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Cheniere EnergyTable of Contents UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 Form 10-K ☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2019 OR ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission file number 1-12295 GENESIS ENERGY, L.P. (Exact name of registrant as specified in its charter) Delaware (State or other jurisdiction of incorporation or organization) 919 Milam, Suite 2100, Houston , TX (Address of principal executive offices) 76-0513049 (I.R.S. Employer Identification No.) 77002 (Zip code) Registrant’s telephone number, including area code: (713) 860-2500 Securities registered pursuant to Section 12(b) of the Act: Title of Each Class Common Units Trading Symbol(s) GEL Name of Each Exchange on Which Registered NYSE Securities registered pursuant to Section 12(g) of the Act: NONE Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No o Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T(§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer," “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act. Large accelerated filer Non-accelerated filer x ☐ Accelerated filer Smaller reporting company Emerging growth company ☐ ☐ ☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2) of the Act). Yes ☐ No x The aggregate market value of the Class A common units held by non-affiliates of the Registrant on June 30, 2019 (the last business day of Registrant’s most recently completed second fiscal quarter) was approximately $2.3 billion based on $21.90 per unit, the closing price of the common units as reported on the NYSE. For purposes of this computation, all executive officers, directors and 10% owners of the registrant are deemed to be affiliates. Such a determination should not be deemed an admission that such executive officers, directors and 10% Table of Contents beneficial owners are affiliates. On February 27, 2020, the Registrant had 122,539,221 Class A Common Units and 39,997 Class B Common Units outstanding. Table of Contents GENESIS ENERGY, L.P. 2019 FORM 10-K ANNUAL REPORT Table of Contents Item 1 Business Item 1A. Risk Factors Item 1B. Unresolved Staff Comments Item 2. Item 3. Properties Legal Proceedings Item 4. Mine Safety Disclosures Part I Part II Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities Item 6. Selected Financial Data Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations Item 7A. Quantitative and Qualitative Disclosures About Market Risk Item 8. Item 9. Financial Statements and Supplementary Data Changes in and Disagreements With Accountants on Accounting and Financial Disclosure Item 9A. Controls and Procedures Item 9B. Other Information Item 10. Directors, Executive Officers and Corporate Governance Item 11. Executive Compensation Part III Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters Item 13. Certain Relationships and Related Transactions, and Director Independence Item 14. Principal Accountant Fees and Services Part IV Item 15. Exhibits and Financial Statement Schedules Item 16. Form 10-K Summary Page 5 32 49 49 49 50 51 52 54 76 77 77 77 79 79 84 95 96 97 98 103 2 Table of Contents Definitions Unless the context otherwise requires, references in this annual report to “Genesis Energy, L.P.,” “Genesis,” “we,” “our,” “us” or like terms refer to Genesis Energy, L.P. and its operating subsidiaries. As generally used within the energy industry and in this annual report, the identified terms have the following meanings: Bbl or Barrel: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to crude oil or other liquid hydrocarbons. Bbls/day: Barrels per day. Bcf: Billion cubic feet of gas. CO2: Carbon dioxide. DST: Dry short tons (2,000 pounds), a unit of weight measurement. FERC: Federal Energy Regulatory Commission. Gal: Gallon. MBbls: Thousand Bbls. MBbls/d: Thousand Bbls per day. Mcf: Thousand cubic feet of gas. mmBtu: One million British thermal units, an energy measurement. MMcf: Thousand Mcf. NaHS: (commonly pronounced as “nash”) Sodium hydrosulfide. NaOH or Caustic Soda: Sodium hydroxide. Natural gas liquid(s) or NGL(s): The combination of ethane, propane, normal butane, isobutane and natural gasolines that, when removed from natural gas, become liquid under various levels of higher pressure and lower temperature. Sour gas: Natural gas containing more than four parts per million of hydrogen sulfide. Wellhead: The point at which the hydrocarbons and water exit the ground. FORWARD-LOOKING INFORMATION The statements in this Annual Report on Form 10-K that are not historical information may be “forward looking statements” as defined under federal law. All statements, other than historical facts, included in this document that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as plans for growth of the business, future capital expenditures, competitive strengths, goals, references to future goals or intentions, estimated or projected future financial performance, and other such references are forward-looking statements, and historical performance is not necessarily indicative of future performance. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “could,” “plan,” “position,” “projection,” “strategy,” “should” or “will,” or the negative of those terms or other variations of them or by comparable terminology. In particular, statements, expressed or implied, concerning future actions, conditions or events or future operating results or the ability to generate sales, income or cash flow are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability or the ability of our affiliates to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include, among others: • demand for, the supply of, our assumptions about, changes in forecast data for, and price trends related to crude oil, liquid petroleum, natural gas, NaHS, soda ash,caustic soda and CO2, all of which may be affected by economic activity, capital expenditures by energy producers, weather, alternative energy sources, international events, conservation and technological advances; 3 Table of Contents • • • • • • • • • • • • • • • • • • • • • • • • our ability to successfully execute our business and financial strategies; the realized benefits of the preferred equity investment in Alkali Holdings (as defined below) by affiliates of GSO (as defined below) or our ability to comply with the GOP (as defined below) agreements and maintain control over and ownership of the Alkali Business; throughput levels and rates; changes in, or challenges to, our tariff rates; our ability to successfully identify and close strategic acquisitions on acceptable terms (including obtaining third- party consents and waivers of preferential rights), develop or construct infrastructure assets, make cost saving changes in operations and integrate acquired assets or businesses into our existing operations; service interruptions in our pipeline transportation systems, and processing operations; shutdowns or cutbacks at refineries, petrochemical plants, utilities, individual plants or other businesses for which we transport crude oil, petroleum, natural gas or other products or to whom we sell soda ash, petroleum or other products; risks inherent in marine transportation and vessel operation, including accidents and discharge of pollutants; changes in laws and regulations to which we are subject, including tax withholding issues, regulations regarding qualifying income, accounting pronouncements, and safety, environmental and employment laws and regulations; the effects of production declines resulting from a suspension of drilling in the Gulf of Mexico; planned capital expenditures and availability of capital resources to fund capital expenditures, and our ability to access the credit and capital markets to obtain financing on terms we deem acceptable; our inability to borrow or otherwise access funds needed for operations, expansions or capital expenditures as a result of our credit agreement and the indentures governing our notes, which contain various affirmative and negative covenants; loss of key personnel; cash from operations that we generate could decrease or fail to meet expectations, either of which could reduce our ability to pay quarterly cash distributions at the current level, pay our quarterly distribution on our preferred units, or to increase quarterly cash distributions in the future; an increase in the competition that our operations encounter; cost and availability of insurance; hazards and operating risks that may not be covered fully by insurance; our financial and commodity hedging arrangements, which may reduce our earnings, profitability and cash flow; changes in global economic conditions, including capital and credit markets conditions, inflation and interest rates; natural disasters, pandemics, epidemics, accidents or terrorism; changes in the financial condition of customers or counterparties; adverse rulings, judgments, or settlements in litigation or other legal or tax matters; the treatment of us as a corporation for federal income tax purposes or if we become subject to entity-level taxation for state tax purposes; and the potential that our internal controls may not be adequate, weaknesses may be discovered or remediation of any identified weaknesses may not be successful and the impact these could have on our unit price. You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risk factors described under “Risk Factors” discussed in Item 1A. These risks may also be specifically described in our Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and Form 8-K/A and other documents that we may file from time to time with the SEC. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information. 4 Table of Contents Item 1. Business General PART I We are a growth-oriented master limited partnership formed in Delaware in 1996. Our common units are traded on the New York Stock Exchange, or NYSE, under the ticker symbol “GEL.” We are (i) a provider of an integrated suite of midstream services - primarily transportation, storage, sulfur removal, blending, terminalling and processing - for a large area of the Gulf of Mexico and the Gulf Coast region of the crude oil and natural gas industry and (ii) one of the leading producers in the world of natural soda ash. A core part of our focus is in the midstream sector of the crude oil and natural gas industry in the Gulf of Mexico and the Gulf Coast region of the United States. We provide an integrated suite of services to refiners, crude oil and natural gas producers, and industrial and commercial enterprises and have a diverse portfolio of assets, including pipelines, offshore hub and junction platforms, refinery-related plants, storage tanks and terminals, railcars, rail unloading facilities, barges and other vessels, and trucks. Within our midstream business, we have two distinct, complementary types of operations- (i) our offshore Gulf of Mexico crude oil and natural gas pipeline transportation and handling operations, which focus on providing a suite of services primarily to integrated and large independent energy companies who make intensive capital investments (often in excess of billions of dollars) to develop numerous large-reservoir, long-lived crude oil and natural gas properties and (ii) our onshore- based refinery-centric operations located primarily in the Gulf Coast region of the U.S., which focus on providing a suite of services primarily to refiners, which includes our sulfur removal, transportation, storage, and other handling services. Our onshore-based operations occur upstream of, at, and downstream of refinery complexes. Upstream of refineries, we aggregate, purchase, gather and transport crude oil, which we sell to refiners. 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. In our offshore crude oil and natural gas pipeline transportation and handling operations, we provide services to one of the most active drilling and development regions in the U.S.- the Gulf of Mexico, a producing region representing approximately 16% of the crude oil production in the U.S. in 2019. The other core focus of our business is our trona and trona-based exploring, mining, processing, producing, marketing and selling business based in Wyoming (our “Alkali Business”). Our Alkali Business mines and processes trona from which it produces natural soda ash, also known as sodium carbonate (Na2CO3), a basic building block for a number of ubiquitous products, including flat glass, container glass, dry detergent and a variety of chemicals and other industrial products and has been operating for over 70 years. Our Alkali Business has a diverse customer base in the United States, Canada, the European Community, the European Free Trade Area and the South African Customs Union with many long-term relationships. Our Alkali Business has an estimated remaining reserve life (based on 2019 production) of over 100 years related to the seam currently being mined, which is disclosed in further detail in the Reporting of Ore and Mineral Reserve section of Item 1. Our existing leases have other seams available to us for future mining that would increase our available reserve quantities. Our operations include, among others, the following diversified businesses, each of which is one of the leaders in its market, has a long commercial life and has significant barriers to entry: • • • • one of the largest pipeline networks (based on throughput capacity) in the Deepwater area of the Gulf of Mexico, an area that produced approximately 16% of the oil produced in the U.S. in 2019, one of the largest providers of crude oil and petroleum transportation, storage, and other handling services for large, complex refineries in Baton Rouge, Louisiana and Baytown, Texas, both of which have been operational for approximately 100 years. one of the leading producers (based on tons produced) of natural soda ash in the world, and the largest producer and marketer (based on tons produced), we believe, of sodium hydrosulfide (or NaHS, pronounced "nash") in North and South America. We conduct our operations and own our operating assets through our subsidiaries and joint ventures. Our general partner, Genesis Energy, LLC, a wholly-owned subsidiary that owns a non-economic general partner interest in us, has sole responsibility for conducting our business and managing our operations. Our outstanding common units (including our Class B common units), and our outstanding Class A convertible preferred units, representing limited partner interests, constitute all of the economic equity interests in us. 5 Table of Contents 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. For additional information, please review the section entitled "Financial Measures." Offshore Pipeline Transportation Segment We conduct our offshore crude oil and natural gas pipeline transportation and handling operations through our offshore pipeline transportation segment, which focuses on providing a suite of services to integrated and large independent energy companies who make intensive capital investments (often in excess of billions of dollars) to develop numerous large-reservoir, long-lived crude oil and natural gas properties in the Gulf of Mexico, primarily offshore Texas, Louisiana, Mississippi and Alabama. This segment provides services to one of the most active drilling and development regions in the U.S.—the Gulf of Mexico— a producing region representing approximately 16% of the crude oil production in the U.S. in 2019. Even though those large-reservoir properties and the related pipelines and other infrastructure needed to develop them are capital intensive, we believe they are generally much less sensitive to short-term commodity price volatility, particularly once a project has been sanctioned. Due to the size and scope of these activities, our customers are predominantly large integrated oil companies and large independent crude oil producers. We own interests in various offshore crude oil and natural gas pipeline systems, platforms and related infrastructure. We own interests in approximately 1,422 miles of crude oil pipelines with an aggregate design capacity of approximately 1,800 MBbls per day, a number of which pipeline systems are substantial and/or strategically located. For example, we own a 64% interest in the Poseidon pipeline system and 100% of the Cameron Highway pipeline system, or CHOPS, which is one of the largest crude oil pipelines (in terms of both length and design capacity) located in the Gulf of Mexico. We also own 100% of the Southeast Keathley Canyon Pipeline Company, LLC ("SEKCO"), which is a deepwater pipeline servicing the Lucius, Buckskin and Hadrian North fields in the southern Keathley Canyon area of the Gulf of Mexico. Our interests in operating offshore natural gas pipeline systems and related infrastructure includes approximately 835 miles of pipe with an aggregate design capacity of approximately 2,313 MMcf per day. We also own an interest in four offshore hub platforms, three of which are operational, with aggregate processing capacity of approximately 711 MMcf per day of natural gas and 159 MBbls per day of crude oil. Our offshore pipelines generate cash flows from fees charged to customers or substantially similar arrangements that otherwise limit our direct exposure to changes in commodity prices. Each of our offshore pipelines currently has significant available capacity (with minimal to no additional capital investment required from us) to accommodate future growth in the fields from which the production is dedicated to that pipeline, including fields that have yet to commence production activities, as well as volumes from non-dedicated fields. Sodium Minerals and Sulfur Services Segment Our Alkali Business owns the largest leasehold position of accessible trona ore reserves in the Green River, Wyoming trona patch, a geological formation holding the vast majority of the world’s accessible trona ore reserves, which we mine to ultimately produce, market, and sell soda ash. Soda ash is utilized by our customers as 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 holds leases covering approximately 87,000 acres of land, containing an estimated 895 million- short tons of proved and probable reserves of trona ore, representing an estimated remaining reserve life of over 100 years, soda ash production facilities, underground trona ore mines and solution mining operations and related equipment, logistics and other assets. Our Alkali Business has been mining trona and producing soda ash in the Green River, Wyoming trona patch for over 70 years. All of our Alkali Business’ mining and processing activities are conducted at its “Westvaco” and “Granger” facilities in Wyoming. Utilizing our two facilities near Green River, our Alkali Business involves the mining of trona ore, processing the trona ore into soda ash, also known as sodium carbonate (Na2CO3), and the marketing, selling and distribution of the soda ash and specialty products. We sell our soda ash and specialty products to a diverse customer base directly in the United States, Canada, the European Community, the European Free Trade Area and the South African Customs Union. Our Alkali Business also sells through the American Natural Soda Ash Corporation, or ANSAC, exclusively in all other markets. ANSAC is a nonprofit foreign sales association of which our Alkali Business and two other U.S. soda ash producers are members, whose purpose is to promote export sales of U.S. produced soda ash in conformity with the Webb-Pomerene Act. ANSAC is our Alkali Business’ largest customer. See Note 15 for a further discussion of ANSAC. The global market in which our Alkali Business operates is competitive. Competition is based on a number of factors such as price, favorable logistics and consistent customer service. In North America, primary competition is from other U.S.- 6 Table of Contents based natural soda ash operations: Solvay Chemicals, Ciner Resources, L.P., and Tata Chemicals Soda Ash Partners in Wyoming, and Searles Valley Minerals, in California. As part of our sulfur services business, we primarily (i) provide sulfur removal services by processing refineries high sulfur (or "sour") gas streams to remove the sulfur at ten refining operations located mostly in Texas, Louisiana, Arkansas, Oklahoma, Montana and Utah; (ii) operate significant storage and transportation assets in relation to those services; and (iii) sell NaHS and NaOH (also known as caustic soda) to large industrial and commercial companies. Our sulfur removal services footprint also includes NaHS and caustic soda terminals, and we utilize railcars, ships, barges and trucks to transport product. Our sulfur removal services contracts are typically long-term in nature and have an average remaining term of four years. NaHS is a by-product derived from our refinery sulfur removal services process, and it constitutes the sole consideration we receive for these services. A majority of the NaHS we receive is sourced from refineries owned and operated by large companies, including Phillips 66, CITGO, HollyFrontier, Calumet and Ergon. We sell our NaHS to customers in a variety of industries, with the largest customers involved in mining of base metals, primarily copper and molybdenum, and the production of pulp and paper. We believe we are one of the largest producers and marketers of NaHS in North and South America. Onshore Facilities and Transportation Segment Our onshore facilities and transportation segment owns and/or leases our increasingly integrated suite of onshore crude oil and refined products infrastructure, including pipelines, trucks, terminals, railcars, and rail unloading facilities. It uses those assets, together with other modes of transportation owned by third parties and us, to service its customers and for its own account. The increasingly integrated nature of our onshore facilities and transportation assets is particularly evident in certain of our more recently completed infrastructure projects in areas such as Louisiana and Texas. We own four onshore crude oil pipeline systems, with approximately 460 miles of pipe located primarily in Alabama, Florida, Louisiana, Mississippi and Texas that are rate regulated by the Federal Energy Regulatory Commission, or FERC. The rates for certain segments of our Texas onshore pipeline are regulated by the Railroad Commission of Texas. Our onshore pipelines generate cash flows from fees charged to customers. Each of our onshore pipelines has significant available capacity to accommodate potential future growth in volumes. We own four operational crude oil rail unloading facilities located in Baton Rouge, Louisiana; Raceland, Louisiana; Walnut Hill, Florida; and Natchez, Mississippi which provide synergies to our existing asset footprint. We generally earn a fee for unloading railcars at these facilities. Three of these facilities, our Baton Rouge, Louisiana, Raceland, Louisiana, and Walnut Hill, Florida facilities are directly connected to our existing integrated crude oil pipeline and terminal infrastructure. In addition to the above, we have access to a suite of approximately 200 trucks, 300 trailers, 397 railcars, and terminals and tankage with 4.3 million barrels of storage capacity (excluding capacity associated with our common carrier crude oil pipelines) in multiple locations along the Gulf Coast, which we use to service customers and for its own account. Usually, our onshore facilities and transportation segment experiences limited direct commodity price risk because it utilizes back-to-back purchases and sales, matching sale and purchase volumes on a monthly basis. Unsold volumes are hedged with NYMEX derivatives to offset the remaining price risk. We own two CO2 pipelines with 269 miles of pipe. We have leased our NEJD System, comprised of 183 miles of pipe in North East Jackson Dome, Mississippi, to an affiliate of an independent crude oil company through 2028. We receive a fixed quarterly payment under the NEJD arrangement. That company also has the exclusive right to use our Free State pipeline, comprised of 86 miles of pipe, pursuant to a transportation agreement that expires in 2028. Payments on the Free State pipeline are subject to an "incentive" tariff which provides that the average rate per Mcf that we charge during any month decreases as our aggregate throughput for that month increases above specified thresholds. 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 and 42 push/tow boats (33 inland and 9 offshore). Our marine transportation segment is a provider of transportation services by tank barge primarily for refined petroleum products, including heavy fuel oil and asphalt, as well as crude oil. Refiners accounted for over 80% of our marine transportation volumes for 2019. We also own the M/T American Phoenix, an ocean going tanker with 330,000 barrels of cargo capacity. The M/T American Phoenix is currently transporting crude oil. We are a provider of transportation services for our customers and, in almost all cases, do not assume ownership of the products that we transport. Our marine transportation services are conducted under term contracts, some of which have renewal options for customers with whom we have traditionally had long-standing relationships, and spot contracts. For more information regarding our charter arrangements, please refer to the marine transportation segment discussion below. All of our vessels operate under the U.S. flag and are qualified for domestic trade under the Jones Act. 7 Table of Contents Our Objectives and Strategies 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 (i) the stable and repeatable cash flows from our four operating segments for the foreseeable future, (ii) new long-term commercial opportunities that will provide significant incremental volumes on our already constructed offshore pipeline transportation assets that require no additional investment from us; and (iii) minimal expected growth capital expenditures in 2020 and for the foreseeable future with the exception of the expansion of our Granger soda ash facility, which can be fully funded externally, allows us the flexibility to use any excess cash flow from operations to pay down borrowings, and naturally deleverage our balance sheet. These strategies allow us to further enhance our financial flexibility to opportunistically pursue accretive organic projects and acquisitions should they present themselves. Business Strategy Our primary business strategy is to provide an integrated suite of services to refiners, crude oil and natural gas producers, and industrial and commercial enterprises. Successfully executing this strategy should enable us to generate and grow stable cash flows. Within our midstream business, we have two distinct, complementary types of operations: (i) our offshore Gulf of Mexico crude oil and natural gas pipeline transportation and handling operations, which focus on providing a suite of services primarily to integrated and large independent energy companies who make intensive capital investments (often in excess of billions of dollars) to develop numerous large-reservoir, long-lived crude oil and natural gas properties; and (ii) our onshore- based refinery-centric operations located primarily in the Gulf Coast region of the U.S., which focus on providing a suite of services primarily to refiners, which includes our sulfur removal, transportation, storage, and other handling services. In 2019, refiners were the shippers of approximately 97% of the volumes transported on our onshore crude pipelines, and refiners contract for over 80% of the use of our inland barges, which are used primarily to transport intermediate refined products (not crude oil) between refining complexes. The integrated and large independent energy companies that use our offshore oil pipelines produce oil that is ideally suited for the vast majority of refineries along the Gulf Coast, unlike the lighter crude oil and condensates produced from numerous onshore shale plays. Our Alkali Business is one of the world's leading producers of natural soda ash. Natural soda ash accounts for approximately 30% of the world’s production of soda ash. We believe the significant cost advantage in the production of natural soda ash over synthetically produced soda ash will remain for the foreseeable future, somewhat mitigating the effects of market specific factors in the soda ash market in which we operate. We intend to develop our business by: Identifying and exploiting incremental profit opportunities, including cost synergies, across an increasingly integrated footprint; Economically expanding our pipeline and terminal operations by utilizing capacity currently available on our existing assets that requires minimal to no additional investment; Optimizing our existing assets and creating synergies through additional commercial and operating advancement; Leveraging customer relationships across business segments; Attracting new customers and expanding our scope of services offered to existing customers; Expanding the geographic reach of our businesses; Evaluating internal and third party growth opportunities (including asset and business acquisitions) that leverage our core competencies and strengths and further integrate our businesses; and Focusing on health, safety and environmental stewardship. • • • • • • • • 8 Table of Contents Financial Strategy We believe that preserving financial flexibility is an important factor in our overall strategy and success. Over the long-term, we intend to: • • Increase the relative contribution of recurring and throughput-based revenues, emphasizing longer-term contractual arrangements; Prudently manage our limited direct commodity price risks; • Maintain a sound, disciplined capital structure, including our current and forward path to deleveraging, as well as being cash flow neutral in 2020 and positive in the foreseeable future; and • Create strategic arrangements and share capital costs and risks through joint ventures and strategic alliances. Competitive Strengths We believe we are well positioned to execute our strategies and ultimately achieve our objectives due primarily to the following competitive strengths: • • Our businesses encompass a balanced, diversified portfolio of customers, operations and assets. We operate four business segments and own and operate assets that enable us to provide a number of services primarily to refiners, crude oil and natural gas producers, and industrial and commercial enterprises that use natural soda ash, NaHS and caustic soda. Our business lines complement each other by allowing us to offer an integrated suite of services to common customers across segments. Our businesses are primarily focused on (i) providing offshore crude oil and natural gas pipeline transportation and related handling services in the Gulf of Mexico to mostly integrated and large independent energy companies, (ii) producing sodium minerals and sulfur removal and (iii) providing onshore-based refinery-centric crude oil and refined products transportation and handling services. We are not dependent upon any one customer or principal location for our revenues. Certain of our businesses are among the leaders in each of their respective markets and each of which has a long commercial life and significant barriers to entry . We operate, among others, diversified businesses, each of which is one of the leaders in its market, has a long commercial life and has significant barriers to entry. We operate one of the largest pipeline networks (based on throughput capacity) in the Deepwater area of the Gulf of Mexico, an area that produced approximately 16% of the oil produced in the U.S. in 2019. We are one of the leading producers (based on tons produced) of natural soda ash in the world. We believe we are the largest producer and marketer (based on tons produced) of NaHS in North and South America. We are one of the largest providers of crude oil and petroleum product transportation, storage and other handling services for large, complex refineries in Baton Rouge, Louisiana and Baytown, Texas, both of which have been operational for approximately 100 years. • We are financially flexible and have significant liquidity. As of December 31, 2019, we had $739.6 million available under our $1.7 billion revolving credit agreement, including up to $195.7 million available under the $200 million petroleum products inventory loan sublimit and $98.9 million available for letters of credit. Our inventory borrowing base was $4.3 million at December 31, 2019. • Our businesses provide relatively consistent consolidated financial performance. Our historically consistent and improving financial performance, combined with our goal of a conservative capital structure over the long term, has allowed us to generate relatively stable and increasing cash flows. • We have limited direct commodity price risk exposure in our oil and gas and NaHS businesses. The volumes of crude oil, refined products or intermediate feedstocks we purchase are either subject to back-to-back sales contracts or are hedged with NYMEX derivatives to limit our direct exposure to movements in the price of the commodity, although we cannot completely eliminate commodity price exposure. Our risk management policy requires us to monitor the effectiveness of the hedges to maintain a value at risk of such hedged inventory not in excess of $2.5 million. In addition, our service contracts with refiners allow us to adjust the rates we charge for processing to maintain a balance between NaHS supply and demand. • Our offshore Gulf of Mexico crude oil and natural gas pipeline transportation and handling operations are located in a significant producing region with large-reservoir, long-lived crude oil and natural gas properties. We provide a suite of services, primarily to integrated and large independent energy companies who make intensive capital investments to develop numerous large-reservoir, long-lived crude oil and natural gas properties, in one of the most active drilling and development regions in the U.S.-the Gulf of Mexico, a producing region representing approximately 16% of the crude oil production in the U.S. in 2019. 9 Table of Contents • • • • • Our Alkali Business has significant cost advantages over synthetic production methods. Our Alkali Business has significant cost advantages over synthetic production methods, including lower raw material and energy requirements. According to IHS, on average, the cash cost to produce material soda ash has been about half of the cost to produce synthetic soda ash. Our expertise and reputation for high performance standards and quality enable us to provide refiners with economic and proven services. Our extensive understanding of the sulfur removal process and crude oil refining can provide us with an advantage when evaluating new opportunities and/or markets. Some of our pipeline transportation and related assets are strategically located. Our pipelines are critical to the ongoing operations of our refiner and producer customers. In addition, a majority of our terminals are located in areas that can be accessed by pipeline, truck, rail or barge. Some of our onshore facilities and transportation assets are operationally flexible. Our portfolio of trucks, railcars, barges and terminals affords us flexibility within our existing regional footprint and provides us the capability to enter new markets and expand our customer relationships. Our marine transportation assets provide waterborne transportation throughout North America. Our fleet of barges and boats provide service to both inland and offshore customers within a large North American geographic footprint. All of our vessels operate under the U.S. flag and are qualified for U.S. coastwise trade under the Jones Act. • We have an experienced, knowledgeable and motivated executive management team with a proven track record. Our executive management team has an average of more than 25 years of experience in the midstream sector. Its members have worked in leadership roles at a number of large, successful public companies, including other publicly-traded partnerships. Through their equity interest in us and compensation package (including long term incentive awards based on available cash before reserves, leverage, and safety metrics), our executive management team is incentivized to create value by increasing cash flows. Recent Developments and Status of Certain Growth Initiatives The following is a brief listing of developments since December 31, 2018. Additional information regarding most of these items may be found elsewhere in this report. Granger Production Facility Expansion On September 23, 2019, we announced the expansion of our existing Granger facility (the "Granger Optimization Project" or "GOP") expected to be completed during 2022. We entered into agreements with funds affiliated with GSO Capital Partners LP ("GSO") for the purchase of up to $350 million of preferred units in Genesis Alkali Holdings Company ("Alkali Holdings"). The proceeds we will receive from GSO will fund up to 100% of the anticipated cost of the GOP. The preferred unitholders will receive payment-in-kind in lieu of cash distributions during the anticipated construction period. As of December 31, 2019, we had issued 130,000 preferred units. Refinancing of our 2022 Notes In January 2020, we issued $750 million in aggregate principal amount of 7.750% senior unsecured notes due February 1, 2028 (the "2028 Notes"). Interest payments are due February 1 and August 1 of each year with the initial interest payment due August 1, 2020. That issuance generated net proceeds of approximately $738.9 million, net of issuance costs incurred. The net proceeds were used to purchase and redeem all of our outstanding 6.750% senior notes due 2022 (the "2022 Notes"). Of the net proceeds, $554.8 million were used to repurchase the 2022 Notes (including principal, accrued interest and tender premium) that were validly tendered in our tender offer for the 2022 Notes, and the remaining balance was used for repaying a portion of the borrowings outstanding under our revolving credit facility. On January 17, 2020 we called for redemption of the remaining balance of our 2022 Notes with a redemption date of February 16, 2020. Ownership Structure We conduct our operations and own our operating assets through subsidiaries and joint ventures. As is customary with publicly traded limited partnerships, Genesis Energy, LLC, our general partner, is responsible for operating our business, including providing all necessary personnel and other resources. 10 Table of Contents The following chart depicts our organizational structure at December 31, 2019. Description of Segments and Related Assets We conduct our businesses through four operating segments: offshore pipeline transportation, sodium minerals and sulfur services, onshore facilities and transportation and marine transportation. These segments are strategic business units that provide a variety of midstream energy-related services as well as soda ash production and sales. Financial information with respect to each of our segments can be found in Note 14 to our Consolidated Financial Statements in Item 8. We have a diverse portfolio of customers, operations and assets, including pipelines, refinery-related plants, soda ash production facilities and related equipment, trona reserves, storage tanks and terminals, railcars, rail unloading facilities, barges and other vessels, and trucks. Substantially all of our revenues are derived from providing services to refiners, integrated and large independent crude oil and natural gas companies, and large industrial and commercial enterprises. Our onshore-based operations, excluding those associated with our Alkali Business, 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. 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. Within our Alkali Business, we sell our soda ash and specialty products to a diverse customer base directly in the United States, Canada, the European Community, the European Free Trade Area and the South African Customs Union. We sell through ANSAC exclusively in all other markets. Offshore Pipeline Transportation Offshore Crude Oil and Natural Gas Pipelines We own interests in several crude oil and natural gas pipelines and related infrastructure located offshore in the Gulf of Mexico, a producing region representing approximately 16% of the crude oil production in the U.S. in 2019. 11 Table of Contents The table below reflects our interests in our operating offshore crude oil pipelines: Offshore crude oil pipelines Operator System Miles Design Capacity (Bbls/day) (1) Interest Owned Throughput (Bbls/day) 100% basis Throughput (Bbls/day) net to ownership interest Main Lines CHOPS Poseidon Odyssey Eugene Island Pipeline and Other Total Lateral Lines (2) SEKCO Shenzi Crude Oil Pipeline Allegheny Crude Oil Pipeline Marco Polo Crude Oil Pipeline Constitution Crude Oil Pipeline Tarantula Genesis Genesis Shell Pipeline Genesis/ Shell Pipeline 380 358 120 184 1,042 500,000 350,000 100% 64% 234,301 264,931 234,301 169,556 200,000 29% 144,785 41,988 39,000 29% 1,089,000 8,845 652,862 8,845 454,690 Genesis 149 115,000 100% Genesis Genesis Genesis Genesis Genesis 83 40 37 67 4 230,000 100% 140,000 100% 120,000 100% 80,000 30,000 100% 100% (1) Capacity figures presented represent 100% of the design capacity; except for Eugene Island, which represents our net capacity in the undivided interest (29%) in that system. Ultimate capacities can vary primarily as a result of pressure requirements, installed pumps, related facilities and the viscosity of the crude oil actually moved. (2) Represents 100% owned lateral crude oil pipelines which, ultimately flow into our other offshore crude oil pipelines (including CHOPS and Poseidon) and thus are excluded from main lines above. • • • • • CHOPS. CHOPS is comprised of 24- to 30-inch diameter pipelines designed to deliver crude oil from fields in the Gulf of Mexico to refining markets along the Texas Gulf Coast via interconnections with refineries and terminals located in Port Arthur and Texas City, Texas. CHOPS also includes two strategically located multi-purpose offshore platforms. Poseidon. The Poseidon system is comprised of 16- to 24-inch diameter pipelines to deliver crude oil from developments in the central and western offshore Gulf of Mexico to other pipelines and terminals onshore and offshore Louisiana. An affiliate of Shell owns the remaining 36% interest in Poseidon. Odyssey. The Odyssey system is comprised of 12- to 20-inch diameter pipelines to deliver crude oil from developments in the eastern Gulf of Mexico to other pipelines and terminals onshore Louisiana. An affiliate of Shell owns the remaining 71% interest in Odyssey. Eugene Island. The Eugene Island system is comprised of a network of crude oil pipelines, the main pipeline of which is 20 inches in diameter, to deliver crude oil from developments in the central Gulf of Mexico to other pipelines and terminals onshore Louisiana. Other owners in Eugene Island include affiliates of Exxon Mobil, ConocoPhillips and Shell Oil Company. SEKCO Pipeline. SEKCO is a deepwater pipeline serving the Lucius crude oil and natural gas field, Buckskin oil field and Hadrian North oil field located in the southern Keathley Canyon area of the Gulf of Mexico. SEKCO has crude oil transportation agreements with various Gulf of Mexico producers who have dedicated their production from Lucius, Buckskin and Hadrian North to that pipeline for the life of the reserves. Buckskin and Hadrian North each had first oil in 2019. 