412 119,918
Marine transportation 60,058 57,919 47,338
Total Segment Margin $ 607,473 $ 713,262 $ 712,758
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Year Ended
Operating results and volumetric data for our offshore pipeline transportation
segment are presented below:
Year Ended December 31,
2020 2019
(in thousands)
Offshore crude oil pipeline revenue, excluding non-cash revenues $ 221,508 $ 259,899 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)
Distributions from equity investments (1) 79,241 75,577
Offshore pipeline transportation Segment Margin $ 270,078 $ 320,023
Volumetric Data 100% basis:
Crude oil pipelines (average barrels/day unless otherwise noted):
CHOPS (2) 133,977 234,301
Poseidon(2) 290,600 264,931
Odyssey 119,145 144,785
GOPL (3) 4,154 8,845
Total crude oil offshore pipelines 547,876 652,862
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):
CHOPS (2) 133,977 234,301
Poseidon (2) 185,984 169,556
Odyssey 34,552 41,988
GOPL (3) 4,154 8,845
Total crude oil offshore pipelines 358,667 454,690
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,
2020 2019
Volumes sold :
NaHS volumes (Dry short tons "DST") 107,428 126,443
Soda Ash volumes (short tons sold) 2,781,926 3,590,680
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
NaOH (caustic soda) revenues 33,731 41,365
Revenues associated with our Alkali Business 645,582 836,125
Other revenues 2,506 5,001
Total segment revenues, excluding non-cash revenues (1) $
797,616
Sodium minerals and sulfur services operating costs, excluding non-cash items (1)
(667,533) (807,395)
Segment Margin (in thousands) $
130,083
Average index price for NaOH per DST (2) $
674
(1)Totals are for external revenues and costs prior to intercompany elimination upon consolidation. (2)Source: IHS Chemical. Sodium minerals and sulfur services Segment Margin for 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 inDecember 2019 andJanuary 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 inSouth America as a result of customer shut-ins, primarily inPeru , due to the spread of 61 -------------------------------------------------------------------------------- Table of Contents Covid-19. This decline was coupled with lower demand from certain of our domestic mining and pulp and paper customers throughout the year endedDecember 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 theUnited 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 ofDecember 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. ManyU.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. 62
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Operating results for our onshore facilities and transportation segment were
as follows:
Year Ended December 31,
2020 2019
(in thousands)
Gathering, marketing, and logistics revenue $ 439,338 $ 747,619
Crude oil and CO2 pipeline tariffs and revenues 58,249 69,418
Distributions from unrestricted subsidiaries not included in income(1)
70,490 8,421
Crude oil and products costs, excluding unrealized gains and losses from derivative transactions
(371,738) (637,629)
Operating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses
(67,710) (76,025) Other 18,625 (392) Segment Margin$ 147,254 $ 111,412 Volumetric Data (average barrels/day unless otherwise noted): Onshore crude oil pipelines: Texas 62,213 59,435 Jay 8,443 10,461 Mississippi 5,638 5,994 Louisiana (2) 90,319 117,130 Onshore crude oil pipelines total 166,613 193,020 CO2 pipeline (average Mcf/day): Free State (3) 101,845 97,912 Total crude oil and petroleum products sales 27,073 31,681 Rail unload volumes (4) 32,174 79,530 (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 endedDecember 31, 2020 and 2019 include 26,708 and 51,267 barrels per day respectively of intermediate refined products associated with ourPort of Baton Rouge Terminal pipelines. (3)The volumes presented for 2020 represent the average Mcf/day throughOctober 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 inLouisiana , including ourBaton Rouge corridor assets and ourRaceland rail facility. During 2020, as a result of lower crude oil prices and the tightening of the differential of Western Canadian Select (WCS) to theGulf 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$10 million associated with the resolution of a crude oil supply agreement. 63 -------------------------------------------------------------------------------- Table of Contents Marine Transportation Segment Within our marine transportation segment, we own a fleet of 91 barges (82 inland and 9 offshore) with a combined transportation capacity of 3.2 million barrels, 42 push/tow boats (33 inland and 9 offshore), and a 330,000 barrel ocean going tanker, the M/T American Phoenix. Operating results for our marine transportation segment were as follows: Year Ended December 31, 2020 2019 Revenues (in thousands): Inland freight revenues$ 91,036 $ 104,756 Offshore freight revenues 81,158 77,630 Other rebill revenues (1) 38,064 53,259 Total segment revenues$ 210,258 $ 235,645
Operating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses
$ 150,200 $ 177,726 Segment Margin (in thousands)$ 60,058 $ 57,919 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 andGulf 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 onSeptember 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 EndedDecember 31, 2020 2019
(in thousands) General and administrative expenses not separately identified below: Corporate
$ 53,335 $ 40,718 Segment 4,088 4,266 Long-term incentive based compensation plan expense (1,420) 3,948
Third party costs related to business development activities and growth projects
917 3,755
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,
2020 2019
(in thousands)
Depreciation and depletion expense $ 279,605 $ 300,213
Amortization expense 15,717 18,704
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 N ote 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,
2020 2019
(in thousands) Interest expense, senior secured credit facility (including commitment fees)
$ 38,842 $ 54,165 Interest expense, senior unsecured notes 163,330 158,188 Amortization of debt issuance costs and discount 9,499 10,766 Capitalized interest (1,892) (3,679) Net interest expense$ 209,779 $ 219,440 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. OnJanuary 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% onJanuary 15, 2020 through a tender offer and we redeemed the remaining$222.1 million of our 2022 Notes onFebruary 16, 2020 . OnDecember 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 endedDecember 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 endedDecember 31, 2019 . Those amounts are included in other income (expense) in the Consolidated Statement of Operations. 65
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A discussion of the operating results for the year endedDecember 31, 2019 compared with the year endedDecember 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 theSEC onFebruary 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 inthe 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. 66 -------------------------------------------------------------------------------- Table of Contents 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 Ended December 31, 2020 2019 I. Applicable to all Non-GAAP Measures Differences in timing of cash receipts for certain contractual arrangements(1)$ 40,848 $ (8,478) Distributions from unrestricted subsidiaries not included in income(2) 70,490 8,421 Certain non-cash items: Unrealized loss on derivative transactions excluding fair value hedges, net of changes in inventory value 1,189 10,926 Loss on debt extinguishment(3) 31,730 - Adjustment regarding equity investees(4) 17,042 20,847 Other 3,465 3,651 Sub-total Select Items, net(5) 164,764 35,367 II. Applicable only to Available Cash before Reserves Certain transaction costs(6) 937 3,755 Equity compensation adjustments - (137) Other (454) 3,168 Total Select Items, net(7)$ 165,247 $ 42,153 (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 toMaintenance 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. 67
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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 sinceDecember 31, 2013 . 68
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Available Cash before Reserves for the years endedDecember 31, 2020 and 2019 was as follows: Year Ended December 31, 2020 2019 (in thousands) Net income (loss) attributable to Genesis Energy, L.P.$ (416,678) $ 95,999 Income Tax expense 1,327 655 Depreciation, depletion, amortization, and accretion 302,602 308,115 Impairment expense 280,826 - Loss on sale of assets 22,045 - Plus (minus) Select Items, net 165,247 42,153 Maintenance capital utilized (40,833) (26,875) Cash tax expense (650) (590) Distributions to preferred unitholders (74,736) (62,190)
Redeemable noncontrolling interest redemption value adjustments(1)
16,113 2,233
Available Cash before Reserves $ 255,263 $ 359,500 (1) Includes distributions paid in kind and accretion adjustments on the redemption feature.
Liquidity and Capital Resources General As ofDecember 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. AtDecember 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 ofMay 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
AtDecember 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, 69 -------------------------------------------------------------------------------- Table of Contents$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. 2023 Notes(1) 2024 Notes 2025 Notes 2026 Notes 2027 Notes 2028 Notes May 15, Redemption right beginning on 2018 June 15, 2019 October 1, 2020 February 15, 2021 January 15, 2024 February 1, 2023 Redemption of up to 35% of the principal amount of notes with the proceeds of an equity offering permitted May 15, February 15, prior to 2018 June 15, 2019 October 1, 2020 2021 January 15, 2024 February 1, 2023
(1) Refer to Note 23 for discussion surrounding the redemption of our remaining outstanding 2023 Notes during the first quarter of 2021.