12 Table of Contents • • Shenzi Crude Oil Pipeline. The Shenzi Crude Oil Pipeline gathers crude oil production from the Shenzi production field located in the Green Canyon area of the Gulf of Mexico offshore Louisiana for delivery to both our CHOPS and Poseidon pipeline systems. Allegheny Crude Oil Pipeline. The Allegheny Crude Oil Pipeline connects the Allegheny and South Timbalier 316 platforms in the Green Canyon area of the Gulf of Mexico with the CHOPS and Poseidon pipelines. • Marco Polo Crude Oil Pipeline. The Marco Polo Crude Oil Pipeline transports crude oil from our Marco Polo crude oil platform to an interconnect with the Allegheny Crude Oil Pipeline in Green Canyon Block 164. • Constitution Crude Oil Pipeline. The Constitution Crude Oil Pipeline gathers crude oil from the Constitution, Constellation, Caesar Tonga and Ticonderoga production fields located in the Green Canyon area of the Gulf of Mexico for delivery to either the CHOPS or Poseidon pipelines. None of our offshore crude oil pipelines are rate regulated with the exception of Eugene Island, which is regulated by the FERC. The table below reflects our interests in our operating offshore natural gas pipelines: Offshore natural gas pipelines High Island Offshore System Anaconda Gathering System Green Canyon Laterals Manta Ray Offshore Gathering System Nautilus System Total Operator Genesis Genesis Genesis Enbridge Enbridge System Miles 287 183 27 237 101 835 Design Capacity (MMcf/day) (1) Interest Owned 500 300 113 800 600 2,313 100% 100% Various (2) 25.7% 25.7% (1) Capacity figures presented represent 100% of the design capacity. (2) We proportionately consolidate our undivided interest, which is 13.58%, in approximately 20 miles of the Green Canyon Lateral pipelines. The remainder of the laterals are wholly owned. • • • High Island. The High Island Offshore System (HIOS) transports natural gas from producing fields located in the Galveston, Garden Banks, West Cameron, High Island and East Breaks areas of the Gulf of Mexico to interconnects with the Kinetica Energy Express. HIOS includes 201 miles of pipeline and eight pipeline junction and service platforms that are regulated by the FERC. In addition, this system included the 86-mile East Breaks Gathering System, which connects HIOS to the Hoover-Diana deepwater platform located in Alaminos Canyon Block 25. Anaconda. The Anaconda Gathering System gathers natural gas from producing fields located in the Green Canyon area of the Gulf of Mexico for delivery to the Nautilus System. Green Canyon. The Green Canyon Laterals represent a collection of small diameter pipelines that gather natural gas for delivery to HIOS and various other downstream pipelines. • Manta Ray. The Manta Ray Offshore Gathering System gathers natural gas from producing fields located in the Green Canyon, Southern Green Canyon, Ship Shoal, South Timbalier and Ewing Bank areas of the Gulf of Mexico for delivery to numerous downstream pipelines, including the Nautilus System. This system includes three pipeline junction platforms. • Nautilus. The Nautilus System connects the Anaconda Gathering system and Manta Ray Offshore Gathering System to the Neptune natural gas processing plant located in south Louisiana. Offshore Hub Platforms Offshore Hub platforms are typically used to interconnect the offshore pipeline network; provide an efficient means to perform pipeline maintenance; locate compression, separation and production handling equipment and similar assets; and conduct drilling operations during the initial development phase of a crude oil and natural gas property. The results of operations from offshore platform services are primarily dependent upon the level of commodity charges and/or demand-type fees billable to customers. Revenue from commodity charges is based on a fee per unit of volume delivered to the platform (typically per MMcf of natural gas or per barrel of crude oil) multiplied by the total volume of each product delivered. Demand-type fees are similar to firm capacity reservation agreements for a pipeline in that they are charged to a customer regardless of the volume the customer actually delivers to the platform. Contracts for platform services often include both 13 Table of Contents demand-type fees and commodity charges, but demand-type fees generally expire after a contractually fixed period of time and in some instances may be subject to cancellation by customers. The table below reflects our interests in our operating offshore hub platforms: Offshore hub platform Marco Polo Garden Banks 72 (2) East Cameron 373 Total Operator Occidental Genesis Genesis Water Depth (Feet) 4,300 518 441 Natural Gas Capacity (MMcf/ day) (1) Crude Oil Capacity (Bbls/ day) (1) Interest Owned 300 216 195 711 120,000 36,000 3,000 159,000 100% 54% 100% (1) Capacity figures presented represent 100% of the design capacity. (2) We proportionately consolidate our undivided interest in the Garden Banks 72 platform. • Marco Polo. The Marco Polo platform, which is located in Green Canyon Block 608, processes crude oil and natural gas from production fields located in the South Green Canyon area of the Gulf of Mexico. • • Garden Banks. The Garden Banks 72 platform serves as a base for gathering deepwater production from the Garden Banks area of the Gulf of Mexico. This platform also serves as a junction platform for the CHOPS and Poseidon pipeline systems. East Cameron. The East Cameron 373 platform processes production from the Garden Banks and East Cameron areas of the Gulf of Mexico. Customers Due to the cost of finding, developing and producing crude oil properties in the deepwater regions of the Gulf of Mexico, most of our offshore pipeline customers are integrated crude oil companies and other large producers, and those producers desire to have longer-term arrangements ensuring that their production can access the markets. Usually, our offshore crude oil pipeline customers enter into buy-sell or other transportation arrangements, pursuant to which the pipeline acquires possession (and, sometimes, title) from its customer of the relevant production at a specified location (often a producer’s platform or at another interconnection) and redelivers possession (and title, if applicable) to such customer of an equivalent volume at one or more specified downstream locations (such as a refinery or an interconnection with another pipeline). Most of the production handled by our offshore pipelines is pursuant to life-of-reserve commitments that include both firm and interruptible capacity arrangements. During 2019, no customers of our offshore pipeline transportation segment generated more than ten percent of our consolidated revenues. Competition The principal competition for our offshore pipelines includes other crude oil and natural gas pipeline systems as well as producers who may elect to build or utilize their own production handling facilities. Our offshore pipelines compete for new production on the basis of geographic proximity to the production, cost of connection, available capacity, transportation rates and access to onshore markets. In addition, the ability of our offshore pipelines to access future reserves will be subject to our ability, or the producers’ ability, to fund the significant capital expenditures required to connect to the new production. In general, most of our offshore pipelines are not subject to regulatory rate-making authority, and the rates our offshore pipelines charge for services are dependent on the quality of the service required by the customer and the amount and term of the reserve commitment by that customer. Sodium Minerals and Sulfur Services Our Sodium Minerals and Sulfur Services segment consists of our Alkali Business and our sulfur removal business as discussed in further detail below. Alkali Business Our Alkali Business is one of the leading producers of natural soda ash worldwide. We provide our soda ash to a variety of industries such as flat glass, container glass, detergent and chemical manufacturing. Soda ash, also known by its chemical name sodium carbonate (Na2CO3), is a highly valued raw material in the manufacture of glass due to its properties of lowering the melting point of silica in the batch. Soda ash is also valued by detergent manufacturers for its absorptive and water 14 Table of Contents softening properties. We produce our products from trona, which we mine at two sites in the Green River Basin, Wyoming. The vast majority of the world’s accessible trona reserves are located in the Green River Basin. According to historical production statistics, approximately 30% of global soda ash is produced from trona or similar sodium carbonate containing materials, with the remainder being produced synthetically, which requires chemical transformation of limestone and salt using a significantly higher amount of energy. Production of soda ash from trona is significantly less expensive than producing it synthetically. In addition, life-cycle analyses reveal that production from trona consumes less energy and produces less carbon dioxide and fewer undesirable by-products than synthetic production. Our Alkali Business includes the following: Dry mining of trona ore underground at our Westvaco facility; Secondary recovery of trona from previously dry mined areas underground at our Westvaco and Granger facilities through solution mining; Processing of raw trona ore into soda ash and specialty sodium alkali products; and • • • • Marketing, sale and distribution of alkali products. Our Alkali Business currently produces approximately 4 million tons of soda ash and downstream specialty products annually. All mining and processing activities related to our products take place in our facilities located in the Green River Basin. Dry Mining of Trona Ore Trona is dry mined underground at our Westvaco facility primarily through the operation of our single longwall mining machine. Longwall mining provides higher recovery rates leading to extended mine life compared to other dry mining techniques. Development of the “tunnels” necessary to access and ventilate our longwall is through room and pillar mining completed primarily by our fleet of borer miners. The ore is conveyed underground to two hoisting operations where it travels about 1,600 feet vertically to the surface and is either taken directly into the processing facilities or stored on outdoor stockpiles for future consumption. Secondary Recovery Solution Mining We solution mine trona at both our Westvaco and Granger sites using secondary recovery techniques. Our secondary recovery mining starts with the recovery of water streams from our operations and non-trona solids (“insolubles”) remaining from the processing of dry mined trona. The water and some insolubles are injected through a number of wells into the old dry mine workings at both our Westvaco and Granger sites. The insolubles settle out while the water travels through the old workings, dissolving trona that remained during previous dry mining. Multiple pumping systems are used to pump the enriched solution to the surface for processing. Processing of Trona into Finished Alkali Products Our Sesqui and Mono plants, located at our Westvaco site, convert dry-mined trona into soda ash. Crushing, dissolution in water, filtration, and crystallization techniques are used to produce the desired final products. In the Mono process, the ore is calcined with heat, prior to dissolution, to convert the trona to soda ash by the removal of water and carbon dioxide. A final drying step using steam produces a dense soda ash product from the Mono process. In our Sesqui plant, the calcination is performed at the end of the process, producing a light density soda ash that is preferred in applications desiring increased absorptivity. The Sesqui process also has the ability to produce refined sodium sesquicarbonate (which we sell under the names S-Carb ® and Sesqui™) for use as a buffer in animal feed formulations and in cleaning and personal care applications. Solution mined trona is converted into dense soda ash in our ELDM operation at the Westvaco site and at our Granger facility. The steps to produce soda ash are similar to the dry mined processes, except the crushing and dissolving steps are eliminated because the trona is already in a water solution as it leaves the mine. Intermediate, semi-processed products are extracted from our soda ash processes at Westvaco at strategic locations for use as feedstocks for production of sodium bicarbonate and 50% caustic soda (NaOH). Marketing, Sale and Distribution of Alkali Products We sell our alkali products to customers directly in the United States, Canada, the European Community, the European Free Trade Area and the South African Customs Union. We sell through ANSAC exclusively in all other markets. ANSAC is a 15 Table of Contents nonprofit foreign sales association in which we and two other U.S. soda ash producers are members, whose purpose is to promote export sales of U.S. produced soda ash in conformity with the Webb-Pomerene Act. All of our alkali products are shipped by rail and truck from our facilities in the Green River Basin. We operate a fleet of approximately 3,500 covered hopper cars which we use to deliver over 90% of the sales of alkali products from the Green River facilities, all of which are shipped via a single rail line owned and operated by Union Pacific Railroad. We lease these railcars from banks and leasing companies and from FMC Corporation under agreements with varying term-lengths. We recover costs of leasing through mileage credits paid under agreements with customers and carriers in accordance with established industry practices and government requirements. We sell most of our Alkali products as soda ash. Soda ash is the only product we sell to ANSAC. Soda ash is highly valued by manufacturers of flat and container glass because it lowers the temperature of the batch in a glass furnace. It is also valued by detergent manufacturers for its absorptive qualities. Demand for soda ash in the United States has been relatively flat over the last five years. Sales of soda ash in rapidly developing economies have grown more rapidly as a growing middle class demands more products that use soda ash, such as glass for housing and autos and detergents for cleaning. In addition, we also market sodium bicarbonate to private label manufacturers who package it for sale to retail grocery customers as baking soda. We also sell sodium bicarbonate to manufacturers of packaged baked goods and similar products. Animal feed is an important market for sodium bicarbonate, which is mixed with feed to increase the yield of dairy cows and improve the health of poultry and other livestock. Sodium bicarbonate is also sold to customers who use it in hemodialysis applications and as an active ingredient in pharmaceutical products. Sulfur Removal Business Our sulfur services business primarily (i) provides sulfur-extraction services to ten refining operations located mostly in Texas, Louisiana, Arkansas, Oklahoma, Montana and Utah, (ii) operates significant storage and transportation assets in relation to those services and (iii) sells NaHS and caustic soda to large industrial and commercial companies. Our sulfur removal services primarily involve processing refiners' high sulfur (or “sour”) gas streams that the refineries have generated from crude oil processing operations. Our process applies our proprietary technology, which uses large quantities of caustic soda (the primary raw material used in our process) to act as a scrubbing agent under prescribed temperature and pressure to remove sulfur. Sulfur removal in a refinery is a key factor in optimizing production of refined products such as gasoline, diesel and aviation fuel. Our sulfur removal technology returns a clean (sulfur-free) hydrocarbon stream to the refinery for further processing into refined products, and simultaneously produces NaHS. The resultant NaHS constitutes the sole consideration we receive for our sulfur removal services. A majority of the NaHS we receive is sourced from refineries owned and operated by large companies, including Phillips 66, CITGO, HollyFrontier, Calumet and Ergon. Our ten sulfur removal services contracts have an average remaining life of four years. This includes the extended term of our renegotiated sulfur removal services contract with Phillips 66 at our Westlake, Louisiana facility, which now extends through 2026. The timing upon which these contracts renew vary based upon location and terms specified within each specific contract. Our sodium minerals and sulfur services footprint includes NaHS and caustic soda terminals in the Gulf Coast, the Midwest, Montana, Utah, British Columbia and South America. In conjunction with our onshore facilities and transportation segment, we sell and deliver (via railcars, ships, barges and trucks) NaHS and caustic soda to approximately 150 customers. We believe we are one of the largest marketers of NaHS in North and South America. By minimizing our costs through utilization of our own logistical assets and leased storage sites, we believe we have a competitive advantage over other suppliers of NaHS. NaHS is used in the specialty chemicals business (plastic additives, dyes and personal care products), in pulp and paper business, and in connection with mining operations (nickel, gold and separating copper from molybdenum) as well as bauxite refining (aluminum). NaHS has also gained acceptance in environmental applications, including waste treatment programs requiring stabilization and reduction of heavy and toxic metals and flue gas scrubbing. Additionally, NaHS can be used for removing hair from hides at the beginning of the tannery process. Caustic soda is used in many of the same industries as NaHS. Many applications require both chemicals for use in the same process. For example, caustic soda can increase the yields in bauxite refining, pulp manufacturing and in the recovery of copper, gold and nickel. Caustic soda is also used as a cleaning agent (when combined with water and heated) for process equipment and storage tanks at refineries. Customers Our natural soda ash is sold to a diverse customer base in the United States, Canada, the European Community, the European Free Trade Area and the South African Customs Union. Our Alkali Business sells exclusively through the American Natural Soda Ash Corporation, or ANSAC, in all other markets. ANSAC is a nonprofit foreign sales association in which our Alkali Business and two other U.S. soda ash producers are members. ANSAC is our Alkali Business’ largest customer. Soda ash sold to ANSAC is later resold to other customers worldwide. Soda ash is utilized by our customers as 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. 16 Table of Contents We provide on-site sulfur removal services utilizing NaHS units at ten refining locations. Even though some of our customers have elected to own the sulfur removal facilities located at their refineries, we operate those facilities. We market all of our NaHS as well as small amounts of NaHS for a handful of third parties. We sell our NaHS to customers in a variety of industries, with the largest customers involved in mining of base metals, primarily copper and molybdenum and the production of pulp and paper. We sell to customers in the copper mining industry in the western U.S., Canada and Mexico. We also export the NaHS to South America for sale to customers for mining in Peru and Chile. No sulfur removal customer or NaHS sales customer is responsible for more than ten percent of our consolidated revenues. Many of the industries that our NaHS customers are in (such as copper mining and the pulp and paper industry) participate in global markets for their products. As a result, this creates an indirect exposure for NaHS to global demand for the end products of our customers. Provisions in our service contracts with refiners allow us to adjust our sour gas processing rates (sulfur removal) to maintain a balance between NaHS supply and demand. We sell caustic soda to many of the same customers who purchase NaHS from us, including pulp and paper manufacturers and customers in the copper mining industry. We also supply caustic soda to some of the refineries in which we operate for use in cleaning processing equipment. Competition- Alkali Business The global soda ash market in which our Alkali Business operates is competitive. Competition is based on a number of factors such as price, favorable logistics and consistent customer service. In North America, primary competition is from other U.S.-based natural soda ash operations: Solvay Chemicals, Ciner Resources, L.P., and Tata Chemicals Soda Ash Partners in Wyoming, and Searles Valley Minerals in California. Because of the structural cost advantages of natural soda ash production in the United States, including lower raw material and energy requirements, imports have not been an important source of competition in North America. According to IHS, on average, the cash cost to produce material soda ash has been about half of the cost to produce synthetic soda ash. Sales of soda ash and specialty products outside of North America (principally through ANSAC) face competition from a variety of others, in most cases producers of soda ash using the synthetic method, but to a lesser extent producers of natural soda ash based in Turkey, China and Africa. Our Alkali Business’ specialty Alkali products also experience significant competition from producers of sodium bicarbonate, such as Church & Dwight Co., Solvay Chemicals and Natural Soda LLC. Soda ash is highly valued by manufacturers of flat and container glass because it lowers the temperature of the batch in a glass furnace. It is also valued by detergent manufacturers for its absorptive qualities. In addition, soda ash is used in paper production applications and other consumer and industrial applications. Demand for soda ash in the United States has been relatively flat over the last five years. Sales of soda ash in rapidly developing economies have grown more rapidly as a growing middle class demands more products that use soda ash, such as glass for housing and autos and detergents for cleaning. ANSAC is our Alkali Business's largest customer, with total sales representing 33% of total sales in the sodium minerals and sulfur services segment. Apart from ANSAC, our sodium minerals and sulfur services segment is not dependent on any single or small group of customers, the loss of one of which would not have a material adverse effect on us. Competition- Sulfur Services Our competitors for the supply of NaHS consist primarily of parties who produce NaHS as a by-product of or an alternative to other sulfur derivative products, including fertilizers, pesticides, other agricultural products, plastic additives and lubricants. Typically our competitors for the supply of NaHS have only one location and they do not have the logistical infrastructure that we have to supply customers. These competitors often reduce NaHS production when demand for their alternative sulfur derivatives is high and increase NaHS production when demand for these alternatives is low. Also, they tend to supply less when prices and demand for elemental sulfur are higher and supply more NaHS when the price of elemental sulfur falls. Demand for NaHS faces competition from alternative sulfidity management mediums such as sulfidic caustic, emulsified sulfur, salt cake and flake NaHS. Changes in the value, supply and/or demand of these alternative products can impact the volume and/or value of our NaHS sold. Typically, our competitors for sulfur removal services include refineries themselves through the use of their sulfur removal processes. Our competitors for sales of caustic soda include manufacturers of caustic soda. These competitors supply caustic soda to our sodium minerals and sulfur services operations and support us in our third-party caustic soda sales. By utilizing our storage capabilities and having access to transportation assets, we sell caustic soda to third parties who gain efficiencies from acquiring both NaHS and caustic soda from one source. 17 Table of Contents Onshore Facilities and Transportation We provide onshore facilities and transportation services to Gulf Coast crude oil refineries and producers through a combination of purchasing, transporting, storing, blending and marketing of crude oil and refined products (primarily fuel oil, asphalt, and other heavy refined products). In connection with these services, we utilize our increasingly integrated portfolio of logistical assets consisting of pipelines, trucks, terminals, railcars and barges. The increasingly integrated nature of our onshore facilities and transportation assets is particularly evident in areas such as Louisiana and Texas. Our crude oil related services include gathering crude oil from producers at the wellhead, transporting crude oil by gathering line, truck, railcar and barge to pipeline injection points, transporting crude oil for our gathering and marketing operations and for other shippers on our pipelines and marketing crude oil to refiners. Not unlike our crude oil operations, we also gather refined products from refineries, transport refined products via pipeline, truck, railcar and barge, and sell refined products to customers in wholesale markets. For certain of these services, we generate fee-based income related to the transportation services provided. In some cases, we also profit from the difference between the price at which we re-sell the crude oil and petroleum products less the price at which we purchase the crude oil and products, minus the associated costs of aggregation and transportation. Our crude oil onshore facilities and transportation operations are concentrated in Texas, Louisiana, Alabama, Florida and Mississippi. These operations help to ensure (among other things) a base supply source for our crude oil pipeline systems, refinery customers and other shippers while providing our producer customers with a market outlet for their production. By utilizing our network of pipelines, trucks, railcars, barges, and terminals, we are able to provide transportation related services to, and in many cases back-to-back gathering and marketing arrangements with, crude oil refiners and producers. Additionally, our crude oil gathering and marketing expertise and knowledge base provide us with an ability to capitalize on opportunities that arise from time to time in our market areas. We gather and market approximately 32,000 barrels per day (as of December 31, 2019) of crude oil, much of which is produced from large resource basins throughout Texas and the Gulf Coast. Our crude oil pipelines transport many of these barrels, as well barrels for third party producers and refiners to which we charge fees for our transportation services. Given our network of terminals, we also have the ability to store crude oil during periods of contango (crude oil prices for future deliveries are higher than for current deliveries) for delivery in future months. When we purchase and store crude oil during periods of contango, we attempt to limit direct commodity price risk by simultaneously entering into a contract to sell the inventory in a future period, either with a counterparty or in the crude oil futures market. The most substantial component of the costs we incur while aggregating crude oil and petroleum products relates to operating our fleet of owned and leased trucks and railcars and incurring transportation related costs. Onshore Crude Oil Pipelines Through the onshore pipeline systems and related assets we own and operate, we transport crude oil for our gathering and marketing operations and for other shippers pursuant to tariff rates regulated by FERC or the Railroad Commission of Texas, or TXRRC. Accordingly, we offer transportation services to any shipper of crude oil, if the products tendered for transportation satisfy the conditions and specifications contained in the applicable tariff. Pipeline revenues are a function of the level of throughput and the particular point where the crude oil is injected into the pipeline and the delivery point. We also may earn revenue from pipeline loss allowance volumes. In exchange for bearing the risk of pipeline volumetric losses, we deduct volumetric pipeline loss allowances and crude oil quality deductions. Such allowances and deductions are offset by measurement gains and losses. When our actual volume losses are less than the related allowances and deductions, we recognize the difference as income and inventory available for sale valued at the market price for the crude oil. The margins from our onshore crude oil pipeline operations are generated by the difference between the sum of revenues from regulated published tariffs and pipeline loss allowance revenues and the fixed and variable costs of operating and maintaining our pipelines. We own and operate four onshore common carrier crude oil pipeline systems: the Texas System, the Jay System, the Mississippi System, and the Louisiana System. 18 Table of Contents Product Interest Owned Design Capacity (Bbls/day) 2019 Throughput (Bbls/day) System Miles Texas System Jay System Mississippi System Louisiana System Crude Oil 100% Crude Oil 100% Crude Oil Intermediates Refined Products 100% 150,000 10,461 143 45,000 5,994 220 350,000 117,130 51 Crude Oil 100% Existing 8" - 60,000 Looped 18" - 275,000 59,435 47 Approximate owned tankage storage capacity (Bbls) 1,100,000 230,000 247,500 330,000 Hastings Junction, TX to Webster, TX Texas City, TX to Webster, TX FERC/ TXRRC Port Hudson, LA to Baton Rouge, LA Baton Rouge, LA to Port Allen, LA Southern AL/ FL to Mobile, AL Soso, MS to Liberty, MS FERC FERC FERC Location Rate Regulated • • Texas System. Our Texas System transports crude oil from Hastings Junction (south of Houston) to several delivery points near Houston, Texas (including our Webster, Texas facility). This system also takes delivery of crude oil volumes at Texas City (which includes the capability of receiving various Gulf of Mexico pipeline volumes) for delivery to our Webster, Texas facility, which ultimately connects to other crude oil pipelines. We earn a tariff for our transportation services, with the tariff rate per barrel of crude oil varying with the distance from injection point to delivery point. Jay System. Our Jay System provides crude oil shippers access to refineries, pipelines and storage near Mobile, Alabama. That system also includes gathering connections to approximately 39 wells, additional crude oil storage capacity of approximately 20,000 barrels in the field, an interconnect with our Walnut Hill rail facility, a delivery connection to a refinery in Alabama and an interconnection to another common carrier pipeline that delivers crude oil into Mississippi. • Mississippi System. Our Mississippi System provides shippers of crude oil in Mississippi indirect access to refineries, pipelines, storage, terminals and other crude oil infrastructure located in the Midwest. That system is adjacent to several crude oil fields that are in various phases of being produced through tertiary recovery strategy, including CO2 injection and flooding. We provide transportation services on our Mississippi pipeline through an “incentive” tariff which provides that the average rate per barrel that we charge during any month decreases as our aggregate throughput for that month increases above specified thresholds. • Louisiana System. Our Louisiana System transports crude oil from Port Hudson to our Baton Rouge Scenic Station rail unloading facility and continues downstream to the Anchorage Tank Farm servicing Exxon Mobil Corporation's Baton Rouge refinery. This refinery is one of the largest refinery complexes in North America, with more than 500,000 barrels per day of refining capacity. Our Louisiana system also connects the Anchorage Tank Farm to our Port of Baton Rouge Terminal (which was also built to service Exxon's Baton Rouge refinery), allowing bidirectional flow of crude oil, intermediates and refined products between the Anchorage Tank Farm and this terminal via a dedicated crude pipeline and a dedicated intermediates pipeline. Total daily volume for the year ended December 31, 2019 includes 51,267 barrels per day of intermediate refined products associated with our Port of Baton Rouge Terminal pipelines. 19 Table of Contents This pipeline system serves as a key asset in our increasingly integrated Baton Rouge area midstream infrastructure, which also includes terminal and rail facilities as discussed previously. Other Onshore Facilities and Transportation Operations We own four operational crude oil rail unloading facilities located in Baton Rouge, Louisiana; Raceland, Louisiana; Walnut Hill, Florida; and Natchez, Mississippi which provide synergies to our existing asset footprint. We generally earn a fee for unloading railcars at these facilities. Three of these facilities, our Baton Rouge, Louisiana, Raceland, Louisiana, and Walnut Hill, Florida facilities are directly connected to our existing integrated crude oil pipeline and terminal infrastructure. Within our onshore facilities and transportation business segment, we employ many types of logistically flexible assets. These assets include approximately 200 trucks, 300 trailers, 397 crude oil railcars, and terminals and other tankage with approximately 4.3 million barrels of leased and owned storage capacity in multiple locations along the Gulf Coast, accessible by pipeline, truck, rail or barge, in addition to tankage related to our crude oil pipelines, previously mentioned. Our refined products onshore facilities and transportation operations are concentrated in the Gulf Coast region, principally Texas and Louisiana. Through our footprint of owned and leased pipelines, trucks, leased railcars, terminals and barges, we are able to provide Gulf Coast area refineries with transportation services as well as market outlets for certain heavy refined products. We primarily engage in the transportation and supply of fuel oil, asphalt, and other heavy refined products to our customers in wholesale markets. We have the ability from time to time to obtain various grades of refined products from our refinery customers and blend them to meet the requirements of our other market customers. However, because our refinery customers may choose to manufacture such refined products based on a number of economic and operating factors, we cannot predict the timing of contribution margins related to our blending services. CO2 Pipelines We transport CO2 on our Free State pipeline for a fee and we lease our Northeast Jackson Dome Pipeline System, or NEJD System, for a fee. Product Interest owned System miles Pipeline diameter Location Rate Regulated Free State Pipeline CO2 100% 86 20" Jackson Dome near Jackson, MS to East Mississippi No Our Free State pipeline extends from CO2 source fields near Jackson, Mississippi to crude oil fields in eastern Mississippi. We have a transportation services agreement through 2028 related to our Free State pipeline with a single shipper who has the right to use 100% of that pipeline's capacity. Our NEJD System transports CO2 to tertiary crude oil recovery operations in southwest Mississippi. We have leased that pipeline to an affiliate of the shipper on our Free State pipeline through 2028. Our NEJD lessee is responsible for all operations and maintenance on that system and will bear and assume substantially all obligations and liabilities with respect to that system. Customers Our onshore facilities and transportation business encompasses numerous refiners and hundreds of producers, for which we provide transportation related services, as well as gather from and market to crude oil and refined products. During 2019, no onshore facilities and transportation customers generated over 10% of our consolidated revenue. Competition In our crude oil onshore facilities and transportation operations, we compete with other midstream service providers and regional and local companies who may have significant market share in the respective areas in which they operate. Competition among common carrier pipelines is based primarily on posted tariffs, quality of customer service and proximity to refineries, production and connecting pipelines. We believe that high capital costs, tariff regulation and the cost of acquiring rights-of-way make it unlikely that other competing pipeline systems, comparable in size and scope to our onshore pipelines, will be built in the same geographic areas in the near future. In addition, as the majority of our onshore pipelines directly serve refineries we believe that these pipelines are not subject to the same competitive pressures as those tied directly to crude oil 20 Table of Contents production. Additionally, the shipper on our Free State pipeline is required to use our Free State pipeline for any transportation of CO2 within a dedicated area. In our refined products onshore facilities and transportation operations, we compete primarily with regional companies. See "Marine Transportation - Competition" for additional discussion of our competitors. Competitive factors in our onshore facilities and transportation business include price, relationships with customers, range and quality of services, knowledge of products and markets, availability of trade credit and capabilities of risk management systems. Marine Transportation Our marine transportation segment consists of (i) our inland marine fleet which transports heavy refined petroleum products, including asphalt, principally serving refineries and storage terminals along the Gulf Coast, Intracoastal Canal and western river systems of the U.S., principally along the Mississippi River and its tributaries, (ii) our offshore marine fleet which transports crude oil and refined petroleum products, principally serving refineries and storage terminals along the Gulf Coast, Eastern Seaboard, Great Lakes and Caribbean, and (iii) our modern double-hulled, Jones Act qualified tanker M/T American Phoenix which is currently under charter serving a customer along the Gulf Coast and Eastern Seaboard until 2020. The below table includes operational information relating to our marine transportation fleet: Aggregate Fleet Design Capacity (Bbls) (in thousands) Individual Vessel Capacity Range (Bbls) (in thousands) (1) Number of: Push/Tug Boats Barges Product Tankers Inland 2,285 23-39 33 82 — Offshore American Phoenix 884 65-135 9 9 — 330 330 — — 1 (1) Represents capacity per barge ranges on our inland and offshore barge, as well as the capacity of our M/T American Phoenix. Customers Our marine customers are primarily refiners and some large energy companies. Our M/T American Phoenix is currently operating under a long term charter into 2020 with a large refining customer. We are a provider of transportation services for our customers and, in almost all cases, do not assume ownership of the products we transport. Marine transportation services are conducted under term contracts, some of which have renewal options for customers with whom we have traditionally had long-standing relationships, as well as spot contracts. Most have been our customers for many years and we generally anticipate continued relationships; however, there is no assurance that any individual contract will be renewed. A term contract is an agreement with a specific customer to transport cargo from a designated origin to a designated destination at a set rate (affreightment) or at a daily rate (time charter). The rate may or may not escalate during the term of the contract; however, the base rate generally remains constant and contracts often include escalation provisions to recover changes in specific costs such as fuel. Time charters, which insulate us from revenue fluctuations caused by weather and navigational delays and temporary market declines, represented over 95% of our marine transportation revenues under term contracts during 2019 and 2018. A spot contract is an agreement with a customer to move cargo from a specific origin to a designated destination for a rate negotiated at the time the cargo movement takes place. Spot contract rates are at the current “market” rate and are subject to market volatility. We typically maintain a higher mix of term contracts to spot contracts to provide a predictable revenue stream while maintaining spot market exposure to take advantage of new business opportunities and existing customers’ peak demands. During 2019 and 2018, approximately 65% and 62%, respectively, of our marine transportation revenues were from term contracts and 35% and 38%, respectively, were from spot contracts. Revenues from customers of our marine transportation segment did not account for more than ten percent of our consolidated revenues. Competition Our competitors for the marine transportation of crude oil and heavy refined petroleum products are both midstream MLPs with marine transportation divisions, along with companies that are in the business of solely marine transportation operations. Competition among common marine carriers is based on a number of factors including proximity to production, refineries and connecting infrastructures, customer service, and transportation pricing. 21 Table of Contents Our marine transportation segment also competes with other modes of transporting crude oil and heavy refined petroleum products, including pipeline, rail and trucking operations. Each such mode of transportation has different advantages and disadvantages, which often are fact and circumstance dependent. For example, without requiring longer-term economic commitments from shippers, marine and truck transportation can offer shippers much more flexibility to access numerous markets in multiple directions (i.e., pipelines tend to flow in a single direction and are geographically limited by their receipt and delivery points with other pipelines and facilities), and marine transportation offers shippers certain economies of scale as compared to truck transportation. In addition, due to construction costs and timing considerations, marine and truck transportation can provide cost effective and immediate services to a nascent producing region, whereas new pipelines can be very expensive and time consuming to construct and may require shippers to make longer-term economic commitments, such as take-or-pay commitments. On the other hand, in mature developed areas serviced by extensive, multi-directional pipelines, with extensive connections to various market, pipeline transportation may be preferred by shippers, especially if shippers are willing to make longer-term economic commitments, such as take-or-pay commitments. Credit Exposure Due to the nature of our operations, a disproportionate percentage of our trade receivables constitute obligations of refiners, large oil producers and integrated oil companies. This energy industry concentration has the potential to affect our overall exposure to credit risk, either positively or negatively, in that our customers could be affected by similar changes in economic, industry or other conditions. However, we believe that the credit risk posed by this industry concentration is offset by the creditworthiness of our specific customer base in the context of our specific transactions as well as other factors, including the strategic nature of certain of our assets and relationships and our credit procedures. Our portfolio of accounts receivable is generally comprised in large part of obligations of refiners, integrated and large independent oil and natural gas producers, and mining and other industrial companies that purchase NaHS and soda ash, most of which have stable payment histories. The credit risk related to contracts that are traded on the NYMEX is limited due to the daily cash settlement procedures and other NYMEX requirements. When we market crude oil, petroleum products, NaHS, soda ash and provide transportation and other services, we must determine the amount, if any, of the line of credit we will extend to any given customer. We have established procedures to manage our credit exposure, including initial credit approvals, credit limits, collateral requirements and rights of offset. Letters of credit, prepayments and guarantees are also utilized to limit credit risk to ensure that our established credit criteria are met. We use similar procedures to manage our exposure to our customers in the offshore pipeline transportation and marine transportation segments. As a result of our activities in the Gulf of Mexico and onshore (including our Alkali Business), our largest customers include Shell, Exxon Mobil Corporation, BP PLC, Phillips 66, Calumet Specialty Products Partners, L.P., Anadarko Petroleum Corporation (now "Occidental Petroleum" or "Occidental") and ANSAC. Employees To carry out our business activities, we employed approximately 2,200 employees at December 31, 2019. We believe that relationships with our employees are good. Regulation Pipeline Rate and Access Regulation The rates and the terms and conditions of service of our interstate common carrier pipeline operations are subject to regulation by FERC under the Interstate Commerce Act, or ICA. Under the ICA, rates must be “just and reasonable,” and must not be unduly discriminatory or confer any undue preference on any shipper. FERC regulations require that oil pipeline rates and terms and conditions of service for regulated pipelines be filed with FERC and posted publicly. Effective January 1, 1995, FERC promulgated rules simplifying and streamlining the ratemaking process. Previously established rates were “grandfathered,” limiting the challenges that could be made to existing tariff rates. Increases from grandfathered rates of interstate oil pipelines are currently regulated by FERC primarily through an index methodology, whereby a pipeline is allowed to change its rates based on the year-to-year change in an index. Under FERC regulations, we are able to change our rates within prescribed ceiling levels that are tied to the Producer Price Index for Finished Goods. Rate increases made pursuant to the index will be subject to protest, but such protests must show that the rate increase resulting from application of the index is substantially in excess of the applicable pipeline’s increase in costs. In addition to the index methodology, FERC allows for rate changes under three other methods—cost-of-service, competitive market showings and agreements between shippers and the oil pipeline company that the rate is acceptable, or Settlement Rates. The pipeline tariff rates on our Mississippi, Jay, Louisiana, and Wyoming Systems are either rates that are 22 Table of Contents subject to change under the index methodology or Settlement Rates. None of our tariffs have been subjected to a protest or complaint by any shipper or other interested party. Our offshore pipelines, with the exception of our Eugene Island pipeline, are neither interstate nor common carrier pipelines. However, these pipelines are subject to federal regulation under the Outer Continental Shelf Lands Act, which requires all pipelines operating on or across the outer continental shelf to provide nondiscriminatory transportation service. Our intrastate common carrier pipeline operations in Texas are subject to regulation by the Railroad Commission of Texas. The applicable Texas statutes require that pipeline rates and practices be reasonable and non-discriminatory and that pipeline rates provide a fair return on the aggregate value of the property of a common carrier, after providing reasonable allowance for depreciation and other factors and for reasonable operating expenses. Although no assurance can be given that the tariffs we charge would ultimately be upheld if challenged, we believe that the tariffs now in effect can be sustained. Our CO2 pipelines are subject to regulation by the state agencies in the states in which they are located. Marine Regulations Maritime Law. The operation of towboats, tugboats, barges, vessels and marine equipment create maritime obligations involving property, personnel and cargo and are subject to regulation by the U.S. Coast Guard, or USCG, the Environmental Protection Agency, or EPA, the Department of Homeland Security, or DHS, federal laws, state laws and certain international conventions under General Maritime Law. These obligations can create risks which are varied and include, among other things, the risk of collision and allision, which may precipitate claims for personal injury, cargo, contract, pollution, third-party claims and property damages to vessels and facilities. Routine towage operations can also create risk of personal injury under the Jones Act and General Maritime Law, cargo claims involving the quality of a product and delivery, terminal claims, contractual claims and regulatory issues. Federal regulations also require that all tank barges engaged in the transportation of oil and petroleum in the U.S. be double hulled. All of our barges are double-hulled. All of our barges are inspected by the USCG and carry certificates of inspection. All of our towboats and tugboats are certificated by the USCG. Most of our vessels are built to American Bureau of Shipping, or ABS, classification standards and in some instances are inspected periodically by ABS to maintain the vessels in class standards. The crews we employ aboard vessels, including captains, pilots, engineers, tankermen and ordinary seamen, are documented by the USCG. We are required by various governmental agencies to obtain licenses, certificates and permits for our vessels depending upon such factors as the cargo transported, the waters in which the vessels operate and other factors. We are of the opinion that our vessels have obtained and can maintain all required licenses, certificates and permits required by such governmental agencies for the foreseeable future. Jones Act: The Jones Act is a federal law that restricts maritime transportation between locations in the U.S. to vessels built and registered in the U.S. and owned and manned by U.S. citizens. We are responsible for monitoring the ownership of our subsidiary that engages in maritime transportation and for taking any remedial action necessary to insure that no violation of the Jones Act ownership restrictions occurs. Jones Act requirements significantly increase operating costs of U.S.-flag vessel operations compared to foreign-flag vessel operations. Further, the USCG and ABS maintain the most stringent regime of vessel inspection in the world, which tends to result in higher regulatory compliance costs for U.S.-flag operators than for owners of vessels registered under foreign flags or flags of convenience. The Jones Act and General Maritime Law also provide damage remedies for crew members injured in the service of the vessel arising from employer negligence or vessel unseaworthiness. Merchant Marine Act of 1936: The Merchant Marine Act of 1936 is a federal law providing that, upon proclamation by the president of the U.S. of a national emergency or a threat to the national security, the U.S. Secretary of Transportation may requisition or purchase any vessel or other watercraft owned by U.S. citizens (including us, provided that we are considered a U.S. citizen for this purpose). If one of our tow boats or barges were purchased or requisitioned by the U.S. government under this law, we would be entitled to be paid the fair market value of the vessel in the case of a purchase or, in the case of a requisition, the fair market value of charter hire. However, if one of our tow boats is requisitioned or purchased and its associated barge or barges are left idle, we would not be entitled to receive any compensation for the lost revenues resulting from the idled barges. We also would not be entitled to be compensated for any consequential damages we suffer as a result of the requisition or purchase of any of our tow boats or barges. Security Requirements: The Maritime Transportation Security Act of 2002 requires, among other things, submission to and approval by the USCG of vessel and waterfront facility security plans, or VSP. Our VSP’s have been approved and we are operating in compliance with the plans for all of its vessels and that are subject to the requirements, whether engaged in domestic or foreign trade. 23 Table of Contents Railcar Regulation We operate a number of railcar unloading facilities and lease a significant number of railcars. Our railcar operations are subject to the regulatory jurisdiction of the Federal Railroad Administration of the DOT, the Occupational Safety and Health Administration, or OSHA, as well as other federal and state regulatory agencies. We believe that our railcar operations are in substantial compliance with all existing federal, state and local regulations. DOT and OSHA have jurisdiction under several federal statutes over a number of safety and health aspects of rail operations, including the transportation of hazardous materials. State agencies regulate some aspects of rail operations with respect to health and safety in areas not otherwise preempted by federal law. Regulation of the Mining Industry in the United States We have the right to mine trona through leases we hold from the U.S. Federal government, the State of Wyoming and Occidental. Our leases with the U.S. government are issued under the provisions of the Mineral Leasing Act of 1920 (30 U.S.C. 18 et. Seq.) and are administered by the U.S. Bureau of Land Management (“BLM”) and our leases with the state of Wyoming are issued under Wyoming Statutes 36-6-101 et. seq. Occidental is the successor to rights originally granted to the Union Pacific Railroad in connection with the construction of the first transcontinental railroad in North America. For more information please see discussion of Mining and Mineral Tenure in Item 1 below. We pay royalties to the BLM, the State of Wyoming and Occidental. These royalties are calculated based upon the gross value of soda ash and related products at a certain stage in the mining process. We are obligated to pay minimum royalties or annual rentals to our lessors regardless of actual sales and in the case of Occidental to pay royalties in advance based on a formula based on the amount of trona produced and sold in the previous year which is then credited against production royalties owed. The royalty rates we pay to our lessors may change upon our renewal of such leases; however, we anticipate being able to renew all material leases at the appropriate time. In the past, the U.S. Congress has passed legislation to cap royalties collected by BLM at a rate lower than the rate stated in our federal leases. Our mining operations in Wyoming are subject to mine permits issued by the Land Quality Division of the Wyoming Department of Environmental Quality (“WDEQ”). WDEQ imposes detailed reclamation obligations on us as a holder of mine permits. As of December 31, 2019, the amount of our reclamation bond was approximately $80 million. The amount of the bond is subject to change based upon periodic re-evaluation by WDEQ. The health and safety of our employees working underground and on the surface are subject to detailed regulation. The safety of our operations at Westvaco are regulated by the U.S. Mine Safety and Health Administration (“MSHA”) and our Granger Facility by the Wyoming Occupational Safety and Health Administration (“Wyoming OSHA”). MSHA administers the provisions of the Federal Mine Safety and Health Act of 1977 and enforces compliance with that statute’s mandatory safety and health standards. As part of MSHA’s oversight, representatives perform at least four unannounced inspections (approximately once quarterly) each year at Westvaco. Wyoming OSHA regulates the health and safety of non-mining operations under a plan approved by the U.S. Occupational Health and Safety Administration. When our Granger facility was restarted in 2009 on solution mine feed (i.e., without any miners working underground), Wyoming OSHA assumed responsibility for the facility. Regulation of Finished Product Manufacturing Our business is subject to extensive regulation by federal, state, local and foreign governments. Governmental authorities regulate the generation and treatment of waste and air emissions at our operations and facilities. We also comply with worldwide, voluntary standards developed by the International Organization for Standardization (“ISO”), a nongovernmental organization that promotes the development of standards and serves as a bridging organization for quality standards, such as ISO 9001:2015 for quality management and ISO 22000 for food safety management. Several of the production operations in our Alkali Business are subject to regulation by the U.S. Food and Drug Administration (“FDA”). Our sodium bicarbonate plant is a registered facility for the production of food and pharmaceutical grade ingredients and we comply with strict Current Good Manufacturing Practice (“CGMP”) requirements in our operations. The U.S. Food Safety Modernization Act requires that parts of our facility that produce animal nutrition products comply with new more rigorous manufacturing standards. We believe that we materially comply with requirements currently in effect and have a program in place to maintain such compliance. We also comply with industry standards developed by various private organizations such as U.S. Pharmacopeia, Organic Materials Review Institute and the Orthodox Union. Alkali has also sought and received certification of its Wyoming facilities under ISO.9001:2015. Environmental Regulations General We are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may (i) require the acquisition of 24 Table of Contents and compliance with permits for regulated activities, (ii) limit or prohibit operations on environmentally sensitive lands such as wetlands or wilderness area, seismically sensitive areas, or areas inhabited by endangered or threatened species, (iii) result in capital expenditures to limit or prevent emissions or discharges, and (iv) place burdensome restrictions on our operations, including the management and disposal of wastes. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, including the assessment of monetary penalties, the imposition of investigatory and remedial obligations, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and the issuance of orders enjoining future operations or imposing additional compliance requirements. Changes in environmental laws and regulations occur frequently, typically increasing in stringency through time, and any changes that result in more stringent and costly operating restrictions, emission control, waste handling, disposal, cleanup and other environmental requirements have the potential to have a material adverse effect on our operations. While we believe that we are in substantial compliance with current environmental laws and regulations and that continued compliance with existing requirements will not materially affect us, there is no assurance that this trend will continue in the future. Revised or new additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and cash flows. Hazardous Substances and Waste Handling The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, or CERCLA, also known as the “Superfund” law, and analogous state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons. These persons include current owners and operators of the site where a release of hazardous substances occurred, prior owners or operators that owned or operated the site at the time of the release of hazardous substances, and companies that disposed or arranged for the disposal of the hazardous substances found at the site. We currently own or lease, and have in the past owned or leased, properties that have been in use for many years with the gathering and transportation of hydrocarbons including crude oil and other activities that could cause an environmental impact. Persons deemed “responsible persons” under CERCLA may be subject to strict and joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. We also may incur liability under the Resource Conservation and Recovery Act, as amended, or RCRA, and analogous state laws which impose requirements and also liability relating to the management and disposal of solid and hazardous wastes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. Certain petroleum production wastes are excluded from RCRA’s hazardous waste regulations. However, it is possible that these wastes, which could include wastes currently generated during our operations, will in the future be designated as “hazardous wastes” and, therefore, be subject to more rigorous and costly disposal requirements. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain crude oil and natural gas exploration and production wastes as “hazardous wastes.” Also, in December 2016, the EPA agreed in a consent decree to review its regulation of oil and gas waste. However, in April 2019, the EPA concluded that revisions to the federal regulations for the management of oil and gas waste are not necessary at this time. Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses. We believe that we are in substantial compliance with the requirements of CERCLA, RCRA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations required under such laws and regulations. Although we believe that the current costs of managing our wastes as they are presently classified are reflected in our budget, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes. Water Discharges The Federal Water Pollution Control Act, as amended, also known as the “Clean Water Act,” and analogous state laws impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including crude oil, into navigable waters of the U.S., as well as state waters. Permits must be obtained to discharge pollutants into these waters. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. On June 29, 2015, the EPA and the U.S. Army Corps of Engineers, or Corps, jointly promulgated final rules redefining the scope of waters protected under the 25 Table of Contents Clean Water Act. However, on October 22, 2019, the agencies repealed the 2015 rules. Both the 2015 rules and the 2019 repeal are subject to ongoing legal challenges. Also, on January 23, 2020, the EPA and the Corps released a final rule replacing the 2015 rules, and significantly reducing the waters subject to federal regulation under the Clean Water Act. The rule is anticipated to generate further legal challenges. Additionally, on April 23, 2019, the EPA published an interpretive statement and request for comment, clarifying that the Clean Water Act's permitting program for pollutant discharges does not apply to releases of pollutants to groundwater. As a result of such recent developments, substantial uncertainty exists regarding the scope of waters protected under the Clean Water Act. To the extent the rules expand the range of properties subject to the Clean Water Act's jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Also, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. The Oil Pollution Act is the primary federal law for oil spill liability. The Oil Pollution Act contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The Oil Pollution Act subjects owners of facilities to strict liability that, in some circumstances, may be joint and several for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters. Noncompliance with the Clean Water Act or the Oil Pollution Act may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with each of these requirements. Air Emissions The Federal Clean Air Act, or CAA, as amended, and analogous state and local laws and regulations restrict the emission of air pollutants, and impose permit requirements and other obligations. Regulated emissions occur as a result of our operations, including the handling or storage of crude oil and other petroleum products. Both federal and state laws impose substantial penalties for violation of these applicable requirements. Accordingly, our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, revocation or suspension of necessary permits and, potentially, criminal enforcement actions. On August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance standards to address emissions of sulfur dioxide and volatile organic compounds and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rules seek to achieve a 95% reduction in volatile organic compounds emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In response, the EPA has issued, and will likely continue to issue, revised rules responsive to some of the requests for reconsideration. In particular, on May 12, 2016, the EPA amended its regulations to impose new standards for methane and volatile organic compounds emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and natural gas sector. However, in a March 28, 2017 executive order, President Trump directed the EPA to review the 2016 regulations and, if appropriate, to initiate a rulemaking to rescind or revise them consistent with the stated policy of promoting clean and safe development of the nation’s energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production. On October 15, 2018, the EPA published a proposed rule to significantly reduce regulatory burdens imposed by the 2016 regulations, including, for example, reducing the monitoring frequency for fugitive emissions and revising the requirements for pneumatic pumps at well sites. Also, on August 28, 2019, the EPA proposed amendments to the 2012 and 2016 New Source Performance standards to ease regulatory burdens, including rescinding standards applicable to transmission or storage segments and eliminating methane requirements altogether. Legal challenges are anticipated and thus substantial uncertainty exists regarding the scope of New Source Performance standards for oil and natural gas operations. These standards, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions. 26 Table of Contents NEPA Under the National Environmental Policy Act, or NEPA, a federal agency, commonly in conjunction with a current permittee or applicant, may be required to prepare an environmental assessment or a detailed environmental impact statement before taking any major action, including issuing a permit for a pipeline extension or addition that would affect the quality of the environment. Should an environmental impact statement or environmental assessment be required for any proposed pipeline extensions or additions, NEPA may prevent or delay construction or alter the proposed location, design or method of construction. Endangered Species Act The federal Endangered Species Act and analogous state statutes restrict activities that may adversely affect endangered and threatened species or their habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act, though, in December 2017, the U.S. Fish and Wildlife Service provided guidance limiting the reach of the Act. The designation of previously unidentified endangered or threatened species in areas where we operate could cause us to incur additional costs or become subject to operating delays, restrictions or bans. Climate Change In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases ("GHGs") present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Accordingly, in recent years, federal, state, and local governments have taken steps to reduce emissions of GHGs. The EPA has finalized a series of GHG monitoring, reporting and emission control rules for the oil and natural gas industry and the U.S. Congress has from time to time considered various proposals to reduce GHG emissions. Almost half of the states, either individually or through multi-state regional initiatives, have already taken legal measures to reduce GHG emissions, primarily through the planned development of GHG emission inventories and/or GHG cap-and-trade programs. The net effect of this regulatory regime is to impose increasing costs on the combustion of carbon-based fuels such as crude oil, refined petroleum products and natural gas. Our compliance with any future legislation or regulation of GHGs, if it occurs, may result in materially increased compliance and operating costs. In addition, in December 2015, the United States participated in the 21st Conference of the Parties (COP-21) of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of GHGs. The Agreement went into effect on November 4, 2016. The Agreement establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. However, on June 1, 2017, President Trump announced that the United States would withdraw from the Paris Agreement, and begin negotiations to either re-enter or negotiate an entirely new agreement with more favorable terms for the United States. The Paris Agreement sets forth a specific exit process, whereby a party may not provide notice of its withdrawal until three years from the effective date, with such withdrawal taking effect one year from such notice. On November 4, 2019, the Trump Administration submitted its formal notification of withdrawal to the United Nations. It is not clear what steps, if any, will be taken to negotiate a new agreement, or what terms would be included in such an agreement. In response to the withdrawal announcement, many state and local leaders have stated their intent to intensify efforts to uphold the commitments set forth in the international accord. Legislative efforts or related implementation regulations that regulate or restrict emissions of GHGs in areas that we conduct business could adversely affect the demand for the products that we transport, store and distribute and, depending on the particular program adopted, could increase our costs to operate and maintain our facilities by requiring that we, among other things, measure and report our emissions, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay any taxes related to our GHG emissions and administer and manage a GHG emissions program. We may be unable to include some or all of such increased costs in the rates charged by our pipelines or other facilities, and any such recovery may depend on events beyond our control, including the outcome of future rate proceedings before the FERC or state regulatory agencies and the provisions of any final legislation or implementing regulations. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby adversely affect demand for the crude oil and natural gas that we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations. It is not possible at this time to predict with any accuracy the structure or outcome of any future legislative or regulatory efforts to address such emissions or the eventual costs to us of compliance. Furthermore, there have been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and 27 Table of Contents pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. In addition, claims have been made against certain energy companies alleging that GHG emissions from crude oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages, or other liabilities. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could adversely impact our business, financial condition and results of operations. Moreover, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially hotter or colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations. Safety and Security Regulations Our crude oil and CO2 pipelines are subject to construction, installation, operation and safety regulation by the U.S. Department of Transportation, or DOT, and various other federal, state and local agencies. Congress has enacted several pipeline safety acts over the years. Currently, the Pipeline and Hazardous Materials Safety Administration, or PHMSA, under DOT administers pipeline safety requirements for natural gas and hazardous liquid pipelines pursuant to detailed regulations set forth in 49 C.F.R. Parts 190 to 199. These regulations, among other things, address pipeline integrity management and pipeline operator qualification rules. In June 2016, Congress approved new pipeline safety legislation, the “Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016,” or the PIPES Act, which provides the PHMSA with additional authority to address imminent hazards by imposing emergency restrictions, prohibitions, and safety measures on owners and operators of gas or hazardous liquids pipeline facilities. Significant expenses could be incurred in the future if additional safety measures are required or if safety standards are raised and exceed the current pipeline control system capabilities. We are subject to the PHMSA Integrity Management, or IM, regulations, which require that we perform baseline assessments of all pipelines that could affect a High Consequence Area, or HCA, including certain populated areas and environmentally sensitive areas. After completing a baseline assessment, we continue to assess all pipelines at specified intervals and periodically evaluate the integrity of each pipeline segment that could affect a HCA. The integrity of these pipelines must be assessed by internal inspection, pressure test, or equivalent alternative new technology. The IM regulations required us to prepare an Integrity Management Plan, or IMP, that details the risk assessment factors, the overall risk rating for each segment of pipe, a schedule for completing the integrity assessment, the methods to assess pipeline integrity, and an explanation of the assessment methods selected. The regulations also require periodic review of HCA pipeline segments to ensure that adequate preventative and mitigative measures exist and that companies take prompt action to address pipeline integrity issues. No assurance can be given that the cost of testing and the required rehabilitation identified will not be material costs to us that may not be fully recoverable by tariff increases. Recently, the PHMSA adopted additional regulations for natural gas and hazardous liquid pipeline safety. In particular, on October 1, 2019, the PHMSA published final rules to expand its IM requirements and impose new pressure testing requirements on regulated pipelines, including certain segments outside HCAs. Many of the requirements will be phased in over an extended compliance schedule. Once effective, the rules also extend reporting requirements to certain previously unregulated gathering lines. We have developed a Risk Management Plan required by the EPA as part of our IMP. This plan is intended to minimize the offsite consequences of catastrophic spills. As part of this program, we have developed a mapping program. This mapping program identified HCAs and unusually sensitive areas along the pipeline right-of-ways in addition to mapping of shorelines to characterize the potential impact of a spill of crude oil on waterways. Our crude oil, refined products and sodium minerals and sulfur services operations are also subject to the requirements of OSHA and comparable state statutes. Various other federal and state regulations require that we train all operations employees in Hazardous Communication ("HAZCOM") and disclose information about the hazardous materials used in our operations. Certain information must be reported to employees, government agencies and local citizens upon request. In most cases, states are responsible for enforcing the federal regulations and more stringent state pipeline regulations and inspection with respect to intrastate hazardous liquids pipelines, including crude oil, natural gas and CO2 pipelines. In practice, states vary considerably in their authority and capacity to address pipeline safety. The Railroad Commission recently updated its pipeline safety regulations, including regulations pertaining to certain natural gas gathering lines, and hazardous 28 Table of Contents liquids and carbon dioxide pipelines located in a rural area, effective January 6, 2020. We do not anticipate any significant problems in complying with applicable state laws and regulations in those states in which we operate. Our trucking operations are licensed to perform both intrastate and interstate motor carrier services. As a motor carrier, we are subject to certain safety regulations issued by the DOT. The trucking regulations cover, among other things, driver operations, log book maintenance, truck manifest preparations, safety placard placement on the trucks and trailer vehicles, drug and alcohol testing, operation and equipment safety and many other aspects of truck operations. We are also subject to OSHA with respect to our trucking operations. The USCG regulates occupational health standards related to our marine operations. Shore-side operations are subject to the regulations of OSHA and comparable state statutes. The Maritime Transportation Security Act requires, among other things, submission to and approval of the USCG of vessel security plans. Since the terrorist attacks of September 11, 2001, the U.S. Government has issued numerous warnings that energy assets could be the subject of future terrorist attacks. We have instituted security measures and procedures in conformity with federal guidance. We will institute, as appropriate, additional security measures or procedures indicated by the federal government. None of these measures or procedures should be construed as a guarantee that our assets are protected in the event of a terrorist attack. Reporting of Ore Reserve and Mineral Resources As of December 31, 2019, we had estimated mineral ore reserves in our Alkali Business. Our Alkali Business extracts trona, a natural hydrous sodium carbonate mineral used in the production of soda ash in the Green River Basin of southwestern Wyoming, USA. Soda ash, the commercial term for sodium carbonate (Na2CO3), is a basic ingredient in many consumer goods and a raw material used in a diversity of manufacturing processes. U.S. registrants are required to report ore reserves under SEC Industry Guide 7, “Description of Property by Issuers Engaged or To Be Engaged in Significant Mining Operations.” Industry Guide 7 requires that sufficient technical and economic studies have been completed to reasonably assure economic extraction of the declared reserves, based on the parameters and assumptions current to the end of the reporting period. We base our mineral reserve estimates on detailed geological, geotechnical, mine engineering and mineral processing inputs, and financial models developed and reviewed by employees/management of our Alkali Business, who possess years of experience directly related to the resources, mining and processing characteristics or financial performance of our operations. Additionally, our management and technical staff includes senior personnel who have remained closely involved with each of our active mining and mineral processing operations. In preparing our reserve estimates for our Alkali operations at Green River, Wyoming, we follow accepted mining industry practice and are guided by our long-term experience in extraction of trona ore from underground mining and sodium carbonate from solution mining in the district. Estimates of recoverable reserves for both techniques are routinely reconciled with actual production, and our Alkali ore reserves disclosures comply with SEC Industry Guide 7. Under SEC Industry Guide 7, Proven reserves are the highest category of ore reserve estimates, whereby the quantity and quality have been computed from detailed sampling and modeling, while Probable reserves provide slightly lower geologic assurance. Mineral Tenure - Wyoming SEC Industry Guide 7 requires us to describe our rights to access and mine the minerals we report as ore reserves and to disclose any change in mineral tenure of material significance. Our trona mining operations in Wyoming USA are secured through private and federal government leases, regulated by the BLM and WDEQ. All of our exploration and mining operations are subject to multiple levels of environmental regulatory review, that include approvals of environmental programs and public comment periods as pre-conditions to granting of mineral tenure. General descriptions of the rights and regulatory framework for minerals of relevance to Alkali follow here. Ownership of land and minerals relative to trona beds in the Green River Basin of southwestern Wyoming is divided between the Federal Government (56%), Occidental (38%) and the State of Wyoming (6%). Occidental recently acquired Anadarko Petroleum Corporation ("Anadarko"), which was inclusive of the ownership Anadarko acquired in 2000 of the Union Pacific Resources Group (“UPRG”) and included the land and mineral ownership originally granted to UPRG’s parent company, the Union Pacific Railroad in connection with the construction of the first transcontinental railroad in North America. Leasing of Federal minerals under 41 Stat. 437, 30 U.S. Code § 124 (Section 23), “Agricultural entry or purchase of lands withdrawn or classified as containing sodium or sulphur,” is authorized by the Mineral Leasing Act of February 25, 1920, and subsequent amendments. The U.S. Government’s interests are administered by the BLM which has designated an area of 700,000 acres (283,280 hectares) as the Known Sodium Leasing Area (“KSLA”). In 1993, the BLM established a 29 Table of Contents Mechanical Mining Trona Area (“MMTA”) within the KSLA and suspended oil and gas leasing within the boundary. Our mineral tenure and assets at Green River are strengthened by the KSLA and MMTA. Mineral leasing authority by the State of Wyoming is granted in W.S. 36-6-101(b). The primary environmental regulatory authority with respect to trona extraction is the WDEQ. The WDEQ is the primary issuer of the environmental permits relevant to our operations, including air quality permits, mining and reclamation permits, as well as class III and class V underground injection control permits. Alkali Business - Green River, Wyoming Our Alkali Business is one of the world’s leading producers of natural soda ash. Natural soda ash is refined from trona, a sodium carbonate mineral composed of soda ash (Na2CO3), sodium bicarbonate (NaHCO3) and water with the chemical formula Na2CO3NaHCO32H2O. Approximately 60% of the world’s natural soda ash is produced from trona extracted from underground mines and solution mining in the Green River Basin of southwestern Wyoming. The Green River trona beds are collectively the largest deposit of trona and the undisputed largest source of raw material feed for the production of natural soda ash in the world. The origin of the trona deposits is the result of very unusual, geological circumstances. Sodium-rich springs are believed to have fed ancient Lake Gosiute, a large, shallow inland lake that reached a maximum extent of over 15,000 square miles (about 40,000 sq km) around 50 million years ago. In response to repetitive cycles of lake expansion, contraction and evaporation, and changes in temperature and salinity, trona was precipitated in beds of remarkable purity and extent. In addition to trona, the evaporite sodium mineral assemblage includes variable levels of other sodium carbonate minerals as well as halite (NaCl). At least 25 beds of natural trona in the Wilkins Peak Member of the Eocene Green River Formation exceed at least locally three feet (1 m) in thickness and are estimated by the USGS to contain a cumulative resource of over 100 billion tons of trona. Individual trona beds are numbered in ascending order and trona beds of significance lie at modern depths between about 400 to 2,000 feet (120-600 m). Our current dry mining and solution mining operations exploit three trona beds, and our reserves are contained in four beds. Our trona resources and mining operations are held under leases covering 86,997 acres (equivalent to 137 sq miles or 353 sq kilometers) over portions of 23 townships, primarily in two contiguous units informally known as the “Westvaco” and “Granger” blocks. Mineral and mining rights are secured by leases from the Federal government, the State of Wyoming, and Occidental Petroleum. We lease approximately 25,215 acres from the U.S. Government under the Mineral Leasing Act of 1920 (Title 30 §181) which includes trona under its definition of a “solid leasable mineral.” Federal minerals are administered by the U.S. Bureau of Land Management (BLM). We lease 40,819 acres from Occidental, formerly Anadarko Land Corporation. Anadarko’s acquisition of the UPRG in 2000 included alternate sections of land for 20 miles on either side of the trans- continental railroad, originally granted to UPRG under the Pacific Railroad Act of 1862 and subsequent railroad land grants. We also lease 20,963 acres from the State of Wyoming. Royalty payments range from 6% to 8% of the sales value of soda ash products. Our Westvaco site is located approximately 25 miles (40-65 km) north-northwest of Green River. We extract trona ore from our Westvaco underground mine by mechanized, continuous mining methods. Our current underground dry mine production is from a single, near-horizontal bed approximately 10 feet (3.05 meters) thick at a depth from surface of 1500-1600 feet (450-490 meters). Ore is extracted from an extensive network of parallel drifts and connecting cross-cuts, known as room- and-pillar mining, and from longwall mining. Longwall miners shear off successive panels of ore which drops onto a conveyor belt for delivery to vertical shafts to be hoisted to the surface. The Westvaco mine has been in uninterrupted, continuous operation since its start in 1947 by Westvaco Chemical Company. The Westvaco interests were acquired by FMC in 1948. We also extract trona by secondary recovery solution mining operations in previously dry mined portions of the Westvaco mine and in trona beds impacted by former dry mining of the Granger mine. The Granger mine and processing facility, about 10 miles (15 km) northeast of the eponymous town, operated as an underground mine from 1976 to 2002. FMC acquired the properties in 1999 by acquiring Tg Soda Ash, originally developed as a unit of Texasgulf and then owned by Elf Atochem. FMC converted the mine and mill to solution mining in 2005. In our secondary recovery solution mining operations, we pump process waters from our surface facilities, along with insoluble remnant from the processing of dry mined ore, into former underground mine workings where the insoluble constituents settle out and sodium carbonate and bicarbonate are leached from trona left behind from previous dry mining. The return mine water is pumped back to the Westvaco and Granger surface processing facilities for recovery of sodium solids. 30 Table of Contents The following table summarizes the estimated in-place trona ore reserve of our Alkali Business: Mine Deposit Reserve Category Million c tons (dry weight) Grade (% Trona) Dry extraction Dry-mining Solution mining Solution mining Alkali Proven Probable Total Reserves Proven Probable Total Reserves Total Reserves 293.5 158.4 451.9 — 443.5 443.5 895.4 89.7 89.1 89.5 — 86.3 86.3 87.9 Our trona ore reserves are calculated from in-place trona-bearing material that can be economically and legally extracted and processed into commercial products at the time of reserve determination. Our reserves estimates are developed using industry-standard procedures and have been reviewed internally and externally to ensure compliance with SEC Industry Guide 7. Dry mining reserves and solution mining reserves are fundamentally different in terms of extraction methods and costs, predicted recoveries and the procedures used for reserve calculations. We use "measured and indicated" resources as the primary basis in determining our proven and probable reserves. We define proven reserves and probable reserves as follows: • • • Proven dry-mining reserves are measured reserves that fall within a 0.5 mile radius from drillhole data points previously mined areas with a 7.0 ft minimum ore thickness. Probable dry-mining reserves are indicated reserves that fall between 0.5 miles and 1.0 miles from drillhole data points or previously mined areas with a 7.0 ft minimum ore thickness. All solution mining reserves are designated as probable based on the degree of confidence in the reserve estimate related to uncertainties involving solution flow paths, trona ore surface area available for dissolution, and the inaccuracy of depletion verification methods. They consist of both measured resources falling with a 0.5 mile radius from drillhole data points or previously mined areas and indicated resources that fall between 0.5 miles and 1.0 miles from drillhole data points or previously mined areas. Solution mining reserves are not limited to a minimum ore thickness, but rather are subjected to a 50 foot halo limit into large blocks of trona adjacent to areas impacted by previous dry mining and adjacent to areas planned for future dry mining. Estimated dry mining ore reserves of 451.9 million short tons include dilution from un-mineralized material within and marginal to the trona ore bed. We exclude support pillars from dry mining reserves, but a portion of the trona contained in the pillars is recovered by solution mining, as described below. We apply a bulk density factor of 133 lb/cu ft (2.16 g/cc) for conversion of volumes to mass. Key dry mining parameters include minimum trona ore bed thickness and minimum trona grade. Our solution mining ore reserves of 443.5 million short tons are reported on an in-place basis, inclusive of dilution from insoluble material that remains in the ground. The solution mining reserves are calculated using recovery parameters developed from our 20+ years of cumulative secondary recovery solution mining experience. Key factors include the surface area of remaining support pillars and other trona-mineralized surfaces exposed to liquid solutions injected into voids created by dry mining, solubility and alkalinity data, and predicted dissolution rates. Our dry mining reserves have a minimum trona grade of 77.4% and our solution mining reserves have a minimum trona grade of 69.8%. The balance of the ore consists of clays, shales, and other impurities. Dry mined and solution mined trona are refined into soda ash at our Westvaco and Granger facilities, located within the boundaries of their respective contiguous lease blocks, and involve multiple processing lines, steam generation facilities, evaporation ponds, spare parts warehouses, maintenance shops, and offices for engineering, production, and support staff. Our Green River trona mining and processing facilities typically operate at an effective capacity of about four million short tons of marketable soda ash per year. 31 Table of Contents The sum of our total proven and probable reserves estimated as of December 31, 2019, was 895.4 million short tons of trona ore equating to more than 500 million short tons of soda ash, sufficient to sustain production for over 100 years at our current production rates. The economic viability of our reserves is based on our production costs, pricing, and cash flows for 2015-2019. We also apply certain additional assumptions when assessing whether the reserves meet the proven and probably standards and in determining the remaining life of our reserves, including, among other things, that: • • • Annual production capacity remains approximately 4.0 million tons of soda ash per year. The average ore to ash ratio for the stated trona reserves is approximately 1.71:1. Sustaining capital is comparable over time to recent actual costs and short-term projections. • Mining and processing costs including consumption rates for energy and other consumables and the cost of those consumables are substantially comparable to 2015-2019 actual results. • Mine and plant overhead and administration costs remain similar to recent actual performance. • • • • • • • Average selling prices remain the same as the 2015-2019 average as estimated in the January 2020 USGS Mineral Commodity Summary, at approximately $136 per short ton of soda ash, f.o.b. plant site. Bed 15, which lies approximately 35 to 55 feet below bed 17, can be effectively dry mined after the completion of dry mining the overlying areas of Bed 17. All leases remain valid throughout the time required to mine the reserves. All permits remain valid throughout the life of the operation, and no new laws are enacted that require any extraordinary compliance which would significantly impact production or cost. New permits and approved mine plans will be obtained for mining the reserves that lie within existing leases, but outside of our current mining permit areas. Tailings storage capacity will be developed as necessary over the life of the mine and processing plants. Our 2019 reserve disclosure is partially based on the report of a third-party consultant that generated an updated reserve estimate as of September 1, 2017. Our reported reserves reflect that estimate, reconciled with 2017, 2018 and 2019 depletion. Our mine plan is inherently forward-looking, under the meaning of the U.S. Securities Act of 1933 and subsequent amendments and is subject to uncertainties and unanticipated events beyond our control. Available Information We make available free of charge on our internet website (www.genesisenergy.com) our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file the material with, or furnish it to, the SEC. These documents are also available at the SEC’s website (www.sec.gov). Additionally, on our internet website we make available our Corporate Governance Guidelines, Code of Business Conduct and Ethics, Audit Committee Charter and Governance, Compensation and Business Development Committee Charter. Information on our website is not incorporated into this Form 10-K or our other securities filings and is not a part of this Form 10-K or our other securities filings. Item 1A. Risk Factors Risks Related to Our Business Our indebtedness could adversely restrict our ability to operate, affect our financial condition, and prevent us from complying with our requirements under our debt instruments and could prevent us from paying cash distributions to our unitholders. We have outstanding debt and the ability to incur more debt. As of December 31, 2019, we had approximately $1.0 billion outstanding of senior secured indebtedness and an additional $2.5 billion of senior unsecured indebtedness. We must comply with various affirmative and negative covenants contained in our credit agreement and the indentures governing our notes, some of which may restrict the way in which we would like to conduct our business. Among other things, these covenants limit or will limit our ability to: • incur additional indebtedness or liens; 32 Table of Contents • make payments in respect of or redeem or acquire any debt or equity issued by us; • sell assets; • make loans or investments; • make guarantees; • • • enter into any hedging agreement for speculative purposes; acquire or be acquired by other companies; and amend some of our contracts. The restrictions under our indebtedness may prevent us from engaging in certain transactions which might otherwise be considered beneficial to us and could have other important consequences to unitholders. For example, they could: • • • • increase our vulnerability to general adverse economic and industry conditions; limit our ability to make distributions; to fund future working capital, capital expenditures and other general partnership requirements; to engage in future acquisitions, construction or development activities; access capital markets (debt and equity); or to otherwise fully realize the value of our assets and opportunities because of the need to dedicate a substantial portion of our cash flows from operations to payments on our indebtedness or to comply with any restrictive terms of our indebtedness; limit our flexibility in planning for, or reacting to, changes in our businesses and the industries in which we operate; and place us at a competitive disadvantage as compared to our competitors that have less debt. We may incur additional indebtedness (public or private) in the future under our existing credit agreement, by issuing debt instruments, under new credit agreements, under joint venture credit agreements, under new credit agreements of our unrestricted subsidiaries, under capital leases or synthetic leases, on a project-finance or other basis or a combination of any of these. If we incur additional indebtedness in the future, it likely would be under our existing credit agreement or under arrangements that may have terms and conditions at least as restrictive as those contained in our existing credit agreement and the indentures governing our existing notes. Failure to comply with the terms and conditions of any existing or future indebtedness would constitute an event of default. If an event of default occurs, the lenders or noteholders will have the right to accelerate the maturity of such indebtedness and foreclose upon the collateral, if any, securing that indebtedness. In addition, if there is a change of control as described in our credit facility, that would be an event of default, unless our creditors agreed otherwise, and, under our credit facility, any such event could limit our ability to fulfill our obligations under our debt instruments and to make cash distributions to unitholders which could adversely affect the market price of our securities. In addition, from time to time, some of our joint ventures or unrestricted subsidiaries may have substantial indebtedness, which will include affirmative and negative covenants and other provisions that limit their freedom to conduct certain operations, events of default, prepayment and other customary terms. We may not be able to access adequate capital (debt and/or equity) on economically viable terms or any terms. The capital markets (debt and equity) have previously been from time to time disrupted and volatile as a result of adverse conditions, including recessionary pressures, bubble-affects and precipitous commodity price declines. These circumstances and events, which can last for extended periods of time, have led to reduced capital availability, tighter lending standards and higher interest rates on loans for companies in the energy industry, especially non-investment grade companies. Although we cannot predict the future condition of the capital markets, future turmoil in capital markets and the related higher cost of capital could have a material adverse effect on our business, liquidity, financial condition and cash flows, particularly if our ability to borrow money from lenders or access the capital markets to finance our operations were to be impaired for long. If we are unable to access the amounts and types of capital we seek at a cost and/or on terms that have been available to us historically, we could be materially and adversely affected. Such an inability to access capital could limit or prohibit our ability to execute significant portions of our business plan, such as executing our growth strategy, refinancing our debt and/or optimizing our capital structure. We may not be able to fully execute our growth strategy due to various factors, such as unreceptive capital markets and/ or excessive competition for acquisitions. Our strategy contemplates substantial growth through the development and acquisition of a wide range of midstream and other infrastructure and mining assets while maintaining a strong balance sheet. This strategy includes constructing and acquiring additional assets and businesses to enhance our ability to compete effectively, diversify our asset portfolio and, thereby, provide more stable cash flow. We regularly consider and enter into discussions regarding, and are currently contemplating, additional potential joint ventures, stand-alone projects and other transactions that we believe will present opportunities to realize synergies, expand our role in the infrastructure and mining businesses, and increase our market position 33 Table of Contents and, ultimately, increase distributions to unitholders. A number of factors could adversely affect our ability to execute our growth strategy, including an inability to raise adequate capital on acceptable terms, competition from competitors and/or an inability to successfully integrate one or more acquired businesses into our operations. We will need new capital to finance the future development and acquisition of assets and businesses. Limitations on our access to capital will impair our ability to execute this strategy. Expensive capital will limit our ability to develop or acquire accretive assets. Although we intend to continue to expand our business, this strategy may require substantial capital, and we may not be able to raise the necessary funds on satisfactory terms, if at all. In addition, we experience competition for the assets we purchase or contemplate purchasing. Increased competition for a limited pool of assets could result in our not being the successful bidder more often or our acquiring assets at a higher relative price than that which we have paid historically. Either occurrence would limit our ability to fully execute our growth strategy. Our ability to execute our growth strategy may impact the market price of our securities. We may be unable to integrate successfully businesses we acquire. We may incur substantial expenses, delays or other problems in connection with our growth strategy that could negatively impact our results of operations. Moreover, acquisitions and business expansions involve numerous risks, including: • • • difficulties in the assimilation of the operations, technologies, services and products of the acquired companies or business segments; inefficiencies and complexities that can arise because of unfamiliarity with new assets and the businesses associated with them, including unfamiliarity with their markets; and diversion of the attention of management and other personnel from day-to-day business to the development or acquisition of new businesses and other business opportunities. Our actual construction, development and acquisition costs could exceed our forecast, and our cash flow from construction and development projects may not be immediate. Our forecast contemplates significant expenditures for the development, construction or other acquisition of infrastructure and mining assets, including some construction and development projects with technological challenges. We (or our joint ventures) may not be able to complete our projects at the costs or within the timeframes currently estimated. If we (or our joint ventures) experience material cost overruns, we will have to finance these overruns using one or more of the following methods: • • • • using cash from operations; delaying other planned projects; incurring additional indebtedness; or issuing additional debt or equity. Any or all of these methods may not be available when needed or may adversely affect our future results of operations. In addition, some construction projects require substantial investments over a long period of time before they begin generating any meaningful cash flow. Fluctuations in interest rates could adversely affect our business. We have exposure to movements in interest rates. The interest rates on our credit facility ($1.0 billion outstanding at December 31, 2019) are variable. Our results of operations and our cash flow, as well as our access to future capital and our ability to fund our growth strategy, could be adversely affected by significant increases in interest rates. An increase in interest rates may also cause a corresponding decline in demand for equity investments, in general, and in particular, for yield-based equity investments such as our common units. Any such reduction in demand for our common units resulting from other more attractive investment opportunities may cause the trading price of our common units to decline. We may not have sufficient cash from operations to pay the current level of quarterly distribution following the establishment of cash reserves and payment of fees and expenses. The amount of cash we distribute on our common and preferred units principally depends upon margins we generate from our businesses, which fluctuate from quarter to quarter based on, among other things: • • • the volumes and prices at which we purchase and sell crude oil, natural gas, refined products, and caustic soda; the volumes of sodium hydrosulfide, or NaHS, and soda ash that we receive for our sodium minerals and sulfur services and the prices at which we sell NaHS and soda ash; the demand for our services; 34 Table of Contents • • • • • • • • • • • • the level of competition; the level of our operating costs; the effect of worldwide energy conservation measures; governmental regulations and taxes; the level of our general and administrative costs; and prevailing economic conditions. In addition, the actual amount of cash we will have available for distribution will depend on other factors that include: the level of capital expenditures we make, including the cost of acquisitions (if any); our debt service requirements; fluctuations in our working capital; restrictions on distributions contained in our debt instruments or organizational documents governing our joint ventures and unrestricted subsidiaries; our ability to borrow under our working capital facility to pay distributions; and the amount of cash reserves