InJanuary 2020 , we issued$750 million in aggregate principal amount of our 2028 Notes. Interest payments are dueFebruary 1 andAugust 1 of each year with the initial interest payment dueAugust 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. OnJanuary 17, 2020 we called for redemption the remaining balance of our 2022 Notes with a redemption date ofFebruary 16, 2020 . InDecember 2020 , we issued$750 million in aggregate principal amount of our 2027 Notes. Interest payments are dueJanuary 15 andJuly 15 of each year with the initial interest payment due onJuly 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. InJanuary 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 endedDecember 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
OnSeptember 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 toMarch 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 afterMarch 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
OnSeptember 23, 2019 , we, through a subsidiary,Alkali Holdings , entered into an amended and restated Limited Liability Company Agreement ofAlkali Holdings (the "LLC Agreement") and a Securities Purchase Agreement (the 70 -------------------------------------------------------------------------------- Table of Contents "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) inAlkali Holdings .Alkali Holdings will use the net proceeds from the preferred units to fund up to 100% of the anticipated cost of theGranger Optimization Project . OnApril 14, 2020 , we entered into an amendment to our agreements with GSO to, among other things, extend the construction timeline of theGranger Optimization Project by one year, which we currently anticipate completing near the end of 2023. In consideration for the amendment, we issued 1,750Alkali 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) inAlkali Holdings . As ofDecember 31, 2020 , there are 141,249Alkali 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 asone 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 theSeptember 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 ofAlkali 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 byAlkali Holdings . A triggering event would occur ifAlkali 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 ofAlkali Holdings and, as applicable, the Partnership. If such an event were to occur, the preferred units would rank senior toAlkali Holdings common units and any class or series of equity ofAlkali 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 ofAlkali 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 ofAlkali 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 theSEC . 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 inApril 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, 71 -------------------------------------------------------------------------------- Table of Contents 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$382.3 million for 2020 and 2019, respectively. The decrease in operating cash flow for 2020 compared to 2019 was primarily due to lower reported segment margin during 2020. Capital Expenditures and Distributions Paid to Our Unitholders We use cash primarily for our operating expenses, working capital needs, debt service, acquisition activities, internal growth projects and distributions we pay to our common and preferred unitholders. We finance maintenance capital expenditures and smaller internal growth projects and distributions primarily with cash generated by our operations. We have historically funded material growth capital projects (including acquisitions and internal growth projects) with borrowings under our credit facility, equity issuances (common and preferred units), and/or the issuance of senior unsecured notes. 72 -------------------------------------------------------------------------------- Table of Contents Capital Expenditures and Business and Asset Acquisitions The following table summarizes our expenditures for fixed assets, business and other asset acquisitions in the periods indicated: Years Ended December 31, 2020 2019 2018 (in thousands) Capital expenditures for fixed and intangible assets: Maintenance capital expenditures: Offshore pipeline transportation assets$ 8,715 $ 16,848 $ 4,202 Sodium mineral and sulfur services assets 43,744 42,065 55,377 Marine transportation assets 31,357 40,820 18,308 Onshore facilities and transportation assets 3,644 2,966 3,340 Information technology systems 383 1,197 72 Total maintenance capital expenditures 87,843 103,896 81,299 Growth capital expenditures: Offshore pipeline transportation assets$ 4,608 $ 961$ 501 Sodium minerals and sulfur services assets 51,767 65,772 19,335 Marine transportation assets - - 12,560 Onshore facilities and transportation assets 489 3,610 47,770 Information technology systems 6,331 2,301 2,704 Total growth capital expenditures 63,195 72,644 82,870
Total capital expenditures for fixed and intangible assets 151,038
176,540 164,169
Capital expenditures related to equity investees - - 3,018
Total capital expenditures $ 151,038 $ 176,540 $ 167,187
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
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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).
Per Common
Unit Total Per Preferred Total
Distribution For Date Paid Amount Amount Unit Amount (1) Amount (1)
2018
4th Quarter February 14,
2019 $ 0.5500 $ 67,419
2019
1st Quarter May 15, 2019 $ 0.5500 $ 67,419 $ 0.2458 $ 6,138
2nd Quarter August 14,
2019 $ 0.5500 $ 67,419 $ 0.7374 $ 18,684
3rd Quarter November 14,
2019 $ 0.5500 $ 67,419 $ 0.7374 $ 18,684
4th Quarter February 14,
2020 $ 0.5500 $ 67,419 $ 0.7374 $ 18,684
2020
1st Quarter May 15, 2020 $ 0.1500 $ 18,387 $ 0.7374 $ 18,684
2nd Quarter August 14,
2020 $ 0.1500 $ 18,387 $ 0.7374 $ 18,684
3rd Quarter November 13,
2020 $ 0.1500 $ 18,387 $ 0.7374 $ 18,684
4th Quarter February 12,
2021 (2) $ 0.1500 $ 18,387 $ 0.7374 $ 18,684
(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 byGenesis Energy, L.P. andGenesis Energy Finance Corporation are fully and unconditionally guaranteed jointly and severally by all ofGenesis 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 byGenesis Free State Pipeline, LLC were sold onOctober 30, 2020 and the ownership ofGenesis NEJD Pipeline LLC's pipeline was transferred onOctober 30, 2020 . See Note 7 for additional information regarding our asset sales and divestitures.Genesis NEJD Pipeline, LLC is 100% owned byGenesis Energy, L.P. The remaining non-Guarantor Subsidiaries are owned byGenesis 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 ofGenesis Energy, L.P. ,Genesis Energy Finance Corporation or the Guarantor Subsidiaries, and the liabilities of our unrestricted subsidiaries do not constitute obligations ofGenesis Energy, L.P. ,Genesis Energy Finance Corporation or the Guarantor Subsidiaries except, in the case ofAlkali Holdings andGenesis Energy, L.P. , to the extent agreed to in the services agreement between the Partnership andAlkali Holdings dated as ofSeptember 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 toGenesis Energy, L.P.
The rights of holders of our senior unsecured notes against the Guarantor
Subsidiaries may be limited under the
The following is the summarized financial information forGenesis 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 SheetsGenesis Energy, L.P.
and Guarantor Subsidiaries
December 31, 2020 December 31, 2019
ASSETS:
Current assets $ 313,328 $ 323,492
Fixed assets, net 3,115,492 3,538,450
Non-current assets 861,230 951,276
LIABILITIES AND CAPITAL:(1)
Current liabilities 266,688 292,941
Non-current liabilities 3,710,044 3,738,816
Class A Convertible Preferred Units 790,115 790,115
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Statements of Operations Genesis Energy, L.P. and Guarantor Subsidiaries
Year Ended Year Ended
December 31, 2020 December 31. 2019
Revenues $ 1,156,428 $ 1,617,170
Operating costs 1,421,674 1,454,040
Operating income (loss) (265,246) 163,130
Income (loss) before income taxes (408,717) 566
Net loss(1) (409,951) (122)
Less: Accumulated distributions to Class A
Convertible Preferred Units (74,736) (74,467)
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 toGenesis Energy, L.P. and the Guarantor Subsidiaries from the non-Guarantor Subsidiaries as ofDecember 31, 2020 andDecember 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 atDecember 31, 2020 .
Payments Due by Period
Commercial Cash Obligations and Less than More than
Commitments one year 1 - 3 years 3 - 5 Years 5 years Total
(in thousands)
Contractual Obligations:
Long-term debt, net of debt issuance
costs (1) $ 80,355 $ 643,700
226,366 396,576 346,455 189,668 1,159,065
Operating lease obligations 33,197 53,211 40,310 143,125 269,843
Unconditional purchase obligations
(3) 119,727 8,100 8,100 4,050 139,977
Capital expenditure commitments (4) 52,756 14,679 - - 67,435
Asset retirement obligations (5) 14,663 26,569 - 135,620 176,852
Total $ 527,064 $ 1,142,835 $ 1,262,232 $ 2,274,757 $ 5,206,888
(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
for
further details. InMarch 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 ofJanuary 1, 2018 . This standard is applied retrospectively. The effect was not material to our financial statements for any of the annual periods presented. InJanuary 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 79 -------------------------------------------------------------------------------- Table of Contents interim periods therein, beginning afterDecember 15, 2019 . We elected to early adopt this standard as of January 1, 2017. See Note 9 for further information. 80
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