required in the conduct of our business. Our ability to pay distributions each quarter depends primarily on our cash flow, including cash flow from financial reserves and working capital borrowings, and our cash requirements, so it is not solely a function of profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and we may not make distributions during periods when we record net income. Our profitability and cash flow are dependent on our ability to increase or, at a minimum, maintain our current commodity-crude oil, natural gas, refined products, soda ash, NaHS and caustic soda-volumes, which often depend on actions and commitments by parties beyond our control. Our profitability and cash flow are dependent on our ability to increase or, at a minimum, maintain our current commodity-crude oil, natural gas, refined products, soda ash, NaHS, and caustic soda-volumes. We access commodity volumes through various sources, such as our mines, producers, service providers (including gatherers, shippers, marketers and other aggregators) and refiners. Depending on the needs of each customer and the market in which it operates, we can either provide a service for a fee (as in the case of our pipeline, marine vessel and railcar transportation operations), we can acquire the commodity from our customer and resell it to another party, or, in the case of soda ash, we can produce the commodity ourselves. Our source of volumes depends on successful exploration and development of additional crude oil and natural gas reserves by others; our successful development of our trona reserves, continued demand for refining and our related sulfur removal and other services, for which we are paid in NaHS; the breadth and depth of our logistics operations; the extent that third parties provide NaHS for resale; and other matters beyond our control. The crude oil, natural gas and refined products available to us and our refinery customers are derived from reserves produced from existing wells, and these reserves naturally decline over time. In order to offset this natural decline, our energy infrastructure assets must access additional reserves. Additionally, some of the projects we have planned or recently completed are dependent on reserves that we expect to be produced from newly discovered properties that producers are currently developing. Finding and developing new reserves is very expensive, requiring large capital expenditures by producers for exploration and development drilling, installing production facilities and constructing pipeline extensions to reach new wells. Many economic and business factors out of our control can adversely affect the decision by any producer to explore for and develop new reserves. These factors include the prevailing market price of the commodity, the capital budgets of producers, the depletion rate of existing reservoirs, the success of new wells drilled, environmental concerns, regulatory initiatives, cost and availability of equipment, capital budget limitations or the lack of available capital and other matters beyond our control. Additional reserves, if discovered, may not be developed in the near future or at all. The precipitous decline in crude oil and natural gas prices over the last five years has forced some producers to significantly curtail their planned capital expenditures. Thus, crude oil and natural gas production in our market areas could decline, which could have a material negative impact on our revenues and prospects. Demand for our services is dependent on the demand for crude oil and natural gas. Any decrease in demand for crude oil or natural gas, including by those refineries or connecting carriers to which we deliver could adversely affect our cash flows. The demand for crude oil also is dependent on the competition from refineries, the impact of future economic conditions, fuel conservation measures, alternative fuel requirements or alternative fuel sources such as electricity, coal, fuel oils or nuclear energy, government regulation or technological advances in fuel economy and energy generation devices, all of which could 35 Table of Contents reduce demand for our services. A reduction in demand for our services in the markets we serve could result in impairments of our assets and have a material adverse effect on our business, financial condition and results of operations. Our ability to access NaHS depends primarily on the demand for our proprietary sulfur removal process. Demand for our services could be adversely affected by many factors, including lower refinery utilization rates, U.S. refineries accessing more “sweet” (instead of "sour") crude, and the development of alternative sulfur removal processes that might be more economically beneficial to refiners. We are dependent on third parties for NaOH for use in our sulfur removal process as well as volume to market to third parties. Should regulatory requirements or operational difficulties disrupt the manufacture of caustic soda by these producers, we could be affected. Our sulfur removal operations are dependent upon the supply of caustic soda, the demand for NaHS, and the continuing operations of the refiners for whom we process sour natural gas. Caustic soda is a major component of the proprietary sulfur removal process we provide to our refinery customers. Because we are a large consumer of caustic soda, we can leverage our economies of scale and logistics capabilities to effectively market caustic soda to third parties. NaHS, the resulting by-product from our sulfur removal operations, is a vital ingredient in a number of industrial and consumer products and processes. Any decrease in the supply of caustic soda could affect our ability to provide sulfur removal services to refiners and any decrease in the demand for NaHS by the parties to whom we sell the NaHS could adversely affect our business. Refineries’ need for our sulfur removal services is also dependent on refining competition from other refineries by refiners to process more “sweet” (instead of sour) crude, the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, government regulation or technological advances in fuel economy and energy generation devices, all of which could reduce demand for our services. Our crude oil and natural gas transportation operations are dependent upon demand for crude oil by refiners, primarily in the Midwest and Gulf Coast, and the demand for natural gas. Any decrease in this demand for crude oil by those refineries or connecting carriers to which, or for the natural gas, we deliver could adversely affect our cash flows. Those refineries’ demand for crude oil also is dependent on the competition from other refineries, the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, government regulation or technological advances in fuel economy and energy generation devices, all of which could reduce demand for our services. The demand for natural gas is dependent on the impact of future economic conditions, fuel conservation measures, alternative fuel requirements and alternative fuel sources such as electricity, coal, fuel oils or nuclear energy, government regulation or technological advances in fuel economy and energy generation devices, all of which could reduce demand for our services. We face intense competition to obtain crude oil, natural gas and refined products volumes. Our competitors-gatherers, transporters, marketers, brokers and other aggregators-include integrated, large and small independent energy companies, as well as their marketing affiliates, who vary widely in size, financial resources and experience. Some of these competitors have capital resources many times greater than ours and control substantially greater supplies of crude oil, natural gas and refined products. Even if reserves exist or refined products are produced in the areas accessed by our facilities, we may not be chosen by the refiners or producers to gather, refine, market, transport, store or otherwise handle any of these crude oil and natural gas reserves, NaHS, caustic soda, soda ash or other refined products. We compete with others for any such volumes on the basis of many factors, including: • • • • • • • • geographic proximity to the production and/or refineries; costs of connection; available capacity; rates; logistical efficiency in all of our operations; operational efficiency in our sulfur removal business; customer relationships; and access to markets. Additionally, on our onshore pipelines most of our third-party shippers do not have long-term contractual commitments to ship crude oil on our pipelines. A decision by a shipper to substantially reduce or cease to ship volumes of crude oil on our pipelines could cause a significant decline in our revenues. In Mississippi, we are dependent on interconnections with other pipelines to provide shippers with a market for their crude oil, and in Texas, we are dependent on interconnections with other pipelines to provide shippers with transportation to our pipeline. Any reduction of throughput 36 Table of Contents available to our shippers on these interconnecting pipelines as a result of testing, pipeline repair, reduced operating pressures or other causes could result in reduced throughput on our pipelines that would adversely affect our cash flows and results of operations. Fluctuations in demand for crude oil or natural gas or availability of refined products or NaHS, such as those caused by refinery downtime or shutdowns, can negatively affect our operating results. Reduced demand in areas we service with our pipelines, marine vessels, rail facilities and trucks can result in less demand for our transportation services. Many of our crude oil and natural gas transportation customers are producers whose drilling activity levels and spending for transportation have been, and may continue to be, impacted by the deterioration in the commodity markets. Many of our customers finance their drilling activities through cash flow from operations, the incurrence of debt or the issuance of equity. New credit facilities and other debt financing from institutional sources have generally become more difficult and expensive to obtain, and there may be a general reduction in the amount of credit available in the markets in which we conduct business. Additionally, many of our customers’ equity values have substantially declined. Adverse price changes put downward pressure on drilling budgets for crude oil and natural gas producers, which have resulted, and could continue to result, in lower volumes than we otherwise would have seen being transported on our pipeline and transportation systems, which could have a material negative impact on our revenues and prospects. For example, prices for crude oil declined precipitously in the second half of 2014 from approximately $109 per barrel in June 2014 to approximately $30 per barrel in January 2016 and settled to approximately $61 per barrel as of the end of December 2019, and such volatility may continue going forward. Fluctuations in prices for crude oil, refined petroleum products, NaHS, soda ash and caustic soda could adversely affect our business. Because we purchase (or otherwise acquire) and sell crude oil, refined petroleum products, NaHS soda ash and caustic soda we are exposed to some direct commodity price risks. Prices for those commodities can fluctuate in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control, which could have an adverse effect on our cash flows, profit and/or Segment Margin. We attempt to limit those commodity price risks through back-to-back purchases and sales, hedges and other contractual arrangements; however, we cannot completely eliminate our commodity price risk exposure. Our use of derivative financial instruments could result in financial losses. We use derivative financial instruments and other hedging mechanisms from time to time to limit a portion of the effects resulting from changes in commodity prices. To the extent we hedge our commodity price exposure, we forego the benefits we would otherwise experience if commodity prices were to increase. In addition, we could experience losses resulting from our hedging and other derivative positions. Such losses could occur under various circumstances, including if our counterparty does not perform its obligations under the hedge arrangement, our hedge is imperfect, or our hedging policies and procedures are not followed. Non-utilization of certain assets could significantly reduce our profitability due to the fixed costs incurred with respect to such assets. From time to time in connection with our business, we may lease or otherwise secure the right to use certain third party assets (such as railcars, trucks, barges, pipeline capacity, storage capacity and other similar assets) with the expectation that the revenues we generate through the use of such assets will be greater than the fixed costs we incur pursuant to the applicable leases or other arrangements. However, when such assets are not utilized or are under-utilized, our profitability is negatively affected because the revenues we earn are either non-existent or reduced (in the event of under-utilization), but we remain obligated to continue paying any applicable fixed charges, in addition to incurring any other costs attributable to the non-utilization of such assets. For example, in connection with our rail operations, we lease all of our railcars that obligate us to pay the applicable lease rate without regard to utilization. If business conditions are such that we do not utilize a portion of our leased assets for any period of time, we will still be obligated to pay the applicable fixed lease rate. In addition, during the period of time that we are not utilizing such assets, we will incur incremental costs associated with the cost of storing such assets, and we will continue to incur costs for maintenance and upkeep. Our failure to utilize a significant portion of our leased assets and other similar assets could have a significant negative impact on our profitability and cash flows. In addition, certain of our field and pipeline operating costs and expenses are fixed and do not vary with the volumes we gather and transport. These costs and expenses may not decrease ratably or at all should we experience a reduction in our volumes transported by truck, marine vessel or rail or transported by our pipelines. As a result, we may experience declines in our margin and profitability if our volumes decrease. 37 Table of Contents We cannot cause our joint ventures and certain of our unrestricted subsidiaries to take or not to take certain actions unless some or all of the joint venture or third party participants agree. Due to the nature of joint ventures, each participant (including us) in our material joint ventures has made substantial investments (including contributions and other commitments) in that joint venture and, accordingly, has required that the relevant charter documents contain certain features designed to provide each participant with the opportunity to participate in the management of the joint venture and to protect its investment in that joint venture, as well as any other assets which may be substantially dependent on or otherwise affected by the activities of that joint venture. These participation and protective features include a governance structure that consists of a management committee composed of members, only some of which are appointed by us. In addition, many of our joint ventures are operated by our “partners” and have “stand-alone” credit agreements that limit their freedom to take certain actions. Thus, without the concurrence of the other joint venture participants and/or the lenders of our joint venture participants, we cannot cause our joint ventures to take or not to take certain actions, even though those actions may be in the best interest of the joint ventures or us. Similarly, third parties that invested in Alkali Holdings' equity have required that Alkali Holdings' governing documents contain certain features designed to protect their investment. These features include a governance structure that consists of a board of managers composed of members, only a majority of which are appointed solely by us. Certain fundamental decisions of Alkali Holdings may require consent of the full board of managers and, thus, without the concurrence of one of more third parties, we cannot cause Alkali Holdings to take or not to take certain fundamental actions, even though those actions may be in the best interest of Alkali Holdings or us. The insolvency of an operator of our joint ventures, the failure of an operator of our joint ventures to adequately perform operations or an operator’s breach of applicable agreements could reduce our revenue and result in our liability to governmental authorities for compliance with environmental, safety and other regulatory requirements and to the operator’s suppliers and vendors. As a result, the success and timing of development activities of our joint ventures operated by others and the economic results derived therefrom depends upon a number of factors outside our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, and the inclusion of other participants. In addition, joint venture participants may have obligations that are important to the success of the joint venture, such as the obligation to pay their share of capital and other costs of the joint venture. The third party equity investors in Alkali Holdings have obligations to invest additional capital in Alkali Holdings, subject to certain conditions. The performance and ability of third parties to satisfy their obligations under joint venture arrangements and Alkali Holdings' governing documents is outside our control. If these third parties do not satisfy their obligations under these arrangements, our business may be adversely affected. We are exposed to the credit risk of our customers in the ordinary course of our business activities. When we (or our joint ventures) market our products or services, we (or our joint ventures) must determine the amount, if any, of the line of credit. Since certain transactions can involve very large payments, the risk of nonpayment and nonperformance by customers, industry participants and others is an important consideration in our business. For example, in those cases where we provide division order services for crude oil and natural gas purchased at the wellhead, we may be responsible for distribution of proceeds to all of the interest owners. In other cases, we pay all of or a portion of the production proceeds to an operator who distributes these proceeds to the various interest owners. These arrangements expose us to operator credit risk. As a result, we must determine that operators have sufficient financial resources to make such payments and distributions and to indemnify and defend us in case of a protest, action or complaint. Additionally, we sell NaHS, soda ash and caustic soda to customers in a variety of industries. Some of these customers are in industries that have been impacted by a decline in demand for their products and services. Even if our credit review and analytical procedures work properly, we have experienced, and we could continue to experience losses in dealings with other parties. We, along with two other U.S. trona-based soda producers, utilize ANSAC as our exclusive export vehicle for sales to customers in all countries excluding Canada, South Africa and members of the European Community and European Free Trade Area. Because ANSAC makes sales to its end customers directly and then allocates a portion of such sales to each member, we do not have direct access to ANSAC's customers and we have no direct control over the credit or other terms ANSAC extends to its customers. As a result, we are indirectly exposed to ANSAC's customer relationship and the credit and other terms ANSAC extends to its customers. In addition, if ANSAC ceased to exist, we could face costs and risks of securing those customers and related logistics arrangements on favorable terms. Further, many of our customers were impacted by the weakened economic conditions, and precipitous decline in commodity prices, such as crude oil, natural gas, copper, molybdenum, and aluminum experienced in recent years in a manner that influenced the need for our products and services and their ability to pay us for those products and services. It is uncertain if commodity prices will increase in the near future. 38 Table of Contents We may not be able to renew our marine transportation time charters and contracts when they expire at favorable rates, for extended periods, or at all, which may increase our exposure to the spot market and lead to lower revenues and increased expenses. During the year ended December 31, 2019, our marine transportation segment received approximately 65% of its revenue from time charters and other fixed contracts, which help to insulate us from revenue fluctuations caused by weather, navigational delays and short-term market declines. We earned approximately 35% of our marine transportation revenues from spot contracts, where competition is high and rates are typically volatile and subject to short-term market fluctuations, and where we bear the risk of vessel downtime due to weather and navigational delays. If we deploy a greater percentage of our vessels in the spot market, we may experience a lower overall utilization of our fleet through waiting time or ballast voyages, leading to a decline in our operating revenue and gross profit. There can be no assurance that we will be able to enter into future time charters or other fixed contracts on terms favorable to us. For further discussion of our marine transportation contracts, see “Marine Transportation - Customers”. Our operations are subject to federal, state and local environmental protection and safety laws and regulations. Our operations are subject to the risk of incurring substantial environmental and safety related costs and liabilities. In particular, our operations are subject to stringent federal, state and local environmental protection and safety laws and regulations. These laws and regulations may (i) require the acquisition of and compliance with permits for regulated activities, (ii) limit or prohibit operations on environmentally sensitive lands such as wetlands or wilderness areas, seismically sensitive areas, or areas inhabited by endangered or threatened species, (iii) result in capital expenditures to limit or prevent emissions or discharges, and (iv) place burdensome restrictions on our operations, including the management and disposal of wastes. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, including the assessment of monetary penalties, the imposition of investigatory and remedial obligations, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and the issuance of orders enjoining future operations or imposing additional compliance requirements. Changes in environmental laws and regulations occur frequently, typically increasing in stringency through time, and any changes that result in more stringent and costly operating restrictions, emission control, waste handling, disposal, cleanup and other environmental requirements have the potential to have a material adverse effect on our operations. While we believe that we are in substantial compliance with current environmental laws and regulations and that continued compliance with existing requirements would not materially affect us, there is no assurance that this trend will continue in the future. Revised or new additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and cash flows. Moreover, our operations, including the transportation and storage of crude oil, natural gas and other commodities, involves a risk that crude oil, natural gas and related hydrocarbons or other substances may be released into the environment, which may result in substantial expenditures for a response action, significant government penalties, liability to government agencies for natural resources damages, liability to private parties for personal injury or property damages, and significant business interruption. These costs and liabilities could rise under increasingly strict environmental and safety laws, including regulations and enforcement policies, or claims for damages to property or persons resulting from our operations. If we are unable to recover such resulting costs through increased rates or insurance reimbursements, our cash flows and distributions to our unitholders could be materially affected. See “Regulation - Environmental Regulations” for additional discussion of environmental laws and regulations affecting our operations. Climate change legislation and regulatory initiatives may decrease demand for the products we store, transport and sell and increase our operating costs. In recent years, federal, state, and local governments have taken steps to reduce emissions of GHGs. The EPA has finalized a series of GHG monitoring, reporting, and emission control rules for the oil and natural gas industry, and the U.S. Congress has, from time to time, considered various proposals to reduce GHG emissions. Almost half of the states, either individually or through multi-state regional initiatives, have already taken legal measures to reduce GHG emissions, primarily through the planned development of GHG emission inventories and/or GHG cap-and-trade programs. While we are subject to certain federal GHG monitoring, reporting and emission control rules, our operations are not adversely and materially impacted by existing federal, state and local climate change initiatives. However, our compliance with any future legislation or regulation of GHGs, if it occurs, may result in materially increased compliance and operating costs. In addition, in December 2015, the United States participated in the 21st Conference of the Parties, or COP-21, of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of GHGs. The Agreement went into effect on November 4, 2016. The Agreement establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. However, on June 1, 2017, President Trump announced that the United States would withdraw from the Paris Agreement, and begin negotiations to either re-enter or negotiate an entirely new 39 Table of Contents agreement with more favorable terms for the United States. The Paris Agreement sets forth a specific exit process, whereby a party may not provide notice of its withdrawal until three years from the effective date, with such withdrawal taking effect one year from such notice. On November 4, 2019, the Trump Administration submitted its formal notification of withdrawal to the United Nations. It is not clear what steps, if any, will be taken to negotiate a new agreement, or what terms would be included in such an agreement. In response to the withdrawal announcement, many state and local leaders have stated their intent to intensify efforts to uphold the commitments set forth in the international accord. Efforts to regulate or restrict emissions of GHGs in areas that we conduct business could adversely affect the demand for the products that we transport, store and distribute and, depending on the particular program adopted, could increase our costs to operate and maintain our facilities by requiring that we, among other things, measure and report our emissions, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay any taxes related to our GHG emissions and administer and manage a GHG emissions program. We may be unable to include some or all of such increased costs in the rates charged by our pipelines or other facilities, and any such recovery may depend on events beyond our control, including the outcome of future rate proceedings before the FERC or state regulatory agencies and the provisions of any final legislation or implementing regulations. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby adversely affect demand for the crude oil and natural gas that we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations. It is not possible at this time to predict with any accuracy the structure or outcome of any future legislative or regulatory efforts to address such emissions or the eventual costs to us of compliance. Furthermore, there have been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. In addition, claims have been made against certain energy companies alleging that GHG emissions from crude oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages, or other liabilities. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could adversely impact our business, financial condition and results of operations. Moreover, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially hotter or colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations. Restrictions on drilling or mining activities to protect certain species of wildlife could adversely affect our business. The federal Endangered Species Act and analogous state statutes restrict activities that may adversely affect endangered and threatened species or their habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act, though, in December 2017, the U.S. Fish and Wildlife Service provided guidance limiting the reach of the Act. The designation of previously unidentified endangered or threatened species in areas where we operate could cause us to incur additional costs or become subject to operating delays, restrictions or bans. We have reclamation and mine closing obligations. If the assumptions underlying our accruals are inaccurate, we could be required to expend greater amounts than anticipated. Our mining operations in Wyoming are subject to mine permits issued by the Land Quality Division of the Wyoming Department of Environmental Quality (“WDEQ”). WDEQ imposes detailed reclamation obligations on us as a holder of mine permits. We accrue for the costs of current mine disturbance and of final mine closure. The amounts recorded are dependent upon a number of variables, including the estimated future closure costs, estimated proven reserves, assumptions involving profit margins, inflation rates and the assumed credit-adjusted risk-free interest rates. If these accruals are insufficient or our liability in a particular year is greater than currently anticipated, our future operating results could be materially adversely affected. Failure to obtain or renew surety bonds on acceptable terms could affect our ability to secure reclamation obligations and, therefore, our ability to conduct our mining operations. We are required to obtain surety bonds or post other financial security to secure performance or payment of certain long-term obligations, such as mine closure or reclamation costs. The amount of security required to be obtained can change as 40 Table of Contents the result of new laws, as well as changes to the factors used to calculate the bonding or security amounts. We may have difficulty procuring or maintaining our surety bonds. Our bond issuers may demand higher fees or additional collateral, including letters of credit or other terms less favorable to us upon those renewals. Because we are required to have these bonds or other acceptable security in place before mining can commence or continue, our failure to maintain surety bonds, letters of credit or other guarantees or security arrangements would materially and adversely affect our ability to mine trona. That failure could result from a variety of factors, including lack of availability, higher expense or unfavorable market terms, the exercise by third-party surety bond issuers of their right to refuse to renew the surety and restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of our financing arrangements. Regulation of the rates, terms and conditions of services and a changing regulatory environment could affect our financial position, results of operations or cash flow. FERC regulates certain of our energy infrastructure assets engaged in interstate operations. Our intrastate pipeline operations are regulated by state agencies. Our railcar operations are subject to the regulatory jurisdiction of the Federal Railroad Administration of the DOT, the Occupational Safety and Health Administration, as well as other federal and state regulatory agencies. This regulation extends to such matters as: • • • • • • rate structures; rates of return on equity; recovery of costs; the services that our regulated assets are permitted to perform; the acquisition, construction and disposition of assets; and to an extent, the level of competition in that regulated industry. In addition, some of our pipelines and other infrastructure are subject to laws providing for open and/or non- discriminatory access. Given the extent of this regulation, the evolving nature of federal and state regulation and the possibility for additional changes, the current regulatory regime may change and affect our financial position, results of operations or cash flow. A natural disaster, pandemic, epidemic, accident, terrorist attack or other interruption event could result in an economic slowdown, severe personal injury, property damage and/or environmental damage, which could curtail our operations or otherwise adversely affect our assets and cash flow. Some of our operations involve significant risks of severe personal injury, property damage and environmental damage, any of which could curtail our operations or otherwise expose us to liability and adversely affect our cash flow. Virtually all of our operations are exposed to the elements, including hurricanes, tornadoes, storms, floods and earthquakes. A significant portion of our operations are located along the U.S. Gulf Coast, and our offshore pipelines are located in the Gulf of Mexico. These areas can be subject to hurricanes. If one or more facilities that are owned by us or that connect to us or our customers is damaged or otherwise affected by severe weather or any other disaster, pandemic, epidemic, accident, catastrophe or event, our operations could be significantly interrupted. Similar interruptions could result from damage to production or other facilities that supply our facilities or other stoppages arising from factors beyond our control. These interruptions might involve significant damage to people, property or the environment, and repairs or recovery might take from a week or less for a minor incident to six months or more for a major interruption. Any event that interrupts the fees generated by our energy infrastructure assets, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying our interest obligations as well as unitholder distributions and, accordingly, adversely impact the market price of our securities. Additionally, the proceeds of any property insurance maintained by us may not be paid in a timely manner or be in an amount sufficient to meet our needs if such an event were to occur, and we may not be able to renew it or obtain other desirable insurance on commercially reasonable terms, if at all. On September 11, 2001, the U.S. was the target of terrorist attacks of unprecedented scale. Since the September 11 attacks, the U.S. government has issued warnings that energy assets, specifically the nation’s pipeline infrastructure, may be the future targets of terrorist organizations. These developments have subjected our operations to increased risks. Any future terrorist attack at our facilities, those of our customers and, in some cases, those of other pipelines, could have a material adverse effect on our business. In addition, a natural disaster, pandemic, epidemic, accident, terrorist attack or other interruption event may cause significant volatility in global financial markets, disruptions to commerce and reduced economic activity. The resulting macroeconomic conditions could adversely affect our cash flows, as well as the market price of our securities. 41 Table of Contents Our business could be negatively impacted by security threats, including cybersecurity threats, and related disruptions. We rely on our information technology infrastructure to process, transmit and store electronic information, including information we use to safely operate our assets. While we believe that we maintain appropriate information security policies and protocols, we face cybersecurity and other security threats to our information technology infrastructure, which could include threats to our operational and safety systems that operate our pipelines, facilities and other assets. We could face unlawful attempts to gain access to our information technology infrastructure, including coordinated attacks from hackers, whether state-sponsored groups, “hacktivists,” or private individuals. The age, operating systems or condition of our current information technology infrastructure and software assets and our ability to maintain and upgrade such assets could affect our ability to resist cybersecurity threats. Our information technology infrastructure is critical to the efficient operation of our business and essential to our ability to perform day-to-day operations. Breaches in our information technology infrastructure or physical facilities, or other disruptions, could result in damage to our assets, loss of intellectual property, impairment of our ability to conduct our operations, disruption of our customers’ operations, loss or damage to our customer data delivery systems, safety incidents, damage to the environment and could have a material adverse effect on our operations, financial position and results of operations. It is also possible that breaches to our systems could go unnoticed for some period of time. Our business would be adversely affected if we failed to comply with the Jones Act foreign ownership provisions. We are subject to the Jones Act and other federal laws that restrict maritime cargo transportation between points in the U.S. only to vessels operating under the U.S. flag, built in the U.S., at least 75% owned and operated by U.S. citizens (or owned and operated by other entities meeting U.S. citizenship requirements to own vessels operating in the U.S. coastwise trade and, in the case of limited partnerships, where the general partner meets U.S. citizenship requirements) and manned by U.S. crews. To maintain our privilege of operating vessels in the Jones Act trade, we must maintain U.S. citizen status for Jones Act purposes. To ensure compliance with the Jones Act, we must be U.S. citizens qualified to document vessels for coastwise trade. We could cease being a U.S. citizen if certain events were to occur, including if non-U.S. citizens were to own 25% or more of our equity interest or were otherwise deemed to control us or our general partner. We are responsible for monitoring ownership to ensure compliance with the Jones Act. The consequences of our failure to comply with the Jones Act provisions on coastwise trade, including failing to qualify as a U.S. citizen, would have an adverse effect on us as we may be prohibited from operating our vessels in the U.S. coastwise trade or, under certain circumstances, permanently lose U.S. coastwise trading rights or be subject to fines or forfeiture of our vessels. Our business would be adversely affected if the Jones Act provisions on coastwise trade or international trade agreements were modified or repealed or as a result of modifications to existing legislation or regulations governing the crude oil and natural gas industry in response to the recent lifting of the crude oil export ban and the Deepwater Horizon drilling rig incident in the U.S. Gulf of Mexico and subsequent crude oil spill. If the restrictions contained in the Jones Act were repealed or altered or certain international trade agreements were changed, the maritime transportation of cargo between U.S. ports could be opened to foreign flag or foreign-built vessels. The Secretary of the Department of Homeland Security, or the Secretary, is vested with the authority and discretion to waive the coastwise laws if the Secretary deems that such action is necessary in the interest of national defense. Any waiver of the coastwise laws, whether in response to natural disasters or otherwise, could result in increased competition from foreign product carrier and barge operators, which could reduce our revenues and cash available for distribution. In December 2015, Congress voted to lift the four decade crude oil export ban. Increased exports of U.S. crude oil may lead to increased calls to repeal or modify the Jones Act. Even before lifting the export ban, in the past several years, interest groups have lobbied Congress to repeal or modify the Jones Act to facilitate foreign-flag competition for trades and cargoes currently reserved for U.S. flag vessels under the Jones Act. Foreign-flag vessels generally have lower construction costs and generally operate at significantly lower costs than we do in U.S. markets, which would likely result in reduced charter rates. We believe that continued efforts will be made to modify or repeal the Jones Act. If these efforts are successful, foreign- flag vessels could be permitted to trade in the U.S. coastwise trade and significantly increase competition with our fleet, which could have an adverse effect on our business. Events within the crude oil and natural gas industry, such as the April 2010 fire and explosion on the Deepwater Horizon drilling rig in the U.S. Gulf of Mexico and the resulting crude oil spill and moratorium on certain drilling activities in the U.S. Gulf of Mexico implemented by the Bureau of Ocean Energy Management, Regulation and Enforcement (formerly, the Minerals Management Service), may adversely affect our customers’ operations and, consequently, our operations. Such events may also subject companies operating in the crude oil and natural gas industry, including us, to additional regulatory scrutiny and result in additional regulations and restrictions adversely affecting the U.S. crude oil and natural gas industry. 42 Table of Contents A decrease in the cost of importing refined petroleum products could cause demand for U.S. flag product carrier and barge capacity and charter rates to decline, which would decrease our revenues and our ability to pay cash distributions on our units. The demand for U.S. flag product carriers and barges is influenced by the cost of importing refined petroleum products. Historically, charter rates for vessels qualified to participate in the U.S. coastwise trade under the Jones Act have been higher than charter rates for foreign flag vessels. This is due to the higher construction and operating costs of U.S. flag vessels under the Jones Act requirements that such vessels be built in the U.S. and manned by U.S. crews. This has made it less expensive for certain areas of the U.S. that are underserved by pipelines or which lack local refining capacity, such as in the Northeast, to import refined petroleum products carried aboard foreign flag vessels than to obtain them from U.S. refineries. If the cost of importing refined petroleum products decreases to the extent that it becomes less expensive to import refined petroleum products to other regions of the East Coast and the West Coast than producing such products in the U.S. and transporting them on U.S. flag vessels, demand for our vessels and the charter rates for them could decrease. We face periodic dry-docking costs for our vessels, which can be substantial. Vessels must be dry-docked periodically for regulatory compliance and for maintenance and repair. Our dry-docking requirements are subject to associated risks, including delay, cost overruns, lack of necessary equipment, unforeseen engineering problems, employee strikes or other work stoppages, unanticipated cost increases, inability to obtain necessary certifications and approvals and shortages of materials or skilled labor. A significant delay in dry-dockings could have an adverse effect on our marine transportation contract commitments. The cost of repairs and renewals required at each dry-dock are difficult to predict with certainty and can be substantial. The U.S. inland waterway infrastructure is aging and may result in increased costs and disruptions to our marine transportation segment. Maintenance of the U.S. inland waterway system is vital to our marine transportation operations. The system is composed of over 12,000 miles of commercially navigable waterway, supported by over 240 locks and dams designed to provide flood control, maintain pool levels of water in certain areas of the country and facilitate navigation on the inland river system. The U.S. inland waterway infrastructure is aging, with more than half of the locks over 50 years old. As a result, due to the age of the locks, scheduled and unscheduled maintenance outages may be more frequent in nature, resulting in delays and additional operating expenses. Failure of the federal government to adequately fund infrastructure maintenance and improvements in the future would have a negative impact on our ability to deliver products for its marine transportation customers on a timely basis. Risks Related to Our Partnership Structure Our significant unitholders may sell units or other limited partner interests in the trading market, which could reduce the market price of common units. As of December 31, 2019, we have a number of significant unitholders. For example, certain members of the Davison family (including their affiliates) and management owned approximately 17 million or 13.7% of our common units. From time to time, we also may have other unitholders that have large positions in our common units. In the future, any such parties may acquire additional interest or dispose of some or all of their interest. If they dispose of a substantial portion of their interest in the trading markets, such sales could reduce the market price of common units. In connection with certain transactions, we have put in place resale shelf registration statements, which allow unit holders thereunder to sell their common units at any time (subject to certain restrictions) and to include those securities in any equity offering we consummate for our own account. Individual members of the Davison family can exert significant influence over us and may have conflicts of interest with us and may be permitted to favor their interests to the detriment of our other unitholders. James E. Davison and James E. Davison, Jr., each of whom is a director of our general partner, each own a significant portion of our common units, including our Class B Common Units, the holders of which elect our directors. Other members of the Davison family also own a significant portion of our common units. Collectively, members of the Davison family and their affiliates own approximately 10.4% of our Class A Common Units and 77.0% of our Class B Common Units and are able to exert significant influence over us, including the ability to elect at least a majority of the members of our board of directors and the ability to control most matters requiring board approval, such as material business strategies, mergers, business combinations, acquisitions or dispositions of assets, issuances of additional partnership securities, incurrences of debt or other financings and payments of distributions. In addition, the existence of a controlling group (if one were to form) may have the effect of making it difficult for, or may discourage or delay, a third party from seeking to acquire us, which may adversely affect the market price of our common units. Further, conflicts of interest may arise between us and other entities for which members of the Davison family serve as officers or directors. In resolving any conflicts that may arise, such members of the Davison family may favor the interests of another entity over our interests. 43 Table of Contents Members of the Davison family own, control and have interests in diverse companies, some of which may (or could in the future) compete directly or indirectly with us. As a result, the interests of the members of the Davison family may not always be consistent with our interests or the interests of our other unitholders. Members of the Davison family could also pursue acquisitions or business opportunities that may be complementary to our business. Our organizational documents allow the holders of our units (including affiliates, like the Davisons) to take advantage of such corporate opportunities without first presenting such opportunities to us. As a result, corporate opportunities that may benefit us may not be available to us in a timely manner, or at all. To the extent that conflicts of interest may arise among us and any member of the Davison family, those conflicts may be resolved in a manner adverse to us or you. Other potential conflicts may involve, among others, the following situations: • • • • our general partner is allowed to take into account the interest of parties other than us, such as one or more of its affiliates, in resolving conflicts of interest; our general partner may limit its liability and reduce its fiduciary duties, while also restricting the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty; our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities, reimbursements and enforcement of obligations to the general partner and its affiliates, retention of counsel, accountants and service providers and cash reserves, each of which can also affect the amount of cash that is distributed to our unitholders; and our general partner determines which costs incurred by it and its affiliates are reimbursable by us and the reimbursement of these costs and of any services provided by our general partner could adversely affect our ability to pay cash distributions to our unitholders. Our Class B Common Units may be transferred to a third party without unitholder consent, which could affect our strategic direction. Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Only holders of our Class B Common Units have the right to elect our board of directors. Holders of our Class B Common Units may transfer such units to a third party without the consent of the unitholders. The new holders of our Class B Common Units may then be in a position to replace our board of directors and officers of our general partner with its own choices and to control the strategic decisions made by our board of directors and officers. Unitholders with registration rights have rights to require underwritten offerings that could limit our ability to raise capital in the public equity market. Unitholders with registration rights have rights to require us to conduct underwritten offerings of our common units. If we want to access the capital markets (debt and equity), those unitholders’ ability to sell a portion of their common units could satisfy investor’s demand for our common units or may reduce the market price for our common units, thereby reducing the net proceeds we would receive from a sale of newly issued units. We may issue additional common units without unitholder’s approval, which would dilute their ownership interests. We may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. The issuance of additional common units or other equity securities of equal or senior rank will have the following effects: • • • • our unitholders’ proportionate ownership interest in us will decrease; the amount of cash available for distribution on each unit may decrease; the relative voting strength of each previously outstanding unit may be diminished; and the market price of our common units may decline. Our general partner has a limited call right that may require unitholders to sell their units at an undesirable time or price. If at any time our general partner and its affiliates own more than 80% of any class of our units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates, including any controlling unitholder, or to us, to acquire all, but not less than all, of the units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units. The interruption of distributions to us from our subsidiaries and joint ventures could affect our ability to make payments on indebtedness or cash distributions to our unitholders. 44 Table of Contents We are a holding company. As such, our primary assets are the equity interests in our subsidiaries and joint ventures. Consequently, our ability to fund our commitments (including payments on our indebtedness) and to make cash distributions depends upon the earnings and cash flow of our subsidiaries and joint ventures and the distribution of that cash to us. While some of our joint ventures and our Alkali Business may generally be required to make cash distributions to us on a quarterly or other periodic basis, distributions from our joint ventures and our unrestricted subsidiaries holding the Alkali Business are subject to the discretion of their respective management committee or similar governing body in one or more respects even if such distributions are generally required, such as with respect to the establishment of cash reserves. Further, the charter documents of certain of our joint ventures and the unrestricted subsidiaries holding the Alkali Business may vest in the management committees or similar governing body's certain discretion or contain certain limitations regarding cash distributions even if such distributions are generally required. Accordingly, our joint ventures and our unrestricted subsidiaries holding the Alkali Business may not continue to make distributions to us at current levels or at all. We do not have the same flexibility as other types of organizations to accumulate cash and equity to protect against illiquidity in the future. Unlike a corporation, our partnership agreement requires us to make quarterly distributions to our unitholders of all available cash reduced by any amounts reserved for commitments and contingencies, including capital and operating costs and debt service requirements. The value of our units and other limited partner interests may decrease in direct correlation with decreases in the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the future, we may not be able to issue more equity to recapitalize. Unitholders may have liability to repay distributions that were wrongfully distributed to them. Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted. Unitholder liability may not be limited if a court finds that unitholder action constitutes control of our business. A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some states in which we do business or may do business in from time to time in the future. Unitholders could be liable for any and all of our obligations as if unitholders were a general partner if a court or government agency were to determine that: • • we were conducting business in a state but had not complied with that particular state’s partnership statute; or unitholders right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitutes “control” of our business. Tax Risks to Our Unitholders Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as us not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service, or IRS, were to treat us as a corporation (for U.S. federal income tax purposes) or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution to our unitholders would be substantially reduced. The anticipated after-tax economic benefit of an investment in our units depends largely on our being treated as a partnership for federal income tax purposes. Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to in this discussion as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships, 90% or more of the gross income of which for each taxable year consists of “qualifying income.” 45 Table of Contents If less than 90% of our gross income for any taxable year is “qualifying income” from transportation, processing or marketing of natural resources (including minerals, crude oil, natural gas or products thereof), interest or dividends income, we will be taxable as a corporation under Section 7704 of the Internal Revenue Code for federal income tax purposes for that taxable year and all subsequent years. We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The decision of the U.S. Court of Appeals for the Fifth Circuit in Tidewater Inc. v. U.S., 565 F.3d 299 (5th Cir. April 13, 2009) held that the marine time charter being analyzed in that case was a “lease” that generated rental income rather than income from transportation services for purposes of a foreign sales corporation provision of the Internal Revenue Code. Even though (i) the Tidewater case did not involve a publicly traded partnership and it was not decided under Section 7704 of the Internal Revenue Code relating to “qualifying income,” (ii) some experienced practitioners believe the decision was not well reasoned, (iii) the IRS stated in an Action on Decision (AOD 2010-01) that it disagrees with and will not acquiesce to the Fifth Circuit’s marine time charter analysis contained in the Tidewater case and (iv) the IRS has issued several favorable private letter rulings (which can be relied upon and cited as precedent by only the taxpayers that obtained them) relating to time charters since the Tidewater decision was issued, the Tidewater decision creates some uncertainty regarding the status of income from certain of our marine time charters as “qualifying income” under Section 7704 of the Internal Revenue Code. Notwithstanding the foregoing, the Tidewater case is relevant authority because it is the only case of which we and our outside tax counsel are aware directly analyzing whether a particular time charter would constitute a lease or service agreement for certain U.S. federal tax purposes. Due to the uncertainty created by the Tidewater decision, our outside tax counsel, Akin Gump Strauss Hauer & Feld, LLP, was required to change the standard in its opinion relating to our status as a partnership for federal income tax purposes to “should” from “will.” Although we do not believe based upon our current operations that we are treated as a corporation for federal income tax purposes, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity. If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 21% and would pay state income tax at varying rates. Distributions to our unitholders would generally be taxable to them again as corporate distributions and no income, gains, losses, or deductions would flow through to them. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our units. At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay Texas franchise tax on our gross income apportioned to Texas. Imposition of any such taxes on us by any other state would reduce our cash available for distribution to our unitholders. The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis. The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our units may be modified by administrative, legislative or judicial interpretation at any time. From time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships, including the elimination of partnership tax treatment for certain publicly traded partnerships. Any modifications to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could cause a material reduction in our anticipated cash flows and could cause us to be treated as an association taxable as a corporation for U.S. federal income tax purposes subjecting us to the entity-level tax and adversely affecting the value of our units. A successful IRS contest of the federal income tax positions we take may adversely affect the market for our units, and the costs of any IRS contest would reduce our cash available for distribution to our unitholders and our general partner. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because these costs will reduce our cash available for distribution. Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties 46 Table of Contents and interest) resulting from such audit adjustments directly from us. To the extent possible under the new rules, our general partner may elect to either cause us to pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each unitholder and former unitholder with respect to an audited and adjusted return. Although our general partner may elect to have it, our unitholders and former unitholders take such audit adjustments into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. If we make payments of taxes and any penalties and interest directly to the IRS in the year in which the audit is completed, our cash available for distribution to our unitholders might be substantially reduced, in which case our current unitholders may bear some or all of the tax liability resulting from such audit adjustments, even if such unitholders did not own units in us during the tax year under audit. Our unitholders will be required to pay taxes on income (as well as deemed distributions, if any) from us even if they do not receive any cash distributions from us. Our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income (as well as deemed distributions, if any) even if unitholders receive no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income (or deemed distributions, if any) or even the tax liability that results from that income (or deemed distribution). Tax gain or loss on the disposition of our units could be more or less than expected. If our unitholders sell their units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their units, the amount, if any, of such prior excess distributions with respect to the units a unitholder sells will, in effect, become taxable income to the unitholder if it sells such units at a price greater than its tax basis in those units, even if the price received is less than its original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our non-recourse liabilities, if our unitholders sell their units, they may incur a tax liability in excess of the amount of cash they receive from the sale. Unitholders may be subject to limitations on their ability to deduct interest expense by us. In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Cuts and Jobs Act (the "Tax Act"), for taxable years beginning after December 31, 2017, our deduction for "business interest" is limited to the sum of our business interest income plus 30% of our "adjusted taxable income." Recently issued proposed regulations adopt a broad definition of interest, treating certain amounts (including income, deduction, gain, or loss from certain derivative instruments that alter our effective cost of borrowing) as business interest subject to the limitation. For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization or depletion (other than depreciation, amortization, or depletion capitalized to inventory). Any interest disallowed may be carried forward and deducted in future years by the unitholder from his share of our "excess taxable income," which is generally equal to the excess of 30% of our adjusted taxable income over the amount of our deduction for business interest for such future taxable year, subject to certain restrictions. While actual results may differ from the current estimates, we anticipate that our deduction for business interest will be limited under the interest expense limitations. If this limitation were to apply with respect to a taxable year, it could result in an increase in the taxable income allocable to a unitholder for such taxable year without any corresponding increase in the cash available for distribution to such unitholder. Tax-exempt entities and non-U.S. persons face unique tax issues from owning our units that may result in adverse tax consequences to them. Investment in our units by tax-exempt entities, such as individual retirement accounts (known as IRAs), other retirement plans and non-U.S. persons, raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. With respect to taxable years beginning after December 31, 2017, subject to the proposed aggregation rules for certain similarly situated businesses or activities issued by the Treasury Department, a tax- exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our units. 47 Table of Contents Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business ("effectively connected income"). Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be "effectively connected" with a U.S. trade or business. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit. Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade or business is generally required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person, and we are required to deduct and withhold from the transferee amounts that should have been withheld by the transferee but were not withheld. The IRS has issued proposed regulations that would treat the total cash purchase price for a unit as the amount realized for purposes of this 10% withholding tax. This withholding tax obligation is currently suspended in the case of a disposition of certain publicly traded partnership interests, including our units, until 60 days after the proposed regulations are finalized. Non-U.S. unitholders should consult a tax advisor before investing in our units. We will treat each purchaser of our common units as having the same tax benefits without regard to the common units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units. Because we cannot match transferors and transferees of our common units, we adopt depreciation and amortization conventions that may not conform to all aspects of existing Treasury Regulations and may result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions. A successful IRS challenge to those conventions could adversely affect the amount of tax benefits available to a common unitholder. It also could affect the timing of these tax benefits or the amount of gain from a sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the common unitholder’s tax returns. Our unitholders will likely be subject to state and local taxes in states where they do not live as a result of an investment in our units. In addition to federal income taxes, our unitholders will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if our unitholders do not live in any of those jurisdictions. Our unitholders will likely be required to file foreign, state, and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently own assets and do business in more than 20 states including Texas, Louisiana, Mississippi, Alabama, Florida, Arkansas and Oklahoma. Many of the states we currently do business in impose a personal income tax. It is our unitholders’ responsibility to file all applicable U.S. federal, foreign, state and local tax returns. Unitholders should consult with their own tax advisors regarding the filing of such tax returns, the payment of such taxes, and the deductibility of any taxes paid. We have subsidiaries that are treated as corporations for federal income tax purposes and subject to corporate-level income taxes. We conduct a portion of our operations through subsidiaries that are, or are treated as, corporations for federal income tax purposes. We may elect to conduct additional operations in corporate form in the future. These corporate subsidiaries will be subject to corporate-level tax, which, effective for taxable years beginning after December 31, 2017, is 21%, and will likely pay state (and possibly local) income tax at varying rates, on their taxable income. Any such entity level taxes will reduce the cash available for distribution to us and, in turn, to our unitholders. If the IRS were to successfully assert that these corporate subsidiaries have more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, our cash available for distribution to our unitholders would be further reduced. We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss, and deduction among our unitholders. We generally prorate our items of income, gain, loss, and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month (the "Allocation Date"), instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate (i) certain deductions for depreciation of capital additions, (ii) gain or loss realized on a sale or other disposition of our assets and (iii) in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. 48 Table of Contents A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, such unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units. The Internal Revenue Service could challenge our treatment of the holders of preferred units as partners for tax purposes, and if such challenge were sustained, certain holders of preferred units could be adversely impacted. The Internal Revenue Service, or IRS, may disagree with our treatment of the preferred units as equity for U.S. federal income tax purposes, and no assurance can be given that our treatment will be sustained. If the IRS were to successfully characterize the preferred units as indebtedness for tax purposes, certain holders of preferred units may be subject to additional withholding and reporting requirements. Further, if the preferred units were treated as indebtedness for U.S. federal tax purposes, rather than equity, distributions likely would be treated as payments of interest by us to the holders of preferred units. Holders of preferred units are encouraged to consult their tax advisors regarding the tax consequences applicable to the re- characterization of the preferred units as indebtedness for tax purposes. The amount that a preferred unitholder would receive upon liquidation may be less than the liquidation value of the preferred units. In general, we intend to specially allocate to the preferred units items of our gross income in an amount equal to the distributions paid in respect of the preferred units during the taxable year. If the distributions paid in respect of the preferred units during a taxable year exceed the amount of our gross income allocated to the preferred units for such taxable year (as in the case of prior distributions during the PIK period), the per unit capital account balance of the preferred unitholders would be reduced by the amount of such excess. If we were to dissolve or liquidate, after satisfying all of our liabilities, our unitholders (including the preferred unitholders) would be entitled to receive liquidating distributions in accordance with their capital account balances. In such event, preferred unitholders would be specially allocated items of gross income and gain in a manner designed to cause the capital account balance of a preferred unit to equal the liquidation value of a preferred unit. If we were to have insufficient gross income and gain to cause the capital account balance to equal the liquidation value of a preferred unit, then the amount that a preferred unitholder would receive upon liquidation would be less than the liquidation value of the preferred units, even though there may be cash available for distribution to the holders of common units or any other junior securities with respect to their capital accounts. Item 1B. Unresolved Staff Comments None. Item 2. Properties See Item 1. “Business.” We also have various operating leases for rental of office space, facilities and field equipment and transportation equipment. See “Commitments and Off-Balance Sheet Arrangements” in Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Note 4 to our Consolidated Financial Statements in Item 8 for details on our right of use assets and related lease liabilities. Such information is incorporated herein by reference. Item 3. Legal Proceedings We are involved from time to time in various claims, lawsuits and administrative proceedings incidental to our business. In our opinion, the ultimate outcome, if any, of such proceedings is not expected to have a material adverse effect on our financial condition, results of operations or cash flows. See Note 22 to our Consolidated Financial Statements in Item 8. 49 Table of Contents Item 4. Mine Safety Disclosures Information regarding mine safety and other regulatory action at our mine in Green River, Wyoming is included in Exhibit 95 to this Form 10-K. 50 Table of Contents PART II Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities Our Class A common units are listed on the New York Stock Exchange, or NYSE, under the symbol “GEL.” At February 27, 2020, we had 122,539,221 Class A common units outstanding. As of December 31, 2019, the closing price of our common units was $20.48 and we had approximately 25,000 record holders of our Class A common units, which include holders who own units through their brokers “in street name.” Additionally, we have issued 25,336,778 Class A Convertible Preferred Units for which there is no established public trading market. • • 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 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. The full definition of available cash is set forth in our partnership agreement and amendments thereto, which are incorporated by reference as an exhibit to this Form 10-K. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Capital Expenditures and Distributions Paid to our Unitholders” and Note 12 to our Consolidated Financial Statements in Item 8 for further information regarding restrictions on our distributions. See Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” for information regarding securities authorized for issuance under equity compensation plans. 51 Table of Contents Item 6. Selected Financial Data The table below includes selected financial and other data for the Partnership for the years ended December 31, 2019, 2018, 2017, 2016 and 2015 (in thousands, except per unit and volume data). The selected financial data should be read in conjunction with our Consolidated Financial Statements and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” 52 Table of Contents $ $ $ $ $ $ $ $ $ $ $ $ $ Income Statement Data: Revenues: Offshore pipeline transportation Sodium minerals and sulfur services Marine transportation Onshore facilities and transportation Total revenues(2) Equity in earnings of equity investees Income (loss) from continuing operations after income taxes Net income (loss) attributable to Genesis Energy, L.P. Net income (loss) available to Common Unitholders Net income (loss) attributable to Common Unitholders per Common Unit: Basic and Diluted Cash distributions declared per Common Unit Balance Sheet Data (at end of period): Current assets Total assets (3) Long-term liabilities (3) Class A Convertible Preferred Units Redeemable noncontrolling interests Partners' capital: Common unitholders Accumulated Other Comprehensive Income (Loss) Noncontrolling interests Total partners’ capital Other Data: Volumes: Offshore crude oil pipeline (barrels per day) Onshore crude oil pipeline (barrels per day) Natural gas transportation volumes (MMBtus/d) CO2 pipeline (Mcf per day) NaHS sales (DST) Soda Ash volumes (short tons sold) NaOH sales (DST) Crude oil and petroleum products sales (barrels per day) (1) 2019 (1) 2018 (1) 2017 2016 (1) 2015 (1) Year Ended December 31, 318,116 1,105,987 235,645 821,072 2,480,820 56,484 100,066 95,999 21,532 0.18 2.2000 593,074 6,597,641 3,835,727 790,115 125,133 $ $ $ $ $ $ $ $ $ $ $ $ 284,544 1,174,434 219,937 1,233,855 2,912,770 43,626 $ $ 318,239 462,622 205,287 1,042,229 2,028,377 51,046 (11,792) $ 82,079 (6,075) $ 82,647 (75,876) $ 60,652 (0.62) $ 0.50 2.1000 443,279 6,479,071 3,704,237 $ $ $ $ 2.6525 636,033 7,137,481 3,966,602 $ $ $ $ $ $ $ $ $ $ 761,466 $ — $ 697,151 $ — $ 334,679 171,503 213,021 993,290 1,712,493 47,944 111,082 113,249 113,249 1.00 2.7175 359,569 5,702,592 $ $ $ $ $ $ $ $ $ 3,321,739 $ — $ — $ 140,230 177,880 238,757 1,689,662 2,246,529 54,450 421,585 422,528 422,528 4.10 2.4700 306,316 5,459,599 3,136,712 — — 1,443,320 1,690,799 2,026,147 2,130,331 2,029,101 (8,431) (3,718) 1,431,171 $ 939 (11,204) 1,680,534 $ (604) (8,079) 2,017,464 $ — (10,281) 2,120,050 $ — (8,350) 2,020,751 652,862 562,467 591,667 581,763 518,211 193,020 247,409 212,768 114,130 144,084 400,770 97,912 126,443 3,590,680 78,927 432,261 107,674 150,671 3,669,206 110,107 496,302 77,921 133,404 1,274,421 84,816 679,862 97,955 125,766 — 80,021 708,556 161,409 127,063 — 86,914 31,681 45,845 51,771 62,484 91,704 (1) Our operating results and financial position have been affected by acquisitions and divestitures. For additional information regarding our acquisitions and divestitures during 2019, 2018 and 2017, see Note 5, related to our acquisitions, and Note 8, related to our divestitures, to our Consolidated Financial Statements included in Item 8. 53 Table of Contents (2) As a result of the adoption of the new revenue recognition standard, prior period amounts have not been adjusted under the modified retrospective method and continue to be reported in accordance with our historic accounting under previous GAAP. (3) As a result of the adoption of the new lease accounting standard, our long-term liabilities and total assets beginning in 2019 reflect recording of our right of use assets and corresponding lease liabilities. Prior period amounts have not been adjusted under the modified retrospective method and continue to be reported in accordance with our historic accounting under previous GAAP. See Note 4 to our Consolidated Financial Statements included in Item 8 for additional information. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations Introduction We are a growth-oriented master limited partnership formed in Delaware in 1996. Our common units are traded on the New York Stock Exchange, or NYSE, under the ticker symbol “GEL.” We are (i) a provider of an integrated suite of midstream services - primarily transportation, storage, sulfur removal, blending, terminalling and processing - for a large area of the Gulf of Mexico and the Gulf Coast region of the crude oil and natural gas industry and (ii) one of the leading producers in the world of natural soda ash. A core part of our focus is in the midstream sector of the crude oil and natural gas industry in the Gulf of Mexico and the Gulf Coast region of the United States. We provide an integrated suite of services to refiners, crude oil and natural gas producers, and industrial and commercial enterprises and have a diverse portfolio of assets, including pipelines, offshore hub and junction platforms, refinery-related plants, storage tanks and terminals, railcars, rail unloading facilities, barges and other vessels, and trucks. Within our midstream business, we have two distinct, complementary types of operations: (i) our offshore Gulf of Mexico crude oil and natural gas pipeline transportation and handling operations, which focus on providing a suite of services primarily to integrated and large independent energy companies who make intensive capital investments (often in excess of billions of dollars) to develop numerous large-reservoir, long-lived crude oil and natural gas properties and (ii) our onshore- based refinery-centric operations located primarily in the Gulf Coast region of the U.S., which focus on providing a suite of services primarily to refiners, which includes our sulfur removal, transportation, storage, and other handling services. Our onshore-based operations occur upstream of, at, and downstream of refinery complexes. Upstream of refineries, we aggregate, purchase, gather and transport crude oil, which we sell to refiners. 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. In our offshore crude oil and natural gas pipeline transportation and handling operations, we provide services to one of the most active drilling and development regions in the U.S., the Gulf of Mexico, a producing region representing approximately 16% of the crude oil production in the U.S. in 2019. The other core focus of our business is our Alkali Business. Our Alkali Business mines and processes trona from which it produces natural soda ash, also known as sodium carbonate (Na2CO3), a basic building block for a number of ubiquitous products, including flat glass, container glass, dry detergent and a variety of chemicals and other industrial products. Our Alkali Business has a diverse customer base in the United States, Canada, the European Community, the European Free Trade Area and the South African Customs Union with many long-term relationships. It has been operating for over 70 years and has an estimated remaining reserve life (based on 2019 production) of over 100 years. Included in Management’s Discussion and Analysis are the following sections: • Overview of 2019 Results • • • • • • • • Acquisitions, Divestitures and Growth Initiatives Results of Operations Other Consolidated Results Financial Measures Liquidity and Capital Resources Commitments and Off-Balance Sheet Arrangements Critical Accounting Policies and Estimates Recent Accounting Pronouncements 54 Table of Contents Overview of 2019 Results We reported Net Income Attributable to Genesis Energy, L.P. of $96.0 million in 2019 compared to Net Loss Attributable to Genesis Energy, L.P. of $6.1 million in 2018. The increase was principally due to 2018 including impairment expense of $126.3 million and gains on asset sales of $42.3 million compared to no such activity during 2019. Additionally, in 2019, we had: (i) lower general and administrative expenses of $14.0 million primarily due to 2018 including certain dispute costs; (ii) lower interest expense of $9.8 million attributable to our lower average outstanding indebtedness during 2019; and (iii) higher equity in earnings of equity investees of $12.9 million. These were partially offset by higher depreciation, depletion, and amortization expense of $6.6 million in 2019 and a decrease in other income(expense) of $14.1 million in 2019 due to an unrealized loss of $9.0 million associated with the valuation of our embedded derivative on our Class A Convertible Preferred Units recognized during 2019 compared to an unrealized gain of $8.4 million reported in 2018. We also recorded a loss on debt extinguishment of $3.3 million during 2018 in other income(expense). Cash flow from operating activities was $382.3 million for the 2019 period compared to $390.0 million for 2018. This decrease was primarily attributable to working capital needs during the respective periods. Available Cash before Reserves (as defined below in "Financial Measures") decreased $106.5 million in 2019 to $359.5 million as compared to 2018 Available Cash before Reserves of $466.1 million. This decrease is primarily attributable to the gain on sale of assets of $42.3 million during 2018 and cash distributions paid or accrued to our Class A Convertible Preferred Unitholders of $62.2 million related to 2019. See "Financial Measures" below for additional information on Available Cash before Reserves. Segment Margin was $713.3 million in 2019, an increase of $0.5 million as compared to 2018. See "Results from Operations" below for discussion on our individual segments. 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 (i) the stable and repeatable cash flows from our four operating segments for the foreseeable future, (ii) new long-term commercial opportunities that will provide significant incremental volumes on our already constructed offshore pipeline transportation assets that require no additional investment from us; and (iii) minimal expected growth capital expenditures in 2020 and for the foreseeable future with the exception of the expansion of our Granger soda ash facility, which can be fully funded externally, allows us the flexibility to use any excess cash flow from operations to pay down borrowings, and naturally deleverage our balance sheet. These strategies allow us to further enhance our financial flexibility to opportunistically pursue accretive organic projects and acquisitions should they present themselves. We currently manage our businesses through four divisions that constitute our reportable segments - offshore pipeline transportation, sodium minerals and sulfur services, onshore facilities and transportation and marine transportation. A more detailed discussion of our segment results and other costs is included below in "Results of Operations". Distributions to Unitholders On February 14, 2020, we paid a distribution of $0.55 per unit related to the fourth quarter of 2019. With respect to our Class A Convertible Preferred Units, we have declared a quarterly cash distribution of $0.7374 per preferred unit (or $2.9496 on an annualized basis) for each preferred unit held of record. These distributions were paid on February 14, 2020 to unitholders holders of record at the close of business January 31, 2020. Recent Developments and Growth Initiatives Refinancing of our 2022 Notes In January 2020, we issued $750 million in aggregate principal amount of our 2028 Notes. Interest payments are due February 1 and August 1 of each year with the initial interest payment due August 1, 2020. That issuance generated net proceeds of approximately $738.9 million, net of issuance costs incurred. The net proceeds were used to purchase and redeem all of our outstanding 2022 Notes. Of the net proceeds, $554.8 million were used to repurchase the 2022 Notes (including principal, accrued interest and tender premium) that were validly tendered in our tender offer for the 2022 Notes, and the remaining balance was used for repaying a portion of the borrowings outstanding under our revolving credit facility. On January 17, 2020 we called for redemption of the remaining balance of our 2022 Notes with a redemption date of February 16, 2020. 55 Table of Contents Granger Facility Expansion On September 23, 2019, we announced the expansion of GOP to expand our existing Granger facility, expected to be completed during 2022. We entered into agreements with funds affiliated with GSO for the purchase of up to $350 million of preferred units in Alkali Holdings. The proceeds we will receive from GSO will fund up to 100% of the anticipated cost of the GOP. The preferred unitholders will receive payment-in-kind in lieu of cash distributions during the anticipated construction period. As of December 31, 2019, we had issued 130,000 preferred units to be used to fund the construction. Powder River Basin Midstream Assets Divestiture On October 11, 2018, we completed the divestiture of our Powder River Basin midstream assets and received total net proceeds of approximately $300 million that we utilized to reduce the balance outstanding under our revolving credit facility. Results of Operations In the discussions that follow, we will focus on our revenues, expenses and net income, as well as two measures that we use to manage the business and to review the results of our operations- Segment Margin and Available Cash before Reserves. Segment Margin and Available Cash before Reserves are defined in the "Financial Measures" section below. Revenues, Costs and Expenses Our revenues for the year ended December 31, 2019 decreased $432.0 million, or 15%, from the year ended December 31, 2018. Additionally, our costs and expenses (excluding gains on sale of assets and impairment expense in 2018) decreased $450.4 million, or 17%, between the two periods. A substantial portion of our revenues and costs are derived from the purchase and sale of crude oil and petroleum products through our onshore facilities and transportation segment. The decrease in our revenues and costs in this segment between 2019 and 2018 is primarily attributable to decreases in crude oil and petroleum product prices, and to an extent, sales volumes. The average closing prices for West Texas Intermediate crude oil on the New York Mercantile Exchange ("NYMEX") decreased 12% to $56.96 in 2019 as compared to $64.74 per barrel in 2018. 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”. In addition to our legacy marketing business discussed above, we continue to operate in our other core businesses, including: (i) our offshore Gulf of Mexico crude oil and natural gas pipeline transportation and handling operations, focusing on integrated and large independent energy companies who make intensive capital investments (often in excess of billions of dollars) to develop numerous large reservoir, long-lived crude oil and natural gas properties; (ii) our sodium minerals and sulfur services businesses, which includes our Alkali Business, which is one of the leading producers of natural soda ash worldwide, and our legacy sulfur removal business; and (iii) our onshore-based refinery-centric operations located primarily in the Gulf Coast region of the U.S., which focus on providing a suite of services primarily to refiners. Refiners are the shippers of approximately 97% of the volumes transported on our onshore crude pipelines, and refiners contract for over 80% of the use of our inland barges, which are used primarily to transport intermediate refined products (not crude oil) between refining complexes. The shippers on our offshore pipelines are mostly integrated and large independent energy companies whose production is ideally suited for the vast majority of refineries along the Gulf Coast, unlike the lighter crude oil and condensates produced from numerous onshore shale plays. Their large-reservoir properties and the related pipelines and other infrastructure needed to develop them are capital intensive and yet, we believe, economically viable, in most cases, even in relatively low commodity price environments. Given these facts, we do not expect changes in commodity prices to impact our Net Income, Available Cash before Reserves or Segment Margin derived from our offshore Gulf of Mexico crude oil and natural gas pipeline transportation and handling operations in the same manner in which they impact our revenues and costs derived from the purchase and sale of crude oil and petroleum products. 56 Table of Contents 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, 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: Offshore pipeline transportation Sodium minerals and sulfur services (1) Onshore facilities and transportation Marine transportation Total Segment Margin Year Ended December 31, 2019 2018 2017 320,023 223,908 111,412 57,919 (in thousands) 285,014 260,488 119,918 47,338 317,540 130,333 96,376 50,294 $ 713,262 $ 712,758 $ 594,543 (1) Our Alkali Business, which is included in the Sodium minerals and sulfur services segment, was acquired on September 1, 2017 and the results for 2017 include the operations subsequent to our acquisition. 57 Table of Contents Year Ended December 31, 2019 Compared with Year Ended December 31, 2018 Offshore Pipeline Transportation Segment Operating results and volumetric data for our offshore pipeline transportation segment are presented below: Offshore crude oil pipeline revenue, excluding non-cash revenues Offshore natural gas pipeline revenue, excluding non-cash revenues Offshore pipeline operating costs, excluding non-cash expenses Distributions from equity investments (1) Offshore pipeline transportation Segment Margin Volumetric Data 100% basis: Crude oil pipelines (average barrels/day unless otherwise noted): CHOPS Poseidon Odyssey GOPL (2) Total crude oil offshore pipelines Year Ended December 31, 2019 2018 (in thousands) $ 259,899 $ 243,049 54,108 (69,561) 75,577 47,048 (75,155) 70,072 $ 320,023 $ 285,014 234,301 264,931 144,785 8,845 652,862 202,121 234,960 115,239 10,147 562,467 Natural gas transportation volumes (MMBtus/d) 400,770 432,261 Volumetric Data net to our ownership interest (3): Crude oil pipelines (average barrels/day unless otherwise noted): CHOPS Poseidon Odyssey GOPL (2) Total crude oil offshore pipelines 234,301 169,556 41,988 8,845 454,690 202,121 150,374 33,419 10,147 396,061 Natural gas transportation volumes (MMBtus/d) 152,388 164,706 (1) Offshore pipeline transportation Segment Margin includes distributions received from our offshore pipeline joint ventures accounted for under the equity method of accounting in 2019 and 2018, respectively. (2) One of our wholly-owned subsidiaries (GEL Offshore Pipeline, LLC, or "GOPL") owns our undivided interest in the Eugene Island pipeline system. (3) 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 2019 increased $35.0 million, or 12%, from 2018, primarily due to higher volumes on our crude oil pipeline systems. These increased volumes are the result of 2019 including: (i) first oil flow from the Buckskin and Hadrian North production fields, both of which are fully dedicated to our SEKCO pipeline, and further downstream, our Poseidon oil pipeline system ("Poseidon"), and (ii) the continued receipt of additional volumes on our CHOPS and Poseidon systems due to deliveries from a third party pipeline that had insufficient capacity to deliver its committed volumes to shore. During the second half of 2019, we entered into agreements to move forty thousand barrels per day on CHOPS and twenty thousand barrels per day on Poseidon that are delivered to us by a third-party pipeline that has insufficient capacity. The agreements include ship-or-pay provisions, have terms as long as five years and required no additional capital on our part. 58 Table of Contents The increased volumes more than offset the approximately $7.8 million in minimum bill platform fees (which ended in June 2018), related to our interest in Poseidon, that we received during 2018. Sodium Minerals and Sulfur Services Segment Operating results for our sodium minerals and sulfur services segment were as follows: Volumes sold : NaHS volumes (Dry short tons "DST") Soda Ash volumes (short tons sold) NaOH (caustic soda) volumes (dry short tons sold) Revenues (in thousands): NaHS revenues, excluding non-cash revenues NaOH (caustic soda) revenues Revenues associated with Alkali Business Other revenues Total segment revenues, excluding non-cash revenues (1) Sodium minerals and sulfur services operating costs, excluding non-cash items (1) Segment Margin (in thousands) Average index price for NaOH per DST (2) Year Ended December 31, 2019 2018 126,443 3,590,680 78,927 150,671 3,669,206 110,107 $ 148,812 $ 181,391 41,365 836,125 5,001 1,031,303 (807,395) 223,908 692 $ $ $ 61,344 829,023 7,020 1,078,778 (818,290) 260,488 768 $ $ $ (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 2019 decreased $36.6 million, or 14%, from 2018. This decrease is due to lower NaHS and soda ash volumes during 2019 relative to 2018. Lower NaHS volumes during 2019 are primarily attributable to production issues at several of our host refineries during 2019 and lower demand from certain of our international customers located in South America. Certain of our customers also experienced supply chain disruptions during 2019, which we believe to be resolved as we enter 2020. Our Alkali Business experienced lower soda ash volumes during 2019 primarily due to more downtime and planned maintenance activities, including the planned replacement and upgrade of a heat exchanger, a move of our longwall mining machine, and a temporary electrical equipment failure that impacted our production. Costs impacting the results of our sodium minerals and sulfur services segment include costs associated with processing and production of soda ash (and other alkali products), NaHS, and marketing and selling activities. In addition, costs include activities associated with mining and extracting trona ore (including energy costs and employee compensation). 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, rail facilities and CO2 pipelines operating primarily within the United States Gulf Coast crude oil market. In addition, we utilize our railcar and trucking fleets that support the purchase and sale of gathered and bulk purchased crude oil, as well as purchased and sold refined products. Through these assets we offer our customers a full suite of services, including the following: • • • • facilitating the transportation of crude oil from producers to refineries and from owned and third party terminals to refiners via pipelines; transporting CO2 from natural and anthropogenic sources to crude oil fields owned by our customers; 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; 59 Table of Contents • • • storing and blending of crude oil and intermediate and finished refined products; purchasing/selling and/or transporting crude oil from the wellhead to markets for ultimate use in refining; and purchasing products from refiners, transporting those products to one of our terminals and blending those products to a quality that meets the requirements of our customers and selling those products (primarily fuel oil, asphalt and other heavy refined products) to wholesale markets; We also may use our terminal facilities to take advantage of contango market conditions for crude oil gathering and marketing and to capitalize on regional opportunities which arise from time to time for both crude oil and petroleum products. Despite crude oil being considered a somewhat homogeneous commodity, many refiners are very particular about the quality of crude oil feedstock they process. Many U.S. refineries have distinct configurations and product slates that require crude oil with specific characteristics, such as gravity, sulfur content and metals content. The refineries evaluate the costs to obtain, transport and process their preferred feedstocks. That particularity provides us with opportunities to help the refineries in our areas of operation identify crude oil sources and transport crude oil meeting their requirements. The imbalances and inefficiencies relative to meeting the refiners’ requirements may also provide opportunities for us to utilize our purchasing and logistical skills to meet their demands. The pricing in the majority of our crude oil purchase contracts contains a market price component and a deduction to cover the cost of transportation and to provide us with a margin. Contracts sometimes contain a grade differential which considers the chemical composition of the crude oil and its appeal to different customers. Typically, the pricing in a contract to sell crude oil will consist of the market price components and the grade differentials. The margin on individual transactions is then dependent on our ability to manage our transportation costs and to capitalize on grade differentials. In our refined products marketing operations, we supply primarily fuel oil, asphalt and other heavy refined products to wholesale markets and some end-users such as paper mills and utilities. We also provide a service to refineries by purchasing “heavier” petroleum products that are the residual fuels from gasoline production, transporting them to one of our terminals and blending them to a quality that meets the requirements of our customers. 60 Table of Contents Operating results for our onshore facilities and transportation segment were as follows: Gathering, marketing, and logistics revenue Crude oil and CO2 pipeline tariffs and revenues from direct financing leases of CO2 pipelines Payments received under direct financing leases not included in income Crude oil and products costs, excluding unrealized gains and losses from derivative transactions Operating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses Other Segment Margin Volumetric Data (average barrels/day unless otherwise noted): Onshore crude oil pipelines: Texas Jay Mississippi Louisiana (1) Wyoming (2) Onshore crude oil pipelines total CO2 pipeline (average Mcf/day): Free State Crude oil and petroleum products sales: Total crude oil and petroleum products sales Rail unload volumes (3) Year Ended December 31, 2019 2018 (in thousands) $ 747,619 $ 1,154,114 69,418 8,421 74,895 7,633 (637,629) (1,038,386) (76,025) (392) 111,412 $ (88,391) 10,053 $ 119,918 59,435 10,461 5,994 117,130 — 193,020 33,303 14,036 6,359 159,754 33,957 247,409 97,912 107,674 31,681 79,530 45,845 89,082 (1) Total daily volume for the years ended December 31, 2019 and 2018 include 51,267 and 55,202 barrels per day respectively of intermediate refined products associated with our Port of Baton Rouge Terminal pipelines. (2) The volumes presented for 2018 represent the average barrels/day through September 30, 2018, as the relevant assets were divested in October 2018. (3) Includes total barrels for unloading at all rail facilities. Segment Margin for our onshore facilities and transportation segment decreased $8.5 million, or 7% , in 2019 as compared to 2018. The decrease is primarily attributable to the lower crude oil pipeline, rail unload volumes, and terminal movements on our Louisiana asset base that services the Baton Rouge corridor due to Canadian production curtailments imposed by the government that affected our main customer. Additionally, 2018 included nearly ten months of margin contribution from our Powder River Basin midstream assets that were divested in the fourth quarter of 2018. These decreases were partially offset by: (i) the increased volumes on our Texas system and the incremental margin recognized during 2019 from these volumes as our main customer utilized all of its prepaid transportation credits prior to December 31, 2019, and (ii) a cash payment of $10 million associated with the resolution of a crude oil supply agreement. 61 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: Revenues (in thousands): Inland freight revenues Offshore freight revenues Other rebill revenues (1) Total segment revenues Operating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses Segment Margin (in thousands) Fleet Utilization: (2) Inland Barge Utilization Offshore Barge Utilization Year Ended December 31, 2019 2018 $ $ $ $ 104,756 $ 77,630 53,259 235,645 177,726 57,919 $ $ $ 93,091 70,804 56,042 219,937 172,599 47,338 96.8% 94.6% 95.2% 93.5% (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 2019 increased $10.6 million, or 22%, from 2018. The increase is primarily attributable to higher inland and offshore barge utilization and an increase in average day rates in the market that were advantageous in 2019 relative to 2018. While we have seen a slight uptick in day rates, 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 are still near cyclical lows. This was partially offset by an increase in operating costs during 2019 due to an increase in dry-docking costs in both our inland and offshore fleet. Other Costs and Interest General and administrative expenses General and administrative expenses not separately identified below: Corporate Segment Long-term incentive based compensation plan expense Third party costs related to business development activities and growth projects Total general and administrative expenses Year Ended December 31, 2019 2018 (in thousands) $ $ 40,718 $ 50,918 4,266 3,948 3,755 4,532 2,345 9,103 52,687 $ 66,898 Total general and administrative expenses decreased $14.2 million between 2019 and 2018. This is primarily attributable to certain dispute costs incurred during 2018, which are included within corporate general and administrative costs. Additionally, our third party costs related to business development activities and growth projects was $5.3 million higher in 2018 due to the continued integration of our Alkali Business in 2018, which was acquired in the second half of 2017. 62 Table of Contents Depreciation, depletion, and amortization expense Depreciation and depletion expense Amortization of intangible assets Amortization of CO2 volumetric production payments Total depreciation, depletion and amortization expense Year Ended December 31, 2019 2018 (in thousands) $ $ 300,213 $ 290,070 18,704 889 21,835 1,285 319,806 $ 313,190 Total depreciation, depletion, and amortization expense increased $6.6 million between 2019 and 2018, primarily as a result of placing additional assets into service, including those acquired as a part of our Alkali Business and our continued annual maintenance capital expenditures. Interest expense, net Interest expense, senior secured credit facility (including commitment fees) Interest expense, senior unsecured notes Amortization and write-off of debt issuance costs and discount Capitalized interest Net interest expense Year Ended December 31, 2019 2018 (in thousands) $ $ 54,165 $ 62,439 158,188 10,766 (3,679) 219,440 $ 159,175 10,914 (3,337) 229,191 Net interest expense decreased $9.8 million during 2019 relative to 2018, primarily due to a decrease in our average outstanding indebtedness on our revolving credit facility during 2019. Additionally, during 2018, we recorded $1.0 million of interest expense on our previously held senior unsecured notes due February 15, 2021, which we redeemed in February 2018. Other Consolidated Results Net income for the year ended December 31, 2019 included an unrealized loss on the valuation of our embedded derivative associated with our Class A Convertible Preferred Units of $9.0 million compared to an unrealized gain of $8.4 million for the year ended December 31, 2018. Those amounts are included in other income (expense) in the Consolidated Statement of Operations. Net loss for the year ended December 31, 2018 included impairment expense of approximately $126.3 million recognized during 2018 including: (i) an impairment of $23.1 million on the goodwill associated with our supply and logistics reporting unit, which primarily consists of our legacy crude oil and refined products marketing and trucking businesses; (ii) an impairment of certain of our non-core offshore gas pipeline and platform assets of approximately $82.0 million for which the abandonment timing has accelerated; and (iii) a write-down of approximately $21.2 million related to our remaining non-core assets in the Powder River Basin subsequent to our divestiture. The year ended December 31, 2018 also included a gain on the sale of our Powder River Basin midstream assets of $38.9 million and a loss on debt extinguishment of $3.3 million, which is included in other income(expense). A discussion of the operating results for the year ended December 31, 2018 compared with the year ended December 31, 2017 has been omitted from this Form 10-K. This discussion can be found within our previously filed 2018 Form 10-K, which was filed with the SEC on February 28, 2019. Financial Measures Overview This Annual Report on Form 10-K includes the financial measure of Available Cash before Reserves, which is a “non- GAAP” measure because it is not contemplated by or referenced in generally accepted accounting principles in the United States of America (GAAP). We also present total Segment Margin as if it were a non-GAAP measure. Our Non-GAAP measures may not be comparable to similarly titled measures of other companies because such measures may include or 63 Table of Contents 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 14 to our Consolidated Financial Statements in Item 8. Our non-GAAP financial measures should not be considered (i) as alternatives to GAAP measures of liquidity or financial performance or (ii) as being singularly important in any particular context; they should be considered in a broad context with other quantitative and qualitative information. Our Available Cash before Reserves and total Segment Margin measures are just two of the relevant data points considered from time to time. When evaluating our performance and making decisions regarding our future direction and actions (including making discretionary payments, such as quarterly distributions) our board of directors and management team 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 14 to our Consolidated Financial Statements in Item 8. Available Cash before Reserves Purposes, Uses and Definition Available Cash before Reserves, often referred to by others as distributable cash flow, is a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and is commonly used as a supplemental financial measure by management and by external users of financial statements such as investors, commercial banks, research analysts and rating agencies, to aid in assessing, among other things: (1) the financial performance of our assets; (2) our operating performance; (3) the viability of potential projects, including our cash and overall return on alternative capital investments as compared to those of other companies in the midstream energy industry; (4) the ability of our assets to generate cash sufficient to satisfy certain non-discretionary cash requirements, including interest payments and certain maintenance capital requirements; and (5) our ability to make certain discretionary payments, such as distributions on our preferred and common units, growth capital expenditures, certain maintenance capital expenditures and early payments of indebtedness. We define Available Cash before Reserves (“Available Cash before Reserves”) as net income(loss) 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. 64 Table of Contents I. Applicable to all Non-GAAP Measures Differences in timing of cash receipts for certain contractual arrangements1 Adjustment regarding direct financing leases2 Certain non-cash items: Unrealized (gain) loss on derivative transactions excluding fair value hedges, net of changes in inventory value Loss on debt extinguishment Adjustment regarding equity investees3 Other Sub-total Select Items, net4 II. Applicable only to Available Cash before Reserves Certain transaction costs5 Equity compensation adjustments Other6 Total Select Items, net7 Year Ended December 31, 2019 2018 $ (8,478) $ (6,629) 7,633 8,421 10,926 — 20,847 3,651 35,367 (10,455) 3,339 28,088 869 22,845 3,755 (137) 3,168 $ 42,153 9,103 (207) 16,208 $ 47,949 (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) Represents the net effect of adding cash receipts from direct financing leases and deducting expenses relating to direct financing leases. (3) Represents the net effect of adding distributions from equity investees and deducting earnings of equity investees net to us. (4) Represents all Select Items applicable to Segment Margin. (5) Represents transaction costs relating to certain merger, acquisition, transition and financing transactions incurred in advance of acquisition. (6) 2018 includes general and administrative costs associated with certain dispute costs. (7) Represents Select Items applicable to Available Cash before Reserves. Disclosure Format Relating to Maintenance Capital We use a modified format relating to maintenance capital requirements because our maintenance capital expenditures vary materially in nature (discretionary vs. non-discretionary), timing and amount from time to time. We believe that, without such modified disclosure, such changes in our maintenance capital expenditures could be confusing and potentially misleading to users of our financial information, particularly in the context of the nature and purposes of our Available Cash before Reserves measure. Our modified disclosure format provides those users with information in the form of our maintenance capital utilized measure (which we deduct to arrive at Available Cash before Reserves). Our maintenance capital utilized measure constitutes a proxy for non-discretionary maintenance capital expenditures and it takes into consideration the relationship among maintenance capital expenditures, operating expenses and depreciation from period to period. 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. 65 Table of Contents Beginning with 2014, we believe a substantial amount of our maintenance capital expenditures from time to time will be (a) related to our assets other than pipelines, such as our marine vessels, trucks and similar assets, (b) discretionary in nature and (c) potentially material in amount as compared to our Available Cash before Reserves measure. Those expenditures will be discretionary (or non-mandatory) in nature because we will have significant discretion as to whether or when we incur them. We will not be forced to incur them in order to continue to operate the related assets in a safe and reliable manner. If we chose not make those expenditures, we would be able to continue to operate those assets economically, although in lieu of maintenance capital expenditures, we would incur increased operating expenses, including maintenance expenses. An example of a discretionary (or non-mandatory) maintenance capital expenditure would be replacing an older marine vessel with a new marine vessel with substantially similar specifications, even though one could continue to economically operate the older vessel in spite of its increasing maintenance and other operating expenses. In summary, as we continue to expand certain non-pipeline portions of our business, we are experiencing changes in the nature (discretionary vs. non-discretionary), timing and amount of our maintenance capital expenditures that merit a more detailed review and analysis than was required historically. Management’s increasing ability to determine if and when to incur certain maintenance capital expenditures is relevant to the manner in which we analyze aspects of our business relating to discretionary and non-discretionary expenditures. We believe it would be inappropriate to derive our Available Cash before Reserves measure by deducting discretionary maintenance capital expenditures, which we believe are similar in nature in this context to certain other discretionary expenditures, such as growth capital expenditures, distributions/dividends and equity buybacks. Unfortunately, not all maintenance capital expenditures are clearly discretionary or non-discretionary in nature. Therefore, we developed a measure, maintenance capital utilized, that we believe is more useful in the determination of Available Cash before Reserves. MAINTENANCE CAPITAL UTILIZED We believe our maintenance capital utilized measure is the most useful quarterly maintenance capital requirements measure to use to derive our Available Cash before Reserves measure. We define our maintenance capital utilized measure as that portion of the amount of previously incurred maintenance capital expenditures that we utilize during the relevant quarter, which would be equal to the sum of the maintenance capital expenditures we have incurred for each project/component in prior quarters allocated ratably over the useful lives of those projects/components. Our maintenance capital utilized measure constitutes a proxy for non-discretionary maintenance capital expenditures and it takes into consideration the relationship among maintenance capital expenditures, operating expenses and depreciation from period to period. Because we did not use our maintenance capital utilized measure before 2014, our maintenance capital utilized calculations will reflect the utilization of solely those maintenance capital expenditures incurred since December 31, 2013. Available Cash before Reserves for the years ended December 31, 2019 and 2018 was as follows: Year Ended December 31, 2019 2018 (in thousands) Net income (loss) attributable to Genesis Energy, L.P. $ 95,999 $ Income Tax expense Depreciation, depletion, amortization, and accretion Impairment expense Plus (minus) Select Items, net Maintenance capital utilized Cash tax expense Distributions to preferred unitholders Redeemable noncontrolling interest redemption value adjustments(1) Available Cash before Reserves (1) Includes distributions paid in kind and accretion adjustments on the redemption feature. 66 655 308,115 — 42,153 (26,875) (590) (62,190) 2,233 (6,075) 1,498 317,186 126,282 47,949 (19,955) (835) — — $ 359,500 $ 466,050 Table of Contents Liquidity and Capital Resources General As of December 31, 2019, we believe our balance sheet and liquidity position remained strong, including $739.6 million of borrowing capacity available 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 and senior unsecured notes. Our primary cash requirements consist of: working capital, primarily inventories and trade receivables and payables; routine operating expenses; capital growth and maintenance projects; acquisitions of assets or businesses; interest payments related to outstanding debt; 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. On October 11, 2018, we completed the sale of our Powder River Basin midstream assets, for which we received total net proceeds of approximately $300 million. We applied those net proceeds to reduce the balance outstanding under our revolving credit facility. At December 31, 2019, we had $959.3 million borrowed under our credit facility, with $4.3 million of the borrowed amount designated as a loan under the inventory sublimit. Due to the revolving nature of loans under our credit facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date of May 9, 2022. Our credit facility does not include a “borrowing base” limitation except with respect to our inventory loans. The total amount available for borrowings under our credit facility at December 31, 2019 was $739.6 million. At December 31, 2019, our long-term debt totaled $3.4 billion, consisting of $1.0 billion outstanding under our credit facility (including $4.3 million borrowed under the inventory sublimit tranche), $450 million of our 2026 Notes, $550 million of our 2025 Notes, $350 million of our 2024 Notes, $400 million of our 2023 Notes and $750 million of our 2022 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. Redemption right beginning on Redemption of up to 35% of the principal amount of notes with the proceeds of an equity offering permitted prior to 2022 Notes 2023 Notes 2024 Notes 2025 Notes 2026 Notes August 1, 2018 May 15, 2018 June 15, 2019 October 1, 2020 February 15, 2021 August 1, 2018 May 15, 2018 June 15, 2019 October 1, 2020 February 15, 2021 In January 2020, we issued $750 million in aggregate principal amount of our 2028 Notes. Interest payments are due February 1 and August 1 of each year with the initial interest payment due August 1, 2020. That issuance generated net proceeds of approximately $738.9 million, net of issuance costs incurred. The net proceeds were used to purchase and redeem all of our outstanding 2022 Notes. Of the net proceeds, $554.8 million were used to repurchase the 2022 Notes (including principal, accrued interest and tender premium) that were validly tendered in our tender offer for the 2022 Notes, and the remaining balance was used for repaying a portion of the borrowings outstanding under our revolving credit facility. On 67 Table of Contents January 17, 2020 we called for redemption of the remaining balance of our 2022 Notes with a redemption date of February 16, 2020. For additional information on our long-term debt and covenants see Note 11 to our Consolidated Financial Statements in Item 8. Class A Convertible Preferred Units On September 1, 2017, we sold $750 million of Class A convertible preferred units in a private placement, comprised of 22,249,494 units for a cash purchase price per unit of $33.71 (subject to certain adjustments, the “Issue Price”) to two initial purchasers. Our general partner executed an amendment to our partnership agreement in connection therewith, which, among other things, authorized and established the rights and preferences of our preferred units. Our 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 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 preferred units. Each of our preferred units accumulate quarterly distribution amounts in arrears at an annual rate of 8.75% (or $2.9496), yielding a quarterly rate of 2.1875% (or $0.7374), subject to certain adjustments. With respect to any quarter ending on or prior to March 1, 2019, we exercised our option to pay the holders of our preferred units the applicable distribution in additional preferred units equal the product of (i) the number of then outstanding preferred units and (ii) the quarterly rate. For all subsequent periods ending after March 1, 2019, we have paid and will pay all distribution amounts in respect of our preferred units in cash. Redeemable Noncontrolling interests On September 23, 2019, we, through a subsidiary, Alkali Holdings, entered into an amended and restated Limited Liability Company Agreement of Alkali Holdings (the "LLC Agreement") and a Securities Purchase Agreement (the "Securities Purchase Agreement") whereby certain investment fund entities affiliated with GSO (collectively, the "Sponsor") purchased $55,000,000 and committed to purchase, during a three-year commitment period, up to a total of $350,000,000 (the "Preferred Commitment") of preferred units in Alkali Holdings. Alkali Holdings will use the net proceeds from the preferred units to fund up to 100% of the anticipated cost of expansion of the Granger facility. As of December 31, 2019, we had issued a total of $130,000,000 in preferred units to the Sponsor in exchange for cash of $122,900,000, which is inclusive of our transaction related expenses and one-time commitment fee. The Sponsor has the right to a quarterly distribution equal to 10% per annum on the liquidation preference of each preferred unit. The liquidation preference is defined as one thousand dollars per preferred unit, plus any accrued and unpaid distributions (including as a result of any distributions paid in kind). Distributions are payable quarterly within 45 days after the end of the fiscal quarter. Distributions may be paid in-kind in lieu of cash distributions during the first 36 months following the September 23, 2019 initial closing date. Subsequent to the payment-in-kind period, all distributions must be paid in cash. In addition to the quarterly distributions paid to the Sponsor, Alkali Holdings will distribute all of its distributable cash to the Partnership each quarter, which is equal to all cash and cash equivalents in the operating accounts of Alkali Holdings less cash reserves and a minimum $5 million cash balance to be maintained for working capital needs. From time to time after we have drawn at least $250 million of our Preferred Commitment, 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 $250 million of our Preferred Commitment, and the Sponsor is not a "defaulting member" under the LLC Agreement, the Sponsor has the right to a make-whole amount on the number of undrawn preferred units. The Sponsor is obligated to purchase a minimum of $250 million of preferred units unless certain customary closing conditions are not satisfied, including the existence of a triggering event or a material uncured breach of the Securities Purchase Agreement by Alkali Holdings. A triggering event would occur if Alkali Holdings fails to pay cash distributions subsequent to the paid-in-kind period, fails to redeem preferred units when required to by a change of control event, or if any preferred units remain outstanding on the six year anniversary date, amongst other events. The preferred units must be redeemed, in whole or in part, following certain change of control events, fundamental changes, or the liquidation, winding up, or dissolution of Alkali Holdings and, as applicable, the Partnership. If such an event were to occur, the preferred units would rank senior to Alkali Holdings common units and any class or series of equity of Alkali Holdings established after the issuance of the preferred units. 68 Table of Contents At any time following the sixth 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, the Sponsor has the right to gain control of the board of Alkali Holdings and effectuate a monetization event using its reasonable good faith efforts to maximize the consideration received to the holders of our common units, including the sale of Alkali Holdings (including all of its equity or assets and all of its equity in its subsidiaries), the proceeds of which would first be used to redeem the preferred units at the Base Preferred Return prior to any distribution to us. See Note 12 for additional information regarding our mezzanine capital. Equity Distribution Program and Shelf Registration Statements We expect 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 2016, we implemented an equity distribution program that will allow us to consummate “at the market” offerings of common units from time to time through brokered transactions, which should help mitigate certain adverse consequences of underwritten offerings, including the downward pressure on the market price of our common units and the expensive fees and other costs associated with such public offerings. We entered into an equity distribution agreement with a group of banks who will act as sales agents or principals for up to $400.0 million of our common units, if and when we should elect to issue additional common units from time to time, although there are limits to the amount of our “at the market” offerings the market can absorb from time to time. In connection with implementing our equity distribution program, we filed a universal shelf registration statement (our "EDP Shelf") with the SEC. Our EDP Shelf allows us to issue up to $1.0 billion of equity and debt securities, whether pursuant to our equity distribution program or otherwise. Our EDP Shelf will expire in October 2020. As of December 31, 2019, we had issued no units under this program. We have another universal shelf registration statement (our "2018 Shelf") on file with the SEC. Our 2018 Shelf allows us to issue an unlimited amount of equity and debt securities in connection with certain types of public offerings. However, the receptiveness of the capital markets to an offering of equity and/or debt securities cannot be assured and may be negatively impacted by, among other things, our long-term business prospects and other factors beyond our control, including market conditions. Our 2018 Shelf will expire in April 2021. We expect to file a replacement universal shelf registration statement before our 2018 Shelf expires. Cash Flows from Operations We generally utilize the cash flows we generate from our operations to fund our common and preferred distributions and working capital needs. Excess funds that are generated are used to repay borrowings under our credit facility and/or to fund a portion of our capital expenditures. Our operating cash flows can be impacted by changes in items of working capital, primarily variances in the carrying amount of inventory and the timing of payment of accounts payable and accrued liabilities related to capital expenditures, 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. 69 Table of Contents Net cash flows provided by our operating activities were $382.3 million and $390.0 million for 2019 and 2018, respectively. As discussed above, changes in the cash requirements related to payment for petroleum products or collection of receivables from the sale of inventory impact the cash provided by operating activities. Additionally, changes in the market prices for crude oil, petroleum products and alkali products can result in fluctuations in our working capital and, therefore, our operating cash flows between periods as the cost to acquire a barrel of crude oil or petroleum products (or the cost to extract/ process in the case alkali products) will require more or less cash. The decrease in operating cash flow for 2019 compared to 2018 was primarily due a change in working capital needs during 2019. 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 and/or the issuance of senior unsecured notes. 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: Capital expenditures for fixed and intangible assets: Maintenance capital expenditures: Offshore pipeline transportation assets Sodium mineral and sulfur services assets Marine transportation assets Onshore facilities and transportation assets Information technology systems Total maintenance capital expenditures Growth capital expenditures: Offshore pipeline transportation assets Sodium minerals and sulfur services assets Marine transportation assets Onshore facilities and transportation assets Information technology systems Total growth capital expenditures Total capital expenditures for fixed and intangible assets Capital expenditures for business combinations, net of liabilities assumed: Acquisition of Alkali Business Capital expenditures related to equity investees Total capital expenditures Years Ended December 31, 2019 2018 2017 (in thousands) $ 16,848 $ 4,202 $ 42,065 40,820 2,966 1,197 103,896 55,377 18,308 3,340 72 81,299 $ 961 $ 501 $ 65,772 — 3,610 2,301 72,644 176,540 19,335 12,560 47,770 2,704 82,870 164,169 5,037 24,045 27,295 5,381 286 62,044 3,778 5,424 41,119 143,742 266 194,329 256,373 $ $ — $ — 176,540 $ — $ 1,325,000 4,647 $ 1,586,020 3,018 167,187 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. 70 Table of Contents Growth Capital Expenditures On September 23, 2019 we announced the GOP to expand our existing Granger facility, expected to be completed during 2022. We entered into agreements with funds affiliated with GSO for the purchase of up to $350 million of preferred units in Alkali Holdings. The proceeds we will receive from GSO will fund up to 100% of the anticipated cost of the GOP. The preferred unitholders will receive payment-in-kind in lieu of cash distributions during the anticipated construction period. As of December 31, 2019, we had issued 130,000 of preferred units to be used to fund the construction. The expansion is expected to increase our production at the Granger facility by approximately 750k tons per year. Except for the GOP, we do not anticipate spending material growth capital expenditures on any individual projects during 2020. Maintenance Capital Expenditures Maintenance capital expenditures increased during 2019 primarily due to the timing of the maintenance capital expenditures incurred related to our marine transportation segment to replace and upgrade certain equipment associated with our vessels. We also incur maintenance capital expenditures 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 incurred higher maintenance capital expenditures in 2019 to replace and upgrade equipment at certain of our offshore platforms and pipelines. We expect future expenditures to be within a reasonable range of 2019'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 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 14, 2020, we paid a distribution of $0.55 per unit related to the fourth quarter of 2019. With respect to our Class A Convertible Preferred Units, we have declared a quarterly cash distribution of $0.7374 per preferred unit (or $2.9496 on an annualized basis) for each preferred unit held of record. These distributions were paid on February 14, 2020 to unitholders holders of record at the close of business January 31, 2020. 71 Table of Contents Our historical distributions to common unitholders and Class A Convertible Preferred unitholders are shown in the table below (in thousands, except per unit amounts). Distribution For 2017 4th Quarter 2018 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter 2019 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Date Paid Per Common Unit Amount Total Amount Per Preferred Unit Amount (1) Total Amount (1) February 14, 2018 May 15, 2018 August 14, 2018 November 14, 2018 February 14, 2019 May 15, 2019 August 14, 2019 November 14, 2019 February 14, 2020 $ $ $ $ $ $ $ $ (2) $ 0.5100 0.5200 0.5300 0.5400 0.5500 0.5500 0.5500 0.5500 0.5500 $ $ $ $ $ $ $ $ $ 62,515 63,741 64,967 66,193 67,419 67,419 67,419 67,419 67,419 $ $ $ $ 0.2458 0.7374 0.7374 0.7374 $ $ $ $ 6,138 18,684 18,684 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 14, 2020 to unitholders of record as of January 31, 2020. Commitments and Off-Balance Sheet Arrangements Contractual Obligations and Commercial Commitments In addition to our credit facility discussed above, we have contractual obligations under operating leases as well as commitments to purchase crude oil and petroleum products. The table below summarizes our obligations and commitments at December 31, 2019. Commercial Cash Obligations and Commitments Less than one year Payments Due by Period 1 - 3 years 3 - 5 Years (in thousands) More than 5 years Total Contractual Obligations: Long-term debt, net of debt issuance costs (1) Estimated interest payable on long- term debt (2) Operating lease obligations Unconditional purchase obligations (3) Capital expenditure commitments (4) Asset retirement obligations (5) $ — $ 1,699,951 $ 742,520 $ 986,766 $ 3,429,237 218,144 39,783 44,531 — 26,580 376,568 55,999 8,100 72,350 6,086 165,461 45,008 8,100 — — 65,584 152,783 8,100 — 142,415 825,757 293,573 68,831 72,350 175,081 Total $ 329,038 $ 2,219,054 $ 961,089 $ 1,355,648 $ 4,864,829 (1) Our credit facility allows us to repay and re-borrow funds at any time through the maturity date of May 9, 2022. We have $750 million in aggregate principal amount of our 2022 Notes that mature on August 1, 2022, $400 million in aggregate principal amount of senior unsecured notes that mature on May 15, 2023 (the "2023 Notes"), $350 million in aggregate principal amount of senior unsecured notes that mature on June 15, 2024 (the "2024 Notes"), $550 million in aggregate principal amount of senior unsecured notes that mature on October 1, 2025 (the"2025 Notes"), and $450 million in aggregate principal amount of senior unsecured notes that mature on May 15, 2026 (the "2026 Notes"). Interest on our long-term debt under our credit facility is at market-based rates. The interest rates on our 2022, 2023, 2024, 2025, and 2026 Notes are 6.75%. 6.00%, 5.625%, 6.50%, and 6.25%, respectively. The amount shown for interest payments represents the (2) 72 Table of Contents amount that would be paid if the debt outstanding at December 31, 2019 under our credit facility remained outstanding through the final maturity date of May 9, 2022 and interest rates remained at the December 31, 2019 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, 2019 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. (4) We have entered into approximately $72 million of contracts with third parties for the construction of the GOP. These commitments will be funded by the issuance of 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, 2019 was $175.1 million and is further discussed in Note 8 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 pertain to measurement of the fair value of assets and liabilities in business acquisitions, depreciation, amortization and impairment of long-lived assets, deferred maintenance on marine fixed assets, equity plan compensation accruals and contingent and environmental liabilities. We discuss these policies 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. We cannot provide assurance that actual amounts will not vary significantly from estimated amounts. See Note 5 to our Consolidated Financial Statements in Item 8 regarding further discussion regarding our acquisitions. 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 73 Table of Contents on an annual basis to determine if adjustments are required. We are recording amortization of our customer and supplier relationships, licensing agreements, trade names, non-compete agreements, and other contract intangibles based on the period over which the asset is expected to contribute to our future cash flows. Generally, the contribution of these assets to our cash flows is expected to decline over time, such that greater value is attributable to the periods shortly after the acquisition was made. Our favorable lease and other intangible assets are being amortized on a straight-line basis over their expected useful lives. 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, 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 the asset. We did not record any impairments in 2019. For the year ended December 31, 2018, we recognized impairment expense of $103.2 million associated with long-lived assets (refer to Note 8 for additional details). Any such write-down of the value and unfavorable change in the useful life of an intangible asset would increase costs and expenses at that time. 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, 2019 for our refinery services reporting unit that has goodwill. No impairment was recorded in our refinery services segment during 2019 as the fair value far exceeded the carrying value. Our supply and logistics reporting unit, which primarily included our legacy crude oil and refined products marketing and trucking businesses, was determined to have a fair value lower than its carrying value and the partnership recorded an impairment charge of $23.1 million during 2018 (Note 10) to reduce the goodwill of the reporting unit to $0. One of our other monitoring procedures is the comparison of our market capitalization to our book equity on a quarterly basis to determine if there is an indicator of impairment. As of December 31, 2019, our market capitalization exceeded the book value of our equity (partner's capital) and there were no other indicators of impairment identified. For additional information regarding our goodwill, see Note 10 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 under this plan are comprised of both service-based and performance- based awards. Until the vesting date, we calculate estimates of the fair value of the awards and record that value as compensation expense during the vesting period on a straight-line basis. These estimates are based on the current trading price of our common units and an estimate of the forfeiture rate we expect may occur. For our performance-based awards, our fair 74 Table of Contents value estimates are weighted based on probabilities for each performance condition applicable to the award. At December 31, 2019, we had 310,848 phantom units outstanding and recorded expense of $1.8 million during 2019. The liability recorded for phantom units expected to vest fluctuates 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. At December 31, 2019, we estimated approximately $0.2 million of remaining compensation costs to be recognized over a weighted average period of approximately 4 months. Changes in our assumptions may impact our liabilities and expenses related to these awards. See Note 17 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 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, 2019. Derivatives related to the embedded derivatives in our 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, 2019, 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 In June 2016, the FASB issued ASU 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” ("ASU 2016-13"). ASU 2016-13 changes 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 will be required to use a new forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. The guidance also requires increased disclosures. ASU 2016-13 is effective for interim and annual periods beginning after December 15, 2019. The standard requires varying transition methods for the different categories of amendments. We have performed an assessment which consisted of reviewing current and historical information pertaining to our trade accounts receivable and existing contract assets and we anticipate no material impact to our consolidated financial statements as of the adoption date. 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. 75 Table of Contents We have adopted guidance under ASC Topic 606, Revenue from Contracts with Customers, and all related ASUs (collectively "ASC 606") as of January 1, 2018 utilizing the modified retrospective method of adoption. Refer to Note 3 for further details. In August 2016, the FASB issued guidance that addresses how certain cash receipts and payments are presented and classified in the statement of cash flows under Topic 230, Statement of Cash flow, and other Topics. The guidance is effective for annual reporting periods, and interim periods therein, beginning after December 15, 2017. We have adopted this guidance as of January 1, 2018 using the retrospective transition method to each period presented on the Consolidated Statements of Cash Flows. We reclassified $15.3 million from operating cash flows to investing cash flows for the year ended December 31, 2017. In March 2017, the FASB issued ASU 2017-07, Compensation-Retirement Benefits (Topic 715). ASU 2017-07 requires employers to separate the service cost component from the other components of net benefit cost in the period. The new standard requires the other components of net benefit costs (excluding service costs), be reclassified to "Other expense" from "General and administrative." We adopted this standard as of January 1, 2018. This standard is applied retrospectively. The effect was not material to our financial statements for any of the annual periods presented. In January 2017, the FASB issued guidance to simplify the goodwill impairment testing at annual or interim periods. The guidance eliminates Step 2 from the goodwill impairment testing process, and any identified impairment charge would be simplified to be the difference between the carrying value and fair value of a reporting unit, but would not exceed the total amount of goodwill allocated to the reporting unit in question. The guidance is effective for annual reporting periods, and interim periods therein, beginning after December 15, 2019. We elected to early adopt this standard as of January 1, 2017. See Note 10 for further information. Item 7a. Quantitative and Qualitative Disclosures About Market Risk We are exposed to various market risks, primarily related to volatility in crude oil and petroleum products prices, soda ash prices, NaHS and NaOH prices, natural gas prices and interest rates. Our policy is to purchase only commodity products for which we have a market, and to structure our sales and purchase contracts so that price fluctuations for those products do not materially affect the Segment Margin we receive. We do not acquire and hold futures contracts or other derivative products for the purpose of speculating on price changes. Our primary price risk relates to the effect of crude oil and petroleum products price fluctuations on our inventories and the fluctuations each month in grade and location differentials and their effect on future contractual commitments. Our risk management policies are designed to monitor our physical volumes, grades and delivery schedules to ensure our hedging activities address the market risks that are inherent in our gathering and marketing activities. We utilize NYMEX commodity based futures contracts and option contracts to hedge our exposure to these market price fluctuations as needed. All of our open commodity price risk derivatives at December 31, 2019 were categorized as non- trading. On December 31, 2019 we had entered into NYMEX future contracts that will settle between February and March 2020 and NYMEX options contracts that will settle during February and March 2020. Our Alkali Business relies on natural gas to generate heat and power for operations. We use a combination of commodity price swap contracts and future purchase contracts to manage our exposure to fluctuations in natural gas prices. The swap contracts fix the basis differential between NYMEX Henry Hub and NW Rocky Mountain posted prices. As of December 31, 2019 we had entered into NYMEX future contracts and over the counter swap contracts that will settle between January and December 2020. This accounting treatment is discussed further in Note 19 to our Consolidated Financial Statements. We believe our hedging activities have been successful in helping to mitigate these risks. The table below presents information about our open commodity derivative contracts at December 31, 2019. Notional amounts in barrels or gallons, the weighted average contract price, total contract amount and total fair value amount in U.S. dollars of our open positions are presented below. Fair values were determined by using the notional amount in barrels or gallons multiplied by the December 31, 2019 quoted market prices. All of the hedge positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the table below. 76 Table of Contents Unit of Measure for Volume Contract Volumes (in 000’s) Unit of Measure for Price Weighed Average Market Price Contract Value (in 000’s) Mark-to Market Change (in 000’s) Settlement Value (in 000’s) Futures and Swap Contracts Sell (Short) Contracts: Crude Oil Natural Gas Swaps Natural Gas Bbl MMBTU MMBTU 98 Bbl 503 MMBTU 92 MMBTU Buy (Long) Contracts: Crude Oil Natural Gas Option Contracts Written Contracts: Crude Oil Purchased Contracts: Crude Oil Bbl 80 Bbl MMBTU 576 MMBTU Bbl Bbl 40 Bbl 18 Bbl $ $ $ $ $ $ $ 59.93 0.38 2.27 $ $ $ 5,872 1,890 2,092 $ $ $ 107 $ (1,382) $ (106) $ 5,979 508 1,986 60.25 $ 4,820 $ 2.60 14,992 61 $ (1,923) $ 4,881 13,069 1.03 $ 41 $ 31 $ 72 0.66 $ 12 $ 4 $ 16 We manage our risks of volatility in NaOH prices by indexing prices for the sale of NaHS to the market price for NaOH in most of our contracts. Given the competitive advantages associated with our naturally produced soda ash as previously discussed (relative to that which is synthetically produced), we believe this somewhat mitigates market risk within our Alkali Business. We are also exposed to market risks due to the floating interest rates on our credit facility. Obligations under our senior secured credit facility bear interest at the LIBOR rate or alternate base rate (which approximates the prime rate), at our option, plus the applicable margin. We have not historically hedged our interest rates. On December 31, 2019, we had $1.0 billion of debt outstanding under our credit facility. For the year ended December 31, 2019, a 10% change in LIBOR would have resulted in approximately a $4.2 million change in net income. The Preferred Distribution Rate Reset Election of our Class A convertible preferred units is an embedded derivative that must be bifurcated from the related host contract, the preferred unit purchase agreement, and recorded at fair value in our Consolidated Balance Sheets. The valuation model utilized for this embedded derivative contains inputs including our common unit price, U.S. treasury rates and dividend yields to ultimately calculate the fair value of our Class A convertible preferred units with and without the Preferred Distribution Rate Reset Option. See Note 12 to our Consolidated Financial Statements for a discussion of embedded derivatives. Item 8. Financial Statements and Supplementary Data The information required hereunder is included in this report as set forth in the “Index to Consolidated Financial Statements.” Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. Item 9A. Controls and Procedures Evaluation of Disclosure Controls and Procedures We maintain disclosure controls and procedures and internal controls designed to ensure that information required to be disclosed in our filings under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our chief executive officer and chief financial officer, with the participation of our management, have evaluated our disclosure controls and procedures as of the end of the period covered by this Annual Report on Form 10-K and have determined that such disclosure controls and procedures 77 Table of Contents are effective in providing assurance of the timely recording, processing, summarizing and reporting of information, and in accumulation and communication to management on a timely basis material information relating to us (including our consolidated subsidiaries) required to be disclosed in this Annual Report on Form 10-K. Changes in Internal Controls over Financial Reporting There were no changes during our last fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Management’s Report on Internal Control over Financial Reporting Management of the Partnership is responsible for establishing and maintaining effective internal control over financial reporting as defined in Rules 13a-15(f) under the Securities Exchange Act of 1934. The Partnership’s internal control over financial reporting is designed to provide reasonable assurance to the Partnership’s management and board of directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Management assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2019. In making this assessment, management used the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). Based on our assessment, we believe that, as of December 31, 2019, the Partnership’s internal control over financial reporting is effective based on those criteria. Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, our management included a report of their assessment of the design and effectiveness of our internal controls over financial reporting as part of this Annual Report on Form 10-K for the fiscal year ended December 31, 2019. Ernst & Young LLP, the Partnership’s independent registered public accounting firm, has issued an attestation report on the effectiveness of the Partnership’s internal control over financial reporting. Ernst & Young’s attestation report on the Partnership’s internal control over financial reporting appears in Item 8. “Financial Statements and Supplementary Data.” 78 Table of Contents Item 9B. Other Information None. Item 10. Directors, Executive Officers and Corporate Governance Management of Genesis Energy, L.P. Part III We are a Delaware limited partnership. We conduct our operations and own our operating assets through our subsidiaries and joint ventures. Our general partner, Genesis Energy, LLC, a wholly-owned subsidiary that owns a non- economic general partner interest in us, has sole responsibility for conducting our business and managing our operations. It also employs most of our personnel, including executive officers. Employees of our Alkali operations are employed by our subsidiary, Genesis Alkali, LLC. The board of directors of our general partner (which we refer to as “our board of directors”) must approve significant matters (such as material business strategies, mergers, business combinations, acquisitions or dispositions of assets, issuances of common units, incurrences of debt or other financings and the payments of distributions). The holders of our Class B Common Units are entitled to (i) vote in the election of our board of directors, subject to the Davison family’s rights under its unitholder rights agreement (described below), as well as (ii) vote on substantially all other matters on which our Class A holders are entitled to vote. The holders of our Class A Common Units are not entitled to vote in the election of directors, but they are entitled to vote in a very limited number of other circumstances, including our merger with another company. As is common with MLPs, our partnership structure does not grant our unitholders (in such capacity) the right to directly or indirectly participate in our management or operations other than through the exercise of their limited voting rights. Collectively, members of the Davison family own approximately 10.4% of our Class A Common Units and 77.0% of our Class B Common Units, for a combined ownership percentage of 10.4% of total Common Units. Pursuant to its unitholder rights agreement, the Davison family is entitled to elect up to three of our directors based on its members’ collective ownership percentage of our outstanding common units: (i) with 15% or more ownership, they have the right to appoint three directors, (ii) with less than 15% ownership but more than 10%, they have the right to appoint two directors, and (iii) with less than 10% ownership, they have the right to appoint one director. That unitholder rights agreement also provides that, so long as the Davison family has the right to elect three directors thereunder, our board of directors cannot have more than 11 directors without the Davison family’s consent. In addition to their rights under that unitholder rights agreement, if the members of the Davison family act as a group, they have the ability to elect at least a majority of our directors because they own a majority of our Class B units. Under our limited partnership agreement, the organizational documents of our general partner and indemnification agreements with our directors, subject to specified limitations, we will indemnify to the fullest extent permitted by Delaware law, from and against all losses, claims, damages or similar events, any director or officer, or while serving as director or officer, any person who is or was serving as a tax matters member or as a director, officer, tax matters member, employee, partner, manager, fiduciary or trustee of our partnership or any of our affiliates. Additionally, we will indemnify to the fullest extent permitted by law, from and against all losses, claims, damages or similar events, any person who is or was an employee (other than an officer) or agent of our general partner. Our board of directors currently consists of Sharilyn S. Gasaway, James E. Davison, James E. Davison, Jr., Kenneth M. Jastrow II, Conrad P. Albert, Jack T. Taylor and Mr. Sims. Our board of directors has determined that each of Ms. Gasaway and Messrs. Jastrow, Albert and Taylor is an independent director under the NYSE rules. Board Leadership Structure and Risk Oversight Board Leadership Structure Our board of directors has no policy that requires the positions of the Chairman of the Board and the Chief Executive Officer to be held by the same or different persons or that we designate a lead or presiding independent director. Our board of directors believes it is important to retain the flexibility to make those determinations based on an assessment of the circumstances existing from time to time, including the composition, skills and experience of our board of directors and its members, specific challenges faced by the company or the industry in which it operates, and governance efficiency. Presently, our board of directors believes that, because Mr. Sims is the director most familiar with our business and industry and the most capable of leading the discussion of, and executing on, our business strategy, he is best situated to serve as Chairman, regardless of the fact that he is the Chief Executive Officer of our general partner. Our board of directors also believes that the appointment of a lead independent director, who will preside over executive sessions of non-management directors of our board of directors, will facilitate teamwork and communication between the non-management directors and 79 Table of Contents management. Our board of directors appointed Mr. Jastrow as our lead independent director because of his executive experience and service as a director of other companies. Our board of directors believes that the combined role of Chairman and Chief Executive Officer working with the lead independent director is currently in the best interest of unitholders, providing the appropriate balance between developing our strategy and overseeing management. On September 1, 2017, we sold $750 million of Class A convertible preferred units in a private placement, comprised of 22,249,494 units for a cash purchase price per unit of $33.71 (subject to certain adjustments, the “Issue Price”) to two initial purchasers. In connection with the private placement, we have granted each initial purchaser (including its applicable affiliate transferees) certain rights, including (i) the right to appoint an observer, who shall have the right to attend our board meetings for so long as an initial purchaser (including its affiliates) owns at least $200 million of our preferred units and (ii) the right to appoint two directors to our general partner’s board of directors if (and so long as) we fail to pay in full any three quarterly distribution amounts, whether or not consecutive, attributable to any period ending after March 1, 2019. We are committed to sound principles of governance. Such principles are critical for us to achieve our performance goals and maintain the trust and confidence of investors, personnel, suppliers, business partners and stakeholders. We believe independent directors are a key element for strong governance, although we have reserved or exercised our right as a limited partnership under the listing standards of the NYSE not to comply with certain requirements of the NYSE. For example, although at least a majority of the members of our board of directors is independent under the NYSE rules, we reserve the right not to comply with Section 303A.01 of the NYSE Listed Company Manual in the future, which would require that our board of directors be comprised of at least a majority of independent directors. In addition, among other things, we have elected not to comply with Sections 303A.04 and 303A.05 of the NYSE Listed Company Manual, which would require our board of directors to maintain a nominating/corporate governance committee and a compensation committee, each consisting entirely of independent directors. Our corporate governance guidelines are available on our website (www.genesisenergy.com) free of charge. For further discussion of director independence, please see Item 13. "Certain Relationships and Related Transactions, and Director Independence—Director Independence." Risk Oversight We face a number of risks, including exposure to matters relating to the environment, regulation, competition, fluctuations in commodity prices and interest rates and severe weather. Management is responsible for the day-to-day management of the risks our company faces, although our board of directors, as a whole and through its committees, has responsibility for the oversight of risk management. In fulfilling its risk oversight role, our board of directors must determine whether risk management processes designed and implemented by our management are adequate and functioning as designed. Senior management regularly delivers presentations to our board of directors on strategic matters, operations, risk management and other matters, and are available to address any questions or concerns raised by our board of directors. Board of directors meetings also regularly include discussions with senior management regarding strategies, key challenges and risks and opportunities for our company. Our board committees assist our board of directors in fulfilling its oversight responsibilities in certain areas of risk. For example, the audit committee assists with risk management oversight in the areas of financial reporting, internal controls and compliance with legal and regulatory requirements and our risk management policy relating to our hedging program. The governance, compensation and business development committee assists our board of directors with risk management relating to our compensation policies and programs. Our board of directors believes that it is important to align (when practical) the interests of the members of our board of directors and certain of our officers with the interests of our long-term stakeholders. Our board of directors has adopted certain policies to further promote that alignment of interests. For example, among other things, our policies prohibit our directors and officers from (i) buying, selling or engaging in transactions with respect to our common units while they are aware of material non-public information and (ii) engaging in short sales of our securities. Certain of our directors and/or officers own substantial amounts of our units, some of which are pledged, including being held in broker margin accounts. See Item 12. "Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters." Audit Committee The audit committee of our board of directors generally oversees our accounting policies and financial reporting and the audit of our financial statements. The audit committee assists our board of directors in its oversight of the quality and integrity of our financial statements and our compliance with legal and regulatory requirements. Our independent registered public accounting firm is given unrestricted access to the audit committee. Our board of directors has determined that the members of the audit committee meet the independence and experience standards established by NYSE and the Securities Exchange Act of 1934, as amended. In accordance with the NYSE rules and the Securities Exchange Act of 1934, as amended, our board of directors has named three of its members to serve on the audit committee—Sharilyn S. Gasaway, Conrad P. Albert and Jack T. Taylor. Ms. Gasaway is the chairperson. Our board of directors believes that Ms. Gasaway and Mr. Taylor qualify 80 Table of Contents as audit committee financial experts as such term is used in the rules and regulations of the SEC. The charter of the audit committee is available on our website (www.genesisenergy.com) free of charge. Each member of the audit committee is an independent director under NYSE rules. Governance, Compensation and Business Development Committee The governance, compensation and business development committee, or G&C Committee, of our board of directors generally (i) monitors compliance with corporate governance guidelines, (ii) reviews and makes recommendations regarding board and committee composition, structure, size, compensation and related matters, and (iii) oversees compensation plans and compensation decisions for our employees. All the members of our board of directors, other than our CEO, serve as members of the G&C Committee. Mr. Jastrow is the chairperson. The charter of the G&C Committee is available on our website (www.genesisenergy.com) free of charge. Conflicts Committee To the extent requested by our board of directors, a conflicts committee of our board of directors would be appointed to review specific matters in connection with the resolution of conflicts of interest and potential conflicts of interest between any of our affiliates and us. If a specific review is requested by our board of directors, our conflicts committee would be formed by our Board and would be comprised solely of independent directors. See Item 13. “Certain Relationships and Related Transactions, and Director Independence—Review or Special Approval of Material Transactions with Related Persons.” Executive Sessions of Non-Management Directors Our board of directors holds executive sessions in which non-management directors meet without any members of management present in connection with regular board meetings. The purpose of these executive sessions is to promote open and candid discussion among the non-management directors. Mr. Jastrow, as the lead independent director, serves as the presiding director at those executive sessions. In accordance with NYSE rules, interested parties can communicate directly with non-management directors by mail in care of the General Counsel and Secretary or in care of the chairperson of the audit committee at 919 Milam, Suite 2100, Houston, TX 77002. Such communications should specify the intended recipient or recipients. Commercial solicitations or communications will not be forwarded. We have established a toll-free, confidential telephone hotline so that interested parties may communicate with the chairperson of the audit committee or with all the non- management directors as a group. All calls to this hotline are reported to the chairperson of the audit committee who is responsible for communicating any necessary information to the other non-management directors. The number of our confidential hotline is (800) 826-6762. 81 Table of Contents Directors and Executive Officers Set forth below is certain information concerning our directors and executive officers, effective as of February 27, 2020. Name Grant E. Sims Conrad P. Albert James E. Davison James E. Davison, Jr. Sharilyn S. Gasaway Kenneth M. Jastrow II Jack T. Taylor Robert V. Deere Edward T. Flynn Richard R. Alexander Karen N. Pape Kristen O. Jesulaitis William S. Goloway Garland G. Gaspard Chad A. Landry Ryan S. Sims Age 64 73 82 53 51 72 68 65 61 44 61 50 59 65 56 36 Director, Chairman of the Board, and Chief Executive Officer Position Director Director Director Director Director Director Chief Financial Officer Executive Vice President Vice President Senior Vice President and Controller General Counsel Vice President Senior Vice President Vice President Senior Vice President Grant E. Sims has served as a director and Chief Executive Officer of our general partner since August 2006 and Chairman of the Board of our general partner since October 2012. Mr. Sims was affiliated with Leviathan Gas Pipeline Partners, LP from 1992 to 1999, serving as the Chief Executive Officer and a director beginning in 1993 until he left to pursue personal interests, including investments. Leviathan (subsequently known as El Paso Energy Partners, L.P. and then GulfTerra Energy Partners, L.P.) was a NYSE listed master limited partnership. Mr. Sims has an established track record of developing strong companies and has led his companies through a period of substantial growth while increasing geographic and operational diversity. Mr. Sims provides leadership skills, executive management experience and significant knowledge of our business environment, which he has gained through his vast experience with other MLPs. Conrad P. Albert has served as a director of our general partner since July 2013. Mr. Albert is a private investor and was formerly a director of Anadarko Petroleum Corporation from 1986 to 2006. Mr. Albert also served as a director of DeepTech International, Inc. from 1992 to 1998. From 1969 to 1991, Mr. Albert served in various positions with Manufacturers Hanover Trust Company, ultimately serving as Executive Vice President in charge of worldwide energy lending and corporate finance. Mr. Albert’s extensive financial, executive and directorial experience and his service in various roles in the management of other energy-related companies will allow him to provide valuable expertise to our board of directors. James E. Davison has served as a director of our general partner since July 2007. Mr. Davison served as chairman of the board of Davison Transport, Inc. for over 30 years. He also serves as President of Terminal Services, Inc. Mr. Davison has over forty years of experience in the energy-related transportation and sulfur removal businesses. Mr. Davison brings to our board of directors significant energy-related transportation and sulfur removal experience and industry knowledge. James E. Davison, Jr. has served as a director of our general partner since July 2007. Mr. Davison is also a director of another public company, Origin Bancorp, Inc., and serves on its finance, risk and insurance committees. Mr. Davison is the son of James E. Davison. Mr. Davison’s executive and leadership experience enable him to make valuable contributions to our board of directors. Sharilyn S. Gasaway has served as a director of our general partner since March 2010 and serves as chairperson of the audit committee. Ms. Gasaway is a private investor and was Executive Vice President and Chief Financial Officer of Alltel Corporation, a wireless communications company, from 2006 to 2009, and served as Controller of Alltel Corporation from 2002 through 2006. In her role as CFO, Ms. Gasaway was responsible for the company's finance, financial reporting, and risk management roles, and gained extensive experience in corporate performance and strategic planning. She brings this vast knowledge to the Partnership. Ms. Gasaway is a director of two other public companies, JB Hunt Transport Services, Inc. and Waddell and Reed Financial, Inc., serving on the audit committee of each company. Additionally, Ms. Gasaway serves on the compensation and nominating committees of JB Hunt and the nominating and corporate governance committee of Waddell and 82 Table of Contents Reed. Ms. Gasaway provides our board of directors valuable business experience, risk management and financial expertise, including an understanding of the accounting, compliance and financial matters that we address on a regular basis. Kenneth M. Jastrow II has served as a director of our general partner since March 2010 and serves as our lead independent director and the chairperson of the G&C Committee. Mr. Jastrow served as Chairman and Chief Executive Officer of Temple-Inland, Inc., a manufacturing company and the former parent of Forestar Group, from 2000 to 2007. Prior to that, Mr. Jastrow served in various roles at Temple-Inland, including President and Chief Operating Officer, Group Vice President and Chief Financial Officer. Mr. Jastrow is also a director and serves on the compensation committee of KB Home and MGIC Investment Corporation. Mr. Jastrow formerly served as Non-Executive Chairman of Forestar Group, Inc. Mr. Jastrow’s executive experience and service as director of other companies enable him to make valuable contributions to our board of directors and particularly well suited to be the lead independent director. Jack T. Taylor has served as a director of our general partner since July 2013. Mr. Taylor is currently a director of Sempra Energy and Murphy USA Inc. Additionally, Mr. Taylor currently serves on the audit committee of Sempra Energy and Murphy USA Inc. Mr. Taylor was a partner of KPMG LLP for 29 years, where from 2005 to 2010 he served as KPMG's Chief Operating Officer-Americas and Executive Vice Chair of U.S. Operations and from 2001 to 2005 he served as the Vice Chairman of U.S. Audit and Risk Advisory Services. Mr. Taylor’s extensive experience with financial and public accounting issues, his various leadership roles at KPMG LLP and his extensive knowledge of the energy industry make him a valuable resource to our board of directors. Robert V. Deere has served as Chief Financial Officer of our general partner since October 2008. Mr. Deere served as Vice President, Accounting and Reporting at Royal Dutch Shell (Shell) from 2003 through 2008. Edward T. Flynn has served as Executive Vice President of our general partner and President, Genesis Alkali since we acquired that business from Tronox Ltd. in September 2017 (where he also previously served as Executive Vice President). Prior to joining Tronox, Mr. Flynn served as President of FMC Minerals. He was previously President of FMC’s Industrial Chemicals Group. Mr. Flynn is a member of the Board of Directors and Chairman of the Board for ANSAC. Richard R. Alexander has served as Vice President of our general partner since November 2014. Mr. Alexander is responsible for the commercial aspects of our marine transportation segment. Since 2008, Mr. Alexander has served in various capacities within our marine operations. Karen N. Pape has served as Senior Vice President and Controller of our general partner since July 2007 and served as Vice President and Controller from May 2002 until July 2007. Kristen O. Jesulaitis has served as an executive officer of our general partner since January 2017. Ms. Jesulaitis has served as our General Counsel since July 2011. She is responsible for all legal functions of Genesis, including acquisitions and commercial transactions, compliance and regulatory affairs, corporate governance, securities, and finance. Prior to joining Genesis, Ms. Jesulaitis was a partner at the law firm Akin Gump Strauss Hauer & Feld LLP principally engaged in the areas of corporate and securities law, with primary focus in the midstream energy sector. William S. Goloway has served as Vice President of our general partner since January 2017. Mr. Goloway has been responsible for the commercial aspects of our offshore Gulf of Mexico assets from the time we acquired these offshore assets from Enterprise Products in 2015. Prior to this acquisition, Mr. Goloway served in various roles within the offshore group at Enterprise Products since 2005. Garland G. Gaspard has served as Senior Vice President of our general partner since January 2017 and is responsible for the operational aspects of our onshore and offshore pipelines, rail facilities, terminals, offshore facilities and assets, engineering, trucking and health, safety, security and environmental compliance. Mr. Gaspard joined Genesis in 2015 as a result of our acquisition of the offshore Gulf of Mexico assets from Enterprise Products and has had responsibility for the operational aspects of our offshore assets since that time. Prior to this acquisition, Mr. Gaspard served in various capacities within Enterprise Products' operations including underground gas storage, natural gas liquids, natural gas pipelines and offshore operations. Chad A. Landry has served as Vice President of our general partner since January 2017. Mr. Landry joined Genesis in 2013 and since that time has been responsible for all operational and commercial aspects of our sodium minerals and sulfur services segment. Prior to joining Genesis, he spent 14 years at Axiall Corporation (Georgia Gulf), most recently as Vice President - Chlor-Alkali & Vinyls. Ryan S. Sims has served as Senior Vice President of our general partner since March 2019. Mr. Sims served as Vice President from January 2017 to March 2019. Mr. Sims joined Genesis in 2011 and is responsible for our finance, planning, corporate development, and investor relations functions. He has also previously been responsible for the operational and commercial aspects of our rail and terminals businesses. Prior to joining Genesis, Mr. Sims spent six years in the investment banking industry. Mr. Sims is the son of Grant E. Sims, our Chairman and Chief Executive Officer. 83 Table of Contents Common Unit Ownership by Directors and Executive Officers We encourage our directors and officers to own our common units, although we do not feel it is necessary to require them to own a minimum number. Certain of our directors and officers own substantial amounts of our securities, although any (or all) of them may sell, pledge or otherwise dispose of all or a portion of those securities at any time, subject to any applicable legal and company policy requirements. See Item 10. “Directors, Executive Officers and Corporate Governance-Board Leadership Structure and Risk Oversight-Risk Oversight.” Code of Ethics We have adopted a Code of Business Conduct and Ethics that is applicable to, among others, the principal financial officer and the principal accounting officer. Our Code of Business Conduct and Ethics is posted at our website (www.genesisenergy.com), where we intend to report any changes or waivers. Item 11. Executive Compensation The Compensation Discussion and Analysis below discusses our compensation process, objectives and philosophy with respect to our Named Executive Officers (“NEOs”), for the fiscal year ended December 31, 2019. Compensation Discussion and Analysis Named Executive Officers Our NEOs for 2019 were: • • • • • Grant E. Sims, Chief Executive Officer; Robert V. Deere, Chief Financial Officer; Edward T. Flynn, Executive Vice President; Richard R. Alexander, Vice President; Chad A. Landry, Vice President. Board and Governance, Compensation and Business Development Committee Our board of directors is responsible for, and effectively determines, compensation programs applicable to our NEOs and to the board itself. Our board of directors has delegated to the G&C Committee, of which a majority of the members are "independent," according to NYSE listing standards, the authority and responsibility to regularly analyze and evaluate our compensation policies, to determine the annual compensation of our NEOs, and to make recommendations to our board of directors with respect to such matters. As described in more detail below, the G&C Committee engaged BDO USA, LLP, or BDO, as its independent compensation adviser. We also utilize committees comprised solely of certain of our independent directors (i.e., the audit committee or special committees) to review and make recommendations with respect to certain matters such as obtaining exemptions from the “insider trading” rules under Section 16 of the Exchange Act in connection with certain acquisitions. Because the G&C Committee is comprised of all the members of our board of directors, excluding our CEO, determinations and recommendations by the G&C Committee are effectively determinations by our board of directors, which has approval authority for all such compensation matters. For a more detailed discussion regarding the purposes and composition of board committees, please see Item 10. “Directors, Executive Officers and Corporate Governance.” Committee/Board Process Following the end of each calendar year, our CEO reviews the compensation of all the other NEOs and makes a proposal to the G&C Committee regarding their compensation. The CEO's proposal is based on (among other things) our financial results for the prior year, the relevant executive’s areas of responsibility, market data provided by our independent compensation adviser and recommendations from the relevant executive’s supervisor (if other than our CEO). The G&C Committee reviews the compensation of our CEO and the proposal of our CEO regarding the compensation of the other NEOs and makes a final determination (and a recommendation to our board of directors) regarding the compensation of our NEOs. Depending on the nature and quantity of changes made to that proposal, there may be additional G&C Committee meetings and discussions with our CEO in advance of that determination. Our board of directors has final approval authority for all such compensation matters. 84 Table of Contents Committee/Board Approval The G&C Committee determines salaries, annual cash incentives and long-term awards for executive officers, taking into consideration the CEO’s recommendation regarding the NEOs. In April, any applicable salary increases, retention bonuses and long-term incentive awards are made or granted. Role of Compensation Consultant and Peer Group Analysis The G&C Committee’s charter authorizes it to retain independent compensation consultants from time to time to serve as a resource in support of its efforts to carry out certain duties. In 2019, the G&C Committee engaged BDO, an independent compensation consultant, to assist the G&C Committee in assessing and structuring competitive compensation packages for the executive officers that are consistent with our compensation philosophy. The G&C Committee assessed the independence of BDO pursuant to current exchange listing requirements and SEC guidance and concluded that no conflict of interest exists that would prevent BDO from serving as an independent consultant to the G&C Committee. At the request of the G&C Committee, BDO reviewed and provided input on the compensation of our NEOs, trends in executive compensation, meeting materials circulated to the G&C Committee, and management’s recommendations regarding executive compensation plans. BDO also developed assessments of market levels of compensation through an analysis of peer data and information disclosed in our peer companies’ public filings, but did not determine or recommend the amount of compensation. The peer group used for this market analysis in 2019 consisted of the following 15 companies in the energy industry: American Midstream Partners, Buckeye Partners, Calumet Specialty Products Partners, Crestwood Energy Partners, EnLink Midstream Partners, Magellan Midstream Partners, NGL Energy Partners, NuStar Energy, Plains All American Pipeline, Summit Energy Partners, Delek US Holdings, HollyFrontier Corp, SemGroup Corp, Tallgrass Energy and Targa Resources Corp. These companies were selected as the compensation peer group for any or all of the following reasons: 1) they reflect our industry competitors for products and services; 2) they operate in similar markets or have comparable geographical reach; 3) they are of similar size and maturity to us; or 4) they are companies that have similar credit profiles to us and/or their growth or capital programs are similar to ours. The G&C Committee reviews the peer group annually and may, from time to time, add or remove companies in order to assure the composition of the group meets the criteria outlined above. The information that BDO compiled included compensation trends for MLPs and levels of compensation for similarly-situated executive officers of companies within this peer group. We believe that compensation levels of executive officers in our peer group are relevant to our compensation decisions because we compete with those companies for executive management talent. Compensation Objectives and Philosophy The primary objectives of our compensation program are to: • encourage our executives to build and operate the partnership in a way that is aligned with our common unitholders’ interests, focusing on growing total unitholder returns and growing the asset base with an emphasis on maintaining a focus on the long-term stability of the enterprise so as to not promote inappropriate risk taking; • offer near-term and long-term compensation opportunities that are consistent with industry norms; and • provide appropriate levels of retention to the executive team to ensure long-term continuity and stability for the successful execution of key growth initiatives and projects. We strive to accomplish these objectives by providing all employees, including our NEOs, with a total compensation package that is market competitive and performance-based. In our assessment of the market competitiveness of compensation, we take into consideration the compensation offered by companies in our peer group described above, but we have not identified a specific percentile of peer company pay as a target. Rather, we use market information as one consideration in setting compensation along with individual performance, our financial and operational performance and our safety performance. We pay base salaries at levels that we feel are appropriate for the skills and qualities of the individual NEOs based on their past performance, current scope of responsibilities and future potential. The incentive-based components of each NEO’s compensation include annual cash bonus opportunities and participation in the long-term incentive program. The annual cash bonus rewards incremental operational and financial achievements required to meet investor expectations in the short-term 85 Table of Contents while the long-term component focuses rewards to the long-term stability of the enterprise. Both incentive components are generally linked to base salary and are consistent in general with our understanding of market practice and with our judgment regarding each individual’s role in the organization. As described in more detail below, we believe that the combination of base salaries, cash bonuses and long-term cash-based incentive plans provide an appropriate balance of short and long-term incentives, and alignment of the incentives for our executives, including our NEOs, with the interests of our common unitholders. The amount of compensation contingent on performance is a significant percentage of total compensation, therefore ensuring that business decisions and actions lead to the long-term growth and sustainability of the organization. Our bonus plan (including annual and retention bonuses) is driven by the generation of Available Cash before Reserves (as defined in Item. 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations-Financial Measures") (which is an important metric of value for our unitholders) and our safety record with the goal of retention of key employees and NEOs. Our long term incentive plan is also linked to our generation of Available Cash before Reserves and safety record, as well as the partnership's leverage ratio. Elements of Our Compensation Program and Compensation Decisions for 2019 The primary elements of our compensation program are a combination of annual cash and long-term incentive-based compensation. For the year ended December 31, 2019, the elements of our compensation program for the NEOs consisted of the following: • • • annual base salary discretionary annual cash and bonus awards annual grants under long-term incentive arrangements Additionally, in order to attract qualified executive personnel, we may make one-time new-hire awards of equity. Base Salaries We believe that base salaries should provide a fixed level of competitive pay that reflects the executive officer’s primary duties and responsibilities, and which provides a foundation for incentive opportunities and benefit levels. As discussed above, the base salaries of our NEOs are reviewed annually by the G&C Committee, taking into account recommendations from our CEO regarding NEOs other than himself. We pay base salaries at a level that we feel is appropriate for the skills and qualities of the individual NEOs based on their past performance, current scope of responsibilities and future potential. Base salaries may be adjusted to achieve what is determined to be a reasonably competitive level or to reflect promotions, the assignment of additional responsibilities, individual performance or company performance. Salaries are also periodically adjusted based on analysis of peer group practices as described above. In April 2019, the G&C Committee reviewed the assessments of market levels of compensation developed by BDO in conjunction with a discussion of individual performance and responsibilities. As a result of and taking into account current market conditions, the 2019 base salaries of all NEOs remained the same from 2018. Bonuses Our NEOs typically participate in a bonus program, or the Bonus Plan, in which substantially all company employees participate. As designed by the G&C Committee, each NEO has an annual bonus target based on a stated percentage of his base salary. The targeted amount for the NEOs is established based on the analysis of market practices of the peer group and consideration of the level of salary and targeted long-term incentives for each NEO. Based on the G&C Committee's subjective review of 2019 operational and financial performance, in the context of total NEO compensation, a discretionary bonus was granted to Mr. Flynn in the amount of $360,000, in recognition of his leadership in his respective area and his individual contribution to the Partnership's performance. This bonus will be paid in March 2020, contingent on Mr. Flynn's employment on the payment date. Further, it was determined by the G&C Committee that each NEO will be considered for a retention bonus for 2019, as further discussed below. Our NEOs may participate in a retention bonus program for which certain key employees, managers and officers are eligible. These retention bonuses are discretionary and are awarded based on individual and company performance with the goal of retaining key employees. In 2019, Mr. Sims was granted a retention bonus of $600,000, Messrs. Deere, Flynn and Landry were granted retention bonuses of $300,000 each, and Mr. Alexander was granted a retention bonus of $200,000, to be paid in five equal installments at the following dates: March 2020, June 2020, September 2020, December 2020, and March 2021, contingent upon continued employment at those dates. Given the near-term economic challenges faced by us and the industry generally, we believe that these retention bonuses are an appropriate mechanism to incentivize key executives to remain with us so that we may benefit from their experience in the industry and other competitive opportunities available to them. Over the long term, the G&C committee intends to continue performance-based cash incentives as a cornerstone of our executive pay program. 86 Table of Contents Long-Term Incentive Compensation We generally provide certain long-term compensation (cash and equity-based) to directors, officers, and certain employees through our long-term incentive compensation plans, or LTIPs. Our G&C Committee designs those awards to align the interests of plan participants with the interests of our long-term unitholders by promoting a sense of proprietorship and personal involvement in our development, growth, and financial success. Our LTIPs have given us flexibility to grant deferred compensation awards in the form of equity or cash-based compensation that vests outright or upon the satisfaction of one or more conditions that reward measurable service and performance, including the passage of time, continued employment, financial, and operating (including safety and environmental) metrics and the appreciation in our unit price over time. For reasons discussed below, in 2018 our G&C Committee adopted our 2018 LTIP. Like our 2010 LTIP, our 2018 LTIP permits awards of equity-based compensation in the form of phantom units and distribution equivalent rights, or DERs. Phantom units are notional units representing unfunded and unsecured promises to pay to the participant a specified amount of cash based on the market value of our common units should specified vesting requirements be met. DERs are tandem rights to receive on a quarterly basis an amount of cash equal to the amount of distributions that would have been paid on outstanding phantom units had they been limited partner units issued by us. In addition, our 2018 LTIP permits cash-based awards. Our G&C Committee administers our LTIPs and has broad authority to grant awards under and alter, amend, or terminate our LTIPs. For example, our G&C Committee has the authority to determine (i) who (if anyone) will receive awards from time to time as well as (ii) the size, nature, terms and conditions of such award. Our G&C Committee also has the authority to adopt, alter, and repeal rules, guidelines and practices relating to our LTIPs and interpret our LTIPs. Our board of directors can terminate the LTIPs at any time. Prior to 2018, we have provided long-term-equity-based compensation for our officers, directors, and certain employees primarily in the form of phantom units and distribution equivalent rights, or DERs, with vesting conditions that were tied to continuing increases in our (i) quarterly distribution rate consistent with our then existing business strategy and (ii) our unit price. In October 2017, our management completed a strategic review and analysis of our capital allocation program and decided that, due to dramatic changes in how the market views MLP units, it was in the best long-term interest of our unitholders to further strengthen our balance sheet and enhance our financial flexibility. We therefore implemented a strategy to re-allocate capital by, among other things, reducing our quarterly distribution rate per unit to $0.50 (from $0.71). That distribution reset immediately resulted in all outstanding 2010 LTIP performance based awards effectively becoming worthless. Consequently, management and the G&C Committee determined that we should change the basic structure of LTIP awards to better align the interests of our employee plan participants with the interests of our long-term unitholders by awards of deferred cash compensation (in lieu of phantom units) allocated between service vesting and performance vesting. During 2019, we awarded phantom units under our 2010 LTIP only to directors, all of which were service-based awards with no performance conditions. During 2019, we also granted cash-based awards to certain officers and other employees under our 2018 LTIP, including our NEOs. We establish grant values for NEOs based on an analysis of market practices of our compensation peer group and consideration of the level of salary and targeted bonus for each NEO. On April 17, 2019, the G&C Committee granted cash awards for both service and performance to each of our NEOs and certain employees under the 2018 LTIP. All awards granted to NEOs were allocated as 20% service-based and 80% performance-based awards. Contingent on continued employment on such date and satisfaction of the relevant performance standards, awards will vest between 20-420% of the cash grant value on April 17, 2022 and be paid in cash within 30 days thereafter. For performance awards, vesting is dependent on the satisfaction of relevant performance conditions and achievement of unit appreciation multiplier thresholds. Performance conditions include target levels of Available Cash before Reserves per unit, leverage ratios and safety metrics based upon such employee’s business unit, each measured for the quarter ending or as of December 31, 2021, as applicable. Our unit appreciation multiplier is based upon the closing price of our common units on April 16, 2022 as compared to $22.80, the closing price for our units on their grant date, April 17, 2019. 87 Table of Contents For 2019, the G&C Committee established the following long-term incentive cash grant values for each of our NEOs: Grant E. Sims Robert V. Deere Edward T. Flynn Richard R. Alexander Chad A. Landry Name $ 2019 Long-Term Incentive Cash Grant Value 2,200,000 800,000 1,200,000 400,000 450,000 Other Compensation and Benefits We offer certain other benefits to our NEOs, including medical, dental, disability and life insurance, and contributions on their behalf to our 401(k) plan. NEOs participate in these plans on the same basis as all other employees. Other than the 401(k) plan, we do not sponsor a pension plan in which our NEOs are eligible to participate, and we do not provide post-retirement medical benefits that would be available to our NEOs. No perquisites of any material nature are provided to our NEOs. Tax and Accounting Implications For our equity-based and cash-based compensation arrangements, we record compensation expense over the vesting period of the awards, as discussed further in Note 17 of our Consolidated Financial Statements in Item 8. Compensation Committee Report The G&C Committee has reviewed and discussed with management the Compensation Discussion and Analysis included above. Based on that review and discussion, the G&C Committee recommended to our board of directors that this Compensation Discussion and Analysis be included in this Form 10-K. The foregoing report is provided by the following directors, who constitute the G&C Committee: Kenneth M. Jastrow II, Chairman James E. Davison James E. Davison, Jr. Sharilyn S. Gasaway Conrad P. Albert Jack T. Taylor The information contained in this report shall not be deemed to be soliciting material or filed with the SEC or subject to the liabilities of Section 18 of the Exchange Act, except to the extent that we specifically incorporate it by reference into a document filed under the Securities Act or the Exchange Act. Compensation Risk Assessment Our board of directors does not believe that our compensation policies and practices for employees are reasonably likely to have a material adverse effect on us. We compensate all employees with a combination of competitive base salary and incentive compensation. Our board of directors believes that the mix and design of the elements of employee compensation do not encourage employees to assume excessive or inappropriate risk taking. Our board of directors concluded that the following risk oversight and compensation design features guard against excessive risk-taking: • • • the company has strong internal financial controls; base salaries are consistent with employees’ responsibilities so that they are not motivated to take excessive risks to achieve a reasonable level of financial security; the determination of incentive awards is based on a review of a variety of indicators of performance as well as a meaningful subjective assessment of personal performance, thus diversifying the risk associated with any single indicator of performance; 88 Table of Contents • • • incentive awards are capped by the G&C Committee; compensation decisions include discretionary authority to adjust annual awards and payments, which further reduces any business risk associated with our plans; and long-term incentive awards are designed to provide appropriate awards for dedication to a corporate strategy that delivers long-term returns to unitholders. Summary Compensation Table The following Summary Compensation Table summarizes the total compensation paid or accrued to our NEOs in 2019, 2018 and 2017. Name & Principal Position Grant E. Sims Year 2019 Chief Executive Officer 2018 (Principal Executive Officer) 2017 2019 Robert V. Deere Chief Financial Officer 2018 (Principal Financial Officer) 2017 2019 Edward T. Flynn (1) Executive Vice President Richard R. Alexander Vice President Chad A. Landry Vice President 2018 2017 2019 2018 2017 2019 2018 2017 Salary ($) Bonus ($) (2) Stock Awards ($) (3) All Other Compensation ($) (4) Total ($) $ 650,000 650,000 $ — $ — — $ — 87,176 193,201 $ 737,176 843,201 600,000 1,400,000 593,428 309,287 2,902,715 450,000 450,000 450,000 500,000 500,000 160,680 325,000 325,000 325,000 325,000 325,000 312,500 — — 450,000 980,000 200,958 63,004 250,000 260,000 640,000 230,000 178,750 443,750 — — 80,813 137,864 530,813 587,864 445,063 187,018 1,532,081 — — — — — 26,396 20,730 2,596 95,738 136,308 1,506,396 721,688 226,280 670,738 721,308 741,761 212,304 1,919,065 — — 311,560 $ 40,017 46,106 85,770 595,017 549,856 1,153,580 (1) Mr. Flynn became an employee of the partnership on September 1, 2017 upon the acquisition of the Alkali business. The salary and bonus presented for 2017 represents his salary and bonus earned as an employee of the partnership. Mr. Flynn's bonus for 2019 includes a discretionary bonus of $730,000 relating to 2018 but paid in March 2019, contingent upon Mr. Flynn's continued employment on the payment date. This discretionary bonus was reported as part of the 2018 bonus amount in our 2018 10-K disclosure. (2) The amounts shown represent any retention bonuses vested and paid during each of 2017, 2018, and 2019, as well as any cash or special bonus awards earned relative to each year. (3) The amounts shown in this column represent the aggregate grant date fair value for each NEO’s phantom units granted under our 2010 Long-Term Incentive Plan. The grant date fair value of each award was determined in accordance with accounting guidance for equity-based compensation and is based on the probable outcome of any underlying performance conditions. Assumptions used in the calculation of these amounts are included in Note 17 to our Consolidated Financial Statements in Item 8. (4) The following table presents the components of "All Other Compensation" for each NEO for the year ended December 31, 2019. 89 Table of Contents Name Grant E. Sims Robert V. Deere Edward T. Flynn Richard R. Alexander Chad A. Landry 401(k) Matching and Profit Sharing Contributions (a) Insurance Premiums (b) Other Compensation (c) $ 14,000 $ 1,458 $ 71,718 $ 30,800 25,692 30,800 28,000 1,458 704 1,458 1,458 48,555 — 63,480 10,559 Totals 87,176 80,813 26,396 95,738 40,017 The amounts in this table represent: (a) Contributions by us to our 401(k) plan on each NEO’s behalf. (b) Term life insurance premiums paid by us on each NEO’s behalf. (c) This column includes cash distributions paid in connection with granted DERs under the 2010 LTIP during 2019. Grants of Plan-Based Awards in Fiscal Year 2019 The following table shows the cash-based awards granted to our NEOs in 2019. Estimated Future Payouts Under 2018 LTIP (1) Name Grant Date Threshold Target Maximum Grant E. Sims Robert V. Deere Edward T. Flynn Richard R. Alexander Chad A. Landry 4/17/2019 4/10/2018 4/17/2019 4/10/2018 4/17/2019 4/10/2018 4/17/2019 4/10/2018 4/17/2019 4/10/2018 $ 1,320,000 1,080,000 $ 2,200,000 1,800,000 $ 3,960,000 3,240,000 480,000 360,000 720,000 540,000 240,000 360,000 270,000 240,000 800,000 600,000 1,200,000 900,000 400,000 600,000 450,000 400,000 1,440,000 1,080,000 2,160,000 1,620,000 720,000 1,080,000 810,000 720,000 (1) Represents the dollar amount of cash to be paid to each NEO under awards granted on April 17, 2019 and April 10, 2018, if the company meets certain performance conditions (threshold, target and maximum) during the fourth quarter of 2021 and 2020, respectively, assuming no forfeitures and considering a 1.0 UAM. See additional discussion in "Long-Term Incentive Compensation" above relating to the 2018 LTIP. Employment Agreements Richard R. Alexander Mr. Alexander entered into an employment agreement in July 2008 relating to his employment and providing for a base salary which is subject to discretionary upward adjustments. Currently, the annual base salary of Mr. Alexander is $325,000. That agreement provides that Mr. Alexander is eligible to participate in all other benefit programs (e.g. health, dental, disability, life and/or other insurance plans) for which executive officers are generally eligible and severance benefits as disclosed in "Potential Payments upon Termination or Change of Control" below. 90 Table of Contents Outstanding Equity Awards at December 31, 2019 The following table presents the information regarding the outstanding equity awards to our NEOs previously issued under the 2010 LTIP at December 31, 2019. Stock Awards (4) Equity Incentive Plan Awards: Number of Phantom Units that have not vested (#) (1) Equity Incentive Plan Awards: Market Value of Phantom Units That Have Not Vested ($) Equity Incentive Plan Awards: Number of Unearned Phantom Units That Have Not Vested (#) (1) Equity Incentive Plan Awards: Market Value of Unearned Phantom Units That Have Not Vested ($) (2) Name Grant Date Grant E. Sims Robert V. Deere Edward T. Flynn Richard R. Alexander Chad A. Landry (3) 4/11/2017 4/11/2017 4/11/2017 4/11/2017 4/11/2017 — $ — — — — — — — 3,848 76,537 18,327 $ 13,745 — 22,908 5,774 — — — — — (1) The number of performance units in the table reflects a target performance payout. Service based units held by Mr. Landry do not specify threshold, target and maximum payouts levels. For additional information regarding Mr. Landry's units, please see note 3 below. (2) Due to the distribution reset in 2017, the distribution rate per unit was reset during 2017 to a level well below the threshold trigger on the outstanding phantom units. Therefore, we have reflected a market value of these outstanding awards of $0 as of December 31, 2019. (3) Phantom units outstanding for Mr. Landry include 3,848 service based units for 2017. The remainder of the outstanding units held by Mr. Landry represented above are performance based units. (4) The phantom units granted on 4/11/2017 have a vest date of 4/11/2020. Phantom Units Vested The following table presents the information regarding the vesting of phantom units during the year ended December 31, 2019 with respect to our NEOs. Name Grant E. Sims Robert V. Deere Edward T. Flynn Richard R. Alexander Chad A. Landry Phantom Unit Awards Number of Phantom Units Vested (#) Value Realized on Vesting ($) $ 57,089 33,302 — 23,787 9,515 — — — — 88,147 The phantom unit awards granted to our NEOs in 2016 vested on April 12, 2019. Pursuant to our 2010 LTIP, the value realized upon vesting was computed by multiplying the average closing price of our common units for the 20 trading days immediately prior to the date of vesting by the number of units that vested for the service based awards. Those phantom unit awards were paid in cash. As noted previously, due to the distribution reset during 2017, our performance based awards that vested during 2019 had a fair value of $0 upon vesting. Termination or Change of Control Benefits We consider maintaining a stable and effective management team to be essential to protecting and enhancing the best interests of us and our unitholders. To that end, we recognize that the possibility of a change of control or other acquisition 91 Table of Contents event may raise uncertainty and questions among management, and such uncertainty could adversely affect our ability to retain our key employees, which would be to our unitholders’ detriment. Because our management team was built over time, as described above, and our NEOs became NEOs under different circumstances, the compensation and benefits awarded to our individual NEOs in the event of termination or a change of control varies. The employment agreement for Mr. Alexander provides certain compensation and benefits as an incentive to remain in our employ, enhancing our ability to call on and rely upon him in the event of a change of control. Mr. Alexander would not be entitled to severance benefits if terminated for cause. In extending these benefits, we considered a number of factors, including the prevalence of similar benefits adopted by other publicly traded MLPs. See “Potential Payments Upon Termination or Change of Control” below for further discussion of these benefits, including the definitions of certain terms such as change of control and cause. We believe that the interests of unitholders will best be served if the interests of our management and unitholders are aligned. We believe the termination and change of control benefits described above strike an appropriate balance between the potential compensation payable and the objectives described above. Potential Payments upon Termination or Change of Control Mr. Alexander is entitled under his employment agreement to specified severance benefits under certain circumstances as discussed above. Under a change of control and certain termination circumstances, each of our NEOs also will vest in any outstanding awards under our 2010 LTIP. Under the 2010 LTIP, a change of control occurs upon, in general, any sale of substantially all of the assets of us or our general partner or a merger, conversion, consolidation of us or our general partner or any other transaction resulting in a change in the beneficial ownership of more than 50% of the voting equity interests in our general partner. Under a change of control under the 2018 LTIP, the unvested service tranche of the cash award granted shall become fully vested and the unvested performance tranche of the cash award granted shall vest at 150% of the performance metric. If Mr. Alexander terminates his employment for good reason or we terminate his employment without cause, he would be entitled to (i) company payment of his COBRA health benefits for 12 months and (ii) monthly payments of his annual base salary due for the remainder of the renewal term of his employment agreement. As used in Mr. Alexander’s employment agreement, the terms “cause”, “change of control”, “good reason” and "renewal term" are generally described below: • • • • “Cause” means, in general, if the executive commits theft, embezzlement, forgery, any other act of dishonesty relating the executive’s employment or violates our policies or any law, rule, or regulation applicable to us, is convicted of a felony or lesser crime having as its predicate element fraud, dishonesty, or misappropriation, fails to perform his duties under the employment agreement or commits an act or intentionally fails to act, which act or failure to act amounts to gross negligence or willful misconduct. “Good Reason” means, in general, following a change of control which results in a substantial diminution of the executive’s duties, compensation, or benefits; executive’s removal from position as Vice President (other than for cause, death or disability, or being offered an equivalent position); or our failure to make any payment to the executive required under the terms of his employment agreement. “Change of control” means, in general, any sale of equity in us or our general partner or sale of substantially all of our assets; any merger, conversion or consolidation of us or our general partner; or any other event that, in each of the foregoing cases, results in any persons or entities having the ability to elect a majority of the members of our board of directors (other than one or more of our executive officers or affiliates). “Renewal term” means, in general, each one-year term of employment beginning on July 18 of each year, absent either the Company or the executive giving the other party at least 90 days advance written notice of its intent not to renew the employment agreement between them. Based upon a hypothetical termination date of December 31, 2019, the termination benefits for Messrs. Sims, Deere, Flynn, Alexander and Landry for voluntary termination or termination for cause would be zero. Based upon a hypothetical termination date of December 31, 2019, the termination benefits for Mr. Alexander for termination without cause (other than as a result of death or disability) or for good reason would have been: Severance pursuant to employment agreement Healthcare Total 92 Richard R. Alexander 325,000 $ 30,017 355,017 $ Table of Contents If termination occurs due to death or disability, Messrs. Sims, Deere, Flynn, Alexander and Landry would vest in outstanding awards under our 2010 and 2018 LTIP plans. Utilizing the closing price of our common units for the twenty trading days prior to December 31, 2019 would result in payments under the 2010 and 2018 LTIP plans of the following amounts upon death or disability: Grant E. Sims Robert V. Deere Edward T. Flynn Richard A. Alexander Chad A. Landry $ 4,000,000 1,400,000 2,100,000 1,000,000 926,537 Based on a hypothetical simultaneous change of control and termination date of December 31, 2019, the change of control termination benefits for Messrs. Sims, Deere, Flynn, Alexander and Landry would have been as follows: Severance pursuant to employment agreement $ Healthcare Cash payment for vested awards under 2018 LTIP granted in 2019 Cash payment for vested awards under 2018 LTIP granted in 2018 Cash payment for vested awards under 2010 LTIP Total Director Compensation in Fiscal Year 2019 Grant E. Sims Robert V. Deere Edward T. Flynn Richard R. Alexander Chad A. Landry — $ — — $ — — $ 325,000 30,017 — $ — — 3,080,000 1,120,000 1,680,000 560,000 630,000 2,520,000 840,000 1,260,000 840,000 540,000 — $5,600,000 — $1,960,000 — $2,940,000 — $1,755,017 76,537 $1,246,537 The table below reflects compensation for our non-employee directors. Mr. Sims does not receive any compensation attributable to his status as a director. Name James E. Davison James E. Davison, Jr. Sharilyn S. Gasaway Kenneth M. Jastrow II Conrad P. Albert Jack T. Taylor Fees Earned or Paid in Cash ($) (1) Stock Awards ($) (2) (3) All Other Compensation ($) (4) $ $ 82,000 82,000 104,500 94,500 92,500 94,500 $ 100,000 100,000 112,500 112,500 102,500 102,500 $ 25,797 25,797 29,020 29,020 26,442 26,442 Total 207,797 207,797 246,020 236,020 221,442 223,442 (1) Amounts include annual retainer fees and fees for attending meetings. (2) Amounts in this column represent the fair value of the awards of phantom units under our 2010 LTIP on the date of grant, as calculated in accordance with accounting guidance for equity-based compensation. (3) Outstanding awards to directors at December 31, 2019 consist of phantom units granted under our 2010 LTIP. Messrs. James Davison and James Davison, Jr. each hold 12,401 outstanding phantom units, Messrs. Jastrow, Albert, Taylor and Ms. Gasaway hold 13,950, 12,711, 12,711 and 13,950 outstanding phantom units, respectively. (4) Amounts in this column represent the amounts paid for tandem DERs related to outstanding phantom units granted under our 2010 LTIP. Directors who are not officers of our general partner are entitled to a base compensation of $180,000 per year, with $80,000 paid in cash and $100,000 paid in phantom units. Cash is paid, and phantom units are awarded, on the first day of each calendar quarter. The number of phantom units awarded is determined by dividing the closing market price of our units on the date of the award into the amount to be paid in phantom units. So long as he or she is a director on the relevant date of determination, each director will receive: (i) a quarterly distribution equal to the number of phantom units held by such director multiplied by the quarterly distribution amount we will pay in respect of each of our outstanding common units on 93 Table of Contents such distribution date, and (ii) on the third anniversary of each award date for such director, an amount equal to the number of phantom units granted to such director on such award date multiplied by the average closing price of our common units for the 20 trading days ending on the day immediately preceding such anniversary date. The lead director and chairpersons of the audit committee and G&C Committee receive an additional amount of base compensation split equally between cash and phantom units, which cash compensation is paid in equal quarterly installments. Such additional amount is $10,000 for the lead director, $25,000 for the chair of the audit committee and $15,000 for the chair of the G&C Committee. In addition, each non-employee director receives additional cash compensation for each “Additional Meeting” (board and/or committee) in which he or she participates. Participation by a director in-person will entitle her/him to additional compensation of $2,500 per meeting, and participation by a director by means of telecommunication will entitle her/him to additional compensation of $2,000 per meeting. Such payments are made in conjunction with the quarterly payments of base compensation. Additional Meetings consist of (i) with respect to our board of directors any meetings (in-person or by telecommunication) other than (x) the four pre-set meetings of our board of directors for each calendar year and (y) brief follow-up telecommunication conferences relating to the Annual Report on Form 10-K or any Quarterly Report on Form 10-Q the company files with the SEC, and (ii) any committee meeting. CEO Pay Ratio Our CEO to median employee pay ratio is calculated in accordance with the SEC’s pay ratio rules, Item 402(u) of Regulation S-K, which requires the disclosure of (i) the median of the annual total compensation of all employees of the company (except the CEO), (ii) the annual total compensation for the CEO, and (iii) the ratio of these two amounts. We identified the median employee initially as of December 31, 2017 as a part of our 2017 10-K disclosure, and have noted no significant changes to our employee population or employee compensation arrangements for the period ended December 31, 2019 that would result in a significant change in the pay ratio disclosure. As such, we have elected to utilize the same median employee and utilize their 2019 total cash compensation for the year ended December 31, 2019. As of December 31, 2019, the company had 2,184 employees, including 2,170 full-time employees, and 14 part-time and seasonal employees. Consistent with Item 402(u), we initially excluded from our employees those individuals who provide services as independent contractors, based on application of the tests used for tax purposes as set forth in the Internal Revenue Service’s “Publication 15A: Employer’s Supplemental Tax Guide. We did not make any assumptions, adjustments, or estimates with respect to total cash compensation. We believe the use of total cash compensation for all employees is a consistently applied compensation measure because we do not widely distribute annual equity awards to employees. Since all of our employees are located in the United States, including the Commonwealth of Puerto Rico, and paid in U.S. dollars, we did not make any cost- of-living adjustments in identifying the median employee. After identifying the median employee based on total cash compensation, we calculated the annual total compensation for that employee using the same methodology we use for our named executive officers as set forth in the 2019 Summary Compensation Table above in this 10-K filing. Mr. Sims, our CEO, had 2019 annual total compensation of $737,176, as reflected in the Summary Compensation Table. Our median employee’s annual total compensation for 2019 was $122,479. Based on this information, Mr. Sims’ total annual compensation was approximately six times that of our median employee in 2019, or 6:1. 94 Table of Contents Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters Beneficial Ownership of Partnership Units Beneficial Ownership of Common Units The following table sets forth certain information as of February 26, 2020, regarding the beneficial ownership of our common units by beneficial owners of 5% or more by class of unit and by directors and the executive officers of our general partner and by all directors and executive officers as a group. This information is based on data furnished by the person named. Name and Address of Beneficial Owner Class A Common Units Class B Common Units Amount and Nature of Beneficial Ownership (1) Percent of Class Amount and Nature of Beneficial Ownership Percent of Class Conrad P. Albert James E. Davison James E. Davison, Jr. Sharilyn S. Gasaway Kenneth M. Jastrow II Jack T. Taylor Grant E. Sims Robert V. Deere Edward T. Flynn Richard R. Alexander Karen N. Pape Kristen O. Jesulaitis Ryan S. Sims William S. Goloway Garland G. Gaspard Chad A. Landry 5,000 3,476,282 (2) 5,323,932 (3) 279,445 150,000 12,865 * 2.8% 4.3% * * * 3,000,000 (4) 2.4% 829,987 (5) 59,500 15,500 (6) 152,131 5,000 16,300 2,400 1,247 30,000 * * * * * * * * * — — 9,453 13,648 1,081 — — 7,087 1,052 — — — — — — — — 23.6% 34.1% 2.7% — — 17.7% 2.6% — — — — — — — — All directors and executive officers as a group (16 in total) 13,359,589 10.9% 32,321 80.8% Steven K. Davison Chickasaw Capital Management, LLC Invesco LTD ALPS Advisors, Inc. Clearbridge Investments, LLC * Less than 1% 2,040,339 (7) 8,860,054 17,530,812 13,084,546 9,653,010 1.5% 7.2% 14.3% 10.7% 7.9% 7,676 19.2% — — — — (1) The Class B Common Units, which also are included in the Class A Common Unit total, are identical in most respects to the Class A Common Units and have voting and distribution rights equivalent to those of the Class A Common Units. In addition, the Class B Common Units have the right to elect all of our board of directors and are convertible into Class A Common Units under certain circumstances, subject to certain exceptions. (2) Mr. Davison pledged 1,049,406 of these Class A Common Units as collateral for a loan from a bank. In addition to his direct ownership interests, Mr. Davison is the sole stockholder of Terminal Services, Inc., which owns 1,010,835 Class A Common Units. (3) Mr. Davison, Jr. pledged 1,164,370 of these Class A Common Units as collateral for a loan from a bank. 1,339,383 of these Class A Common Units are held by trusts for Mr. Davison's children. 187,856 of these Class A Common Units are held by the James E. and Margaret A. B. Davison Special Trust. (4) Mr. Sims pledged 1,450,000 of these Class A Common Units as collateral for loans from a bank. (5) Mr. Deere pledged 249,935 of these Class A Common Units as collateral for a loan from a bank. (6) Mr. Alexander pledged 10,000 Class A Common Units as collateral for margin brokerage accounts. (7) Includes 147,941 Class A Common units held by the Steven Davison Family Trust. Except as noted, each unitholder in the above table is believed to have sole voting and investment power with respect to the units beneficially held, subject to applicable community property laws. 95 Table of Contents Beneficial Ownership of Preferred Units The following table sets forth certain information as of December 18, 2019, regarding the beneficial ownership of our preferred units. This information is based on data furnished by the persons named. Name and Address of Beneficial Owner Preferred Units GSO Rodeo Holdings LP (2) (3) Rodeo Finance Aggregator LLC (4) Amount and Nature of Beneficial Ownership Percent of Class (1) 12,668,389 12,668,389 50.0% 50.0% (1) The percentage of beneficial ownership is calculated based on 25,336,778 preferred units deemed outstanding as of December 18, 2019. (2) Reflects preferred units directly owned by GSO Rodeo Holdings LP. GSO Rodeo Holdings Associates LLC is the general partner of GSO Rodeo Holdings LP. GSO Holdings I L.L.C. is the managing member of GSO Rodeo Holdings Associates LLC. Blackstone Holdings II L.P. is the managing member of GSO Holdings I L.L.C. Blackstone Holdings I/II GP Inc. is the general partner of Blackstone Holdings II L.P. The Blackstone Group Inc. is the sole member of Blackstone Holdings I/II GP, L.L.C. Blackstone Group Management L.L.C. is the sole holder of Class C common stock of The Blackstone Group Inc. Blackstone Group Management L.L.C. is wholly-owned by Blackstone’s senior managing directors and controlled by its founder, Stephen A. Schwarzman. In addition, Bennett J. Goodman may be deemed to have shared voting power and/or investment power with respect to the securities held by GSO Rodeo Holdings LP. Each of the foregoing (other than GSO Rodeo Holdings LP) disclaims beneficial ownership of the preferred units beneficially owned by GSO Rodeo Holdings LP. The business address for GSO Rodeo Holdings LP is c/o GSO Capital Partners LP, 345 Park Avenue, New York, New York 10154. (3) On September 23, 2019, Genesis, through an unrestricted subsidiary, entered into an amended and restated limited liability company agreement and a securities purchase agreement pursuant to which certain funds affiliated with GSO purchased $55,000,000, and committed to purchase, during a three-year commitment period, up to an additional $295,000,000, of preferred interests in Alkali Holdings. Each additional purchase of preferred interests is subject to the satisfaction of customary closing conditions. AlkaliHoldings will use the net proceeds from the sales of preferred interests to fund the expansion of the Granger facility. (4) Reflects preferred units directly owned by Rodeo Finance Aggregator LLC. KKR Rodeo Aggregator L.P., as the sole member of Rodeo Finance Aggregator LLC, KKR Rodeo Aggregator GP LLC, as the general partner of KKR Rodeo Aggregator L.P., KKR Global Infrastructure Investors II (Rodeo) L.P., as the sole member of KKR Rodeo Aggregator GP LLC, KKR Associates Infrastructure II AIV L.P., as the general partner of KKR Global Infrastructure Investors II (Rodeo) L.P., KKR Infrastructure II AIV GP LLC, as the general partner of KKR Associates Infrastructure II AIV L.P., KKR Financial Holdings LLC, as the Class B member of KKR Infrastructure II AIV GP LLC, KKR Fund Holdings L.P., as the Class A member of KKR Infrastructure II AIV GP LLC and the sole member of KKR Financial Holdings LLC, KKR Fund Holdings GP Limited, as a general partner of KKR Fund Holdings L.P., KKR Group Holdings Corp., as the sole shareholder of KKR Fund Holdings GP Limited and a general partner of KKR Fund Holdings L.P., KKR & Co. Inc., as the sole shareholder of KKR Group Holdings Corp., KKR Management LLC, as the Class B common stockholder of KKR & Co. Inc., and Messrs. Kravis and Roberts, as the designated members of KKR Management LLC, may be deemed to be the beneficial owners having shared voting and investment power with respect to the preferred units described in this footnote. The principal business address of each of the entities and persons identified in this paragraph, except Mr. Roberts, is c/o Kohlberg Kravis Roberts & Co. L.P., 9 West 57th Street, Suite 4200, New York, NY 10019. The principal business address for Mr. Roberts is c/o Kohlberg Kravis Roberts & Co. L.P., 2800 Sand Hill Road, Suite 200, Menlo Park, CA 94025. Beneficial Ownership of General Partner Interest Genesis Energy, LLC owns a non-economic general partner interest in us. Genesis Energy, LLC is our wholly-owned subsidiary. The mailing address for Genesis Energy, LLC and all officers and directors is 919 Milam, Suite 2100, Houston, Texas, 77002. Item 13. Certain Relationships and Related Transactions, and Director Independence Transactions with Related Persons Our CEO, Mr. Sims owns an aircraft, which is used by us for business purposes in the course of operations. We pay Mr. Sims a fixed monthly fee and reimburse the aircraft management company for costs related to our usage of the aircraft, including fuel and the actual out-of-pocket costs. In connection with this arrangement, we made payments to Mr. Sims totaling $0.7 million, during 2019. Based on current market rates for chartering of private aircraft under long-term, priority arrangements with industry recognized chartering companies, we believe that the terms of this arrangement are no worse than what we could have expected to obtain in an arms-length transaction. 96 Table of Contents Family members of certain of our executive officers and directors may work for us from time to time. In 2019, Mr. Sims (our CEO and a director) had two sons that worked for us- one as senior vice president of finance and corporate development and the other as vice president and general manager of refined products. Mr. James Davison, Sr. (a director) had one son (who is also a brother of James E. Davison, Jr., a director), that worked as a director in our onshore facilities and transportation department in 2019. In the aggregate, these family members received total W-2 compensation of less than $1,100,000. Director Independence Because we are a limited partnership, the listing standards of the NYSE do not require that we have a majority of independent directors (although at least a majority of the members of our board of directors is independent,as defined by the NYSE rules) or that we have either a nominating committee or a compensation committee of our board of directors. We are, however, required to have an audit committee consisting of at least three members, all of whom are required to be “independent” as defined by the NYSE. Under NYSE rules, to be considered independent, our board of directors must determine that a director has no material relationship with us other than as a director. The rules specify the criteria by which the independence of directors will be determined, including guidelines for directors and their immediate family members with respect to employment or affiliation with us or with our independent public accountants. Our board of directors has determined that each of Ms. Gasaway and Messrs. Jastrow, Albert and Taylor is an independent director under the NYSE rules. See Item 10. “Directors, Executive Officers and Corporate Governance” for additional discussion relating to our directors and director independence. Item 14. Principal Accounting Fees and Services The following table summarizes the fees for professional services rendered by Ernst & Young for the years ended December 31, 2019 and 2018. Audit Fees (1) All Other Fees (2) Total 2019 2018 (in thousands) $ $ 2,141 8 2,149 $ $ 2,977 8 2,985 (1) (2) Includes fees for the annual audit and quarterly reviews (including internal control evaluation and reporting), SEC registration statements and accounting and financial reporting consultations and research work regarding Generally Accepted Accounting Principles. Includes fees associated with licenses for accounting research software. Pre-Approval Policy The services by Ernst & Young in 2019 and 2018 were pre-approved in accordance with the pre-approval policy and procedures adopted by the audit committee. This policy describes the permitted audit, audit-related, tax and other services, which we refer to collectively as the Disclosure Categories that the independent auditor may perform. The policy requires that each fiscal year, a description of the services, or the Service List expected to be performed by the independent auditor in each of the Disclosure Categories in the following fiscal year be presented to the audit committee for approval. Any requests for audit, audit-related, tax and other services not contemplated on the Service List must be submitted to the audit committee for specific pre-approval and cannot commence until such approval has been granted. Normally, pre- approval is provided at regularly scheduled meetings. In considering the nature of the non-audit services provided by Ernst & Young in 2019 and 2018, the audit committee determined that such services are compatible with the provision of independent audit services. The audit committee discussed these services with Ernst & Young and management of our general partner to determine that they are permitted under the rules and regulations concerning auditor independence promulgated by the SEC to implement the Sarbanes-Oxley Act of 2002, as well as the American Institute of Certified Public Accountants. 97 Table of Contents Item 15. Exhibits and Financial Statement Schedules (a)(1) Financial Statements See “Index to Consolidated Financial Statements and Financial Statement Schedules”. (a)(2) Financial Statement Schedules. See “Index to Consolidated Financial Statements and Financial Statement Schedules”. (a)(3) Exhibits 2.1 3.1 3.2 3.3 3.4 3.5 3.6 3.7 3.8 3.9 3.10 Stock Purchase Agreement, dated August 2, 2017, by and among Genesis Energy, L.P., Tronox US Holdings, Inc., Tronox Alkali Corporation and, for the purposes set forth therein, Tronox Limited (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on August 7, 2017, File No. 001-12295). Certificate of Limited Partnership of Genesis Energy, L.P. (incorporated by reference to Exhibit 3.1 to Amendment No. 2 of the Registration Statement on Form S-1 filed on November 15, 1996, File No. 333-11545). Amendment to the Certificate of Limited Partnership of Genesis Energy, L.P. (incorporated by reference to Exhibit 3.2 to the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011, File No. 001-12295). Fifth Amended and Restated Agreement of Limited Partnership of Genesis Energy, L.P. (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on January 3, 2011, File No. 001-12295). First Amendment to Fifth Amended and Restated Agreement of Limited Partnership of Genesis Energy, L.P., dated September 1, 2017 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on September 7, 2017, File No. 001-12295). Second Amendment to Fifth Amended and Restated Agreement of Limited Partnership of Genesis Energy, L.P., dated December 31, 2017 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on January 4, 2018, File No. 001-12295). Certificate of Conversion of Genesis Energy, Inc., a Delaware corporation, into Genesis Energy, LLC, a Delaware limited liability company (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K filed on January 7, 2009, File No. 001-12295). Certificate of Formation of Genesis Energy, LLC (formerly Genesis Energy, Inc.) (incorporated by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K filed on January 7, 2009, File No. 001-12295). Second Amended and Restated Limited Liability Company Agreement of Genesis Energy, LLC dated December 28, 2010 (incorporated by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K filed on January 3, 2011, File No. 001-12295). Certificate of Incorporation of Genesis Energy Finance Corporation, dated as of November 26, 2006 (incorporated by reference to Exhibit 3.7 to the Company's Registration Statement on Form S-4 filed on September 26, 2011, File No. 333-177012). Bylaws of Genesis Energy Finance Corporation (incorporated by reference to Exhibit 3.8 to the Company's Registration Statement on Form S-4 filed on September 26, 2011, File No. 333-177012). * 4.1 Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934. 4.2 4.3 4.4 4.5 4.6 Form of Unit Certificate of Genesis Energy, L.P. (incorporated by reference to Exhibit 4.1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-12295). Form of Common Unit Certificate of Genesis Energy, L.P. (incorporated by reference to Exhibit 4.1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-12295) Davison Unitholder Rights Agreement dated July 25, 2007 (incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K filed on July 31, 2007, File No. 001-12295). Amendment No. 1 to the Davison Unitholder Rights Agreement dated October 15, 2007 (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed on October 19, 2007, File No. 001-12295). Amendment No. 2 to the Davison Unitholder Rights Agreement dated December 28, 2010 (incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K filed on January 3, 2011, File No. 001-12295). 98 Table of Contents 4.7 4.8 4.9 4.10 4.11 4.12 4.13 4.14 4.15 4.16 4.17 4.18 4.19 4.20 4.21 4.22 4.23 Davison Registration Rights Agreement dated July 25, 2007 (incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K filed on July 31, 2007, File No. 001-12295). Amendment No. 1 to the Davison Registration Rights Agreement, dated November 16, 2007 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed on November 16, 2007, File No. 001-12295). Amendment No. 2 to the Davison Registration Rights Agreement, dated December 6, 2007 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed on December 11, 2007, File No. 001-12295). Amendment No. 3 to the Davison Registration Rights Agreement, dated as of December 28, 2010 (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed on January 3, 2011, File No. 001-12295). Registration Rights Agreement, dated as of December 28, 2010, by and among Genesis Energy, L.P. and the former unitholders of Genesis Energy, LLC (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed on January 3, 2011, File No. 001-12295). Registration Rights Agreement, dated September 1, 2017, by and among Genesis Energy, L.P., GSO Rodeo Holdings LP and Rodeo Finance Aggregator LLC (incorporated by reference from Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on September 7, 2017, File No. 001-12295). Indenture, dated May 15, 2014, among Genesis Energy, L.P., Genesis Energy Finance Corporation, certain subsidiary guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on May 15, 2014, File No. 001-12295). Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of May 15, 2014, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K filed on May 15, 2014, File No. 001-12295). Second Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of October 15, 2014, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.35 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, File No. 001-12295). Third Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of December 17, 2014, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.36 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, File No. 001-12295). Fourth Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of January 22, 2015, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.37 to Company’s Annual Report on Form 10-K for the year ended December 31, 2014, File No. 001-12295). Fifth Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of February 19, 2015, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.38 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, File No. 001-12295). Sixth Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of February 19, 2015, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.39 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, File No. 001-12295). Seventh Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of June 26, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.6 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, File No. 001-12295). Eighth Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of July 15, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.7 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, File No. 001-12295). Ninth Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of September 22, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, File No. 001-12295). Tenth Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of December 11, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.52 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2015, File No. 001-12295). 99 Table of Contents 4.24 4.25 4.26 4.27 4.28 4.29 4.30 4.31 4.32 4.33 4.34 4.35 4.36 4.37 Eleventh Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of March 10, 2016, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, File No. 001-12295). Twelfth Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of June 29, 2017, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.57 to the Company's Annual Report on Form 10-K for the year ended December 31, 2017, File No. 001-12295). Thirteenth Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of November 13, 2017, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.57 to the Company's Annual Report on Form 10-K for the year ended December 31, 2017, File No. 001-12295). Fourteenth Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of August 28, 2018, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 of the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2018, File No. 001-12295). Fifteenth Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of March 22, 2019, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 of the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2019, File No. 001-12295). Indenture, dated May 21, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on May 21, 2015, File No. 001-12295). Supplemental Indenture for the Issuers' 6.000% Senior Notes due 2023, dated May 21, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (including the form of the Notes) (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K filed on May 21, 2015, File No. 001-12295). Second Supplemental Indenture for 6.000% Senior Notes due 2023, dated as of June 26, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, File No. 001-12295). Third Supplemental Indenture for 6.000% Senior Notes due 2023, dated as of July 15, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, File No. 001-12295). Fourth Supplemental Indenture for 6.75% Senior Notes due 2022, dated as of July 23, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K filed on July 28, 2015, File No. 001-12295). Fifth Supplemental Indenture for 6.000% Senior Notes due 2023 and 6.75% Senior Notes due 2022, dated as of September 22, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, File No. 001-12295). Sixth Supplemental Indenture for 6.000% Senior Notes due 2023 and 6.75% Senior Notes due 2022, dated as of December 11, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.59 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2015, File No. 001-12295). Seventh Supplemental Indenture for 6.000% Senior Notes due 2023 and 6.75% Senior Notes due 2022, dated as of March 10, 2016, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, File No. 001-12295). Eighth Supplemental Indenture for 6.000% Senior Notes due 2023 and 6.75% Senior Notes due 2022, dated as of June 29, 2017, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.67 to the Company's Annual Report on Form 10-K for the year ended December 31, 2017, File No. 001-12295). 100 Table of Contents 4.38 4.39 4.40 4.41 4.42 4.43 10.1 10.2 10.3 10.4 10.5 Ninth Supplemental Indenture for 6.50% Senior Notes due 2025, dated as of August 14, 2017, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference from Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on August 14, 2017, File No. 001-12295). Tenth Supplemental Indenture for 6.000% Senior Notes due 2023, 6.75% Senior Notes due 2022 and 6.50% Senior Notes due 2025, dated as of November 13, 2017, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.69 to the Company's Annual Report on Form 10-K for the year ended December 31, 2017, File No. 001-12295). Eleventh Supplemental Indenture for 6.250% Senior Notes Due 2026, dated as of December 11, 2017, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed on December 11, 2017, File No. 001-12295). Twelfth Supplemental Indenture for 6.000% Senior Notes due 2023, 6.75% Senior Notes due 2022, 6.50% Senior Notes due 2025, and 6.250% Senior Notes due 2026, dated as of August 28, 2018, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 of the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2018, File No. 001-12295). Thirteenth Supplemental Indenture for 6.000% Senior Notes due 2023, 6.75% Senior Notes due 2022, 6.50% Senior Notes due 2025, and 6.250% Senior Notes due 2026, dated as of March 22, 2019, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 of the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2019, File No. 001-12295). Fourteenth Supplemental Indenture for 7.750% Senior Notes due 2028, dated as of January 16, 2020, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed on January 16, 2020, File No. 001-12295). Fourth Amended and Restated Credit Agreement, dated as of June 30, 2014, among Genesis Energy, L.P. as borrower, Wells Fargo Bank, National Association, as administrative agent, Bank of America, N.A. and Bank of Montreal as co-syndication agents, U.S. Bank National Association as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed on July 3, 2014, File No. 001-12295). First Amendment to Fourth Amended and Restated Credit Agreement, dated August 25, 2014, among Genesis Energy, L.P. as borrower, Wells Fargo Bank, National Association, as administrative agent, Bank of America, N.A. and Bank of Montreal as co-syndication agents, U.S. Bank National Association as documentation agent and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed on August 29, 2014, File No. 001-12295). Second Amendment to Fourth Amended and Restated Credit Agreement and Joinder Agreement, dated as of July 17, 2015, among Genesis Energy, L.P. as borrower, Wells Fargo Bank, National Association, as administrative agent and issuing bank, Bank of America, N.A. and Bank of Montreal as co- syndication agents, U.S. Bank National Association as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.3 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2015, File No. 001-12295). Third Amendment to Fourth Amended and Restated Credit Agreement, dated as of September 17, 2015, among Genesis Energy, L.P. as borrower, Wells Fargo Bank, National Association, as administrative agent and issuing bank, Bank of America, N.A. and Bank of Montreal as co-syndication agents, U.S. Bank National Association as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed on September 23, 2015, File No. 001-12295). Fourth Amendment to Fourth Amended and Restated Credit Agreement and Joinder Agreement dated as of April 27, 2016 among Genesis Energy, L.P., as the borrower, Wells Fargo Bank, National Association, as administrative agent and issuing bank, Bank of America, N.A. and Bank of Montreal, as co-syndication agents, U.S. Bank National Association, as documentation agent, and the lenders party thereto. (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed on May 3, 2016, File No. 001-12295). 101 Table of Contents 10.6 10.7 10.8 10.9 10.10 10.11 10.12 Fifth Amendment to Fourth Amended and Restated Credit Agreement and Second Amendment to Fourth Amended and Restated Guarantee and Collateral Agreement dated as of May 9, 2017 among Genesis Energy, L.P., as the borrower, Wells Fargo Bank, National Association, as administrative agent and issuing bank, Bank of America, N.A. and Bank of Montreal, as co-syndication agents, U.S. Bank National Association, as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 15, 2017, File No. 001-12295). Sixth Amendment to Fourth Amended and Restated Credit Agreement, dated July 28, 2017, among Genesis Energy, L.P., as borrower, Wells Fargo Bank National Association, as administrative agent, Bank of America, N.A. and Bank of Montreal as co-syndication agents, U.S. Bank National Association as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on August 7, 2017, File No. 001-12295). Seventh Amendment to Fourth Amended and Restated Credit Agreement, dated as of August 28, 2018, among Genesis Energy, L.P., as the borrower, Wells Fargo Bank, National Association, as administrative agent and issuing bank, Bank of America, N.A. and Bank of Montreal, as co-syndication agents, U.S. Bank National Association, as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 31, 2018, File No. 333-177012). Eighth Amendment to Fourth Amended and Restated Credit Agreement, dated as of October 11, 2018, among Genesis Energy, L.P., as the borrower, Wells Fargo Bank, National Association, as administrative agent and issuing bank, Bank of America, N.A. and Bank of Montreal, as co-syndication agents, U.S. Bank National Association, as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 11, 2018, File No. 001-12295). Ninth Amendment to Fourth Amended and Restated Credit Agreement, dated as of September 23, 2019, among Genesis Energy, L.P., as the borrower, Wells Fargo Bank, National Association, as administrative agent and issuing bank, Bank of America, N.A. and Bank of Montreal, as co-syndication agents, U.S. Bank National Association, as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 23, 2019, File No. 001-12295). Form of Indemnity Agreement, among Genesis Energy, L.P., Genesis Energy, LLC and each of the Directors of Genesis Energy, LLC (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 5, 2010, File No. 001-12295). Equity Distribution Agreement, dated June 27, 2016, among Genesis Energy, L.P., RBC Capital Markets, LLC, BNP Paribas Securities Corp., Capital One Securities, Inc., Deutsche Bank Securities Inc., DNB Markets, Inc., Fifth Third Securities, Inc., Scotia Capital (USA) Inc. and SMBC Nikko Securities America, Inc. (incorporated by reference to Exhibit 1.1 to the Company's Current Report on Form 8-K filed on June 27, 2016, File No. 001-12295). 10.13 + Genesis Energy, L.P. 2010 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 001-12295). 10.14 + Genesis Energy, LLC 2010 Long-Term Incentive Plan Form of Directors Phantom Unit with DERs Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10- Q for the quarter ended March 31, 2013, File No. 001-12295). 10.15 + Genesis Energy, LLC 2010 Long-Term Incentive Plan Form of Executive Phantom Unit with DERs Award – Officers (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, File No. 001-12295). 10.16 + Genesis Energy, LLC 2010 Long-Term Incentive Plan Form of Employee Phantom Unit with DERs Agreement (incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10- Q for the quarter ended March 31, 2010, File No. 001-12295). 10.17 + Genesis Energy 2018 Long-Term Incentive Plan (incorporated by reference from Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2018, File No. 001-12295). 10.18 + Form of Award for 2018 LTIP (General) (incorporated by reference from Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2018, File No. 001-12295) 10.19 + Form of Award for 2018 LTIP (Alkali) (incorporated by reference from Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2018, File No. 001-12295) 10.20 + Form of Award for 2018 LTIP (Marine) (incorporated by reference from Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2018, File No. 001-12295) 102 Table of Contents 10.21 10.22 21.1 23.1 23.2 31.1 31.2 32.1 32.2 99.1 95 Employment Agreement by and between DG Marine Transportation, LLC and Richard Alexander dated July 18, 2008 (incorporated by reference to Exhibit 10.22 to the Company's Annual Report on Form 10- K for the year ended December 31, 2014, File No. 001-12295). Board Observer Agreement, dated September 1, 2017, by and among Genesis Energy, L.P., GSO Rodeo Holdings LP and Rodeo Finance Aggregator LLC (incorporated by reference from Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 7, 2017, File No. 001-12295). Subsidiaries of the Registrant. Consent of Ernst & Young LLP. Consent of Ernst & Young LLP. Certification by Chief Executive Officer Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934. Certification by Chief Financial Officer Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934. Certification by Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Certification by Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Financial Statements of Poseidon Oil Pipeline Company, LLC for the three years ended December 31, 2019 (audited) pursuant to Rule 3-09 of Regulation S-X (17 CFR 210.3-09) Mine Safety Disclosure Exhibit 101.INS XBRL Instance Document- the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. 101.SCH XBRL Schema Document. 101.CAL XBRL Calculation Linkbase Document. 101.LAB XBRL Label Linkbase Document. 101.PRE XBRL Presentation Linkbase Document. 101.DEF XBRL Definition Linkbase Document. 104 Cover Page Interactive Data File (formatted as Inline XBRL) Filed herewith A management contract or compensation plan or arrangement. * * * * * * * * * * * * * * * * * + Item 16. Form 10-K Summary Not Applicable 103 Table of Contents SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. Date: February 27, 2020 GENESIS ENERGY, L.P. (A Delaware Limited Partnership) By: GENESIS ENERGY, LLC, as General Partner By: /s/ GRANT E. SIMS Grant E. Sims Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated. NAME TITLE DATE /s/ GRANT E. SIMS Grant E. Sims /s/ ROBERT V. DEERE Robert V. Deere /s/ KAREN N. PAPE Karen N. Pape /s/ CONRAD P. ALBERT Conrad P. Albert /s/ JAMES E. DAVISON James E. Davison /s/ JAMES E. DAVISON, JR. James E. Davison, Jr. /s/ SHARILYN S. GASAWAY Sharilyn S. Gasaway /s/ KENNETH M. JASTROW, II Kenneth M. Jastrow, II /s/ JACK T. TAYLOR Jack T. Taylor * Genesis Energy, LLC is our general partner. (OF GENESIS ENERGY, LLC)* Chairman of the Board, Director and Chief Executive Officer (Principal Executive Officer) Chief Financial Officer, (Principal Financial Officer) Senior Vice President and Controller (Principal Accounting Officer) Director Director Director Director Director Director February 27, 2020 February 27, 2020 February 27, 2020 February 27, 2020 February 27, 2020 February 27, 2020 February 27, 2020 February 27, 2020 February 27, 2020 104 Table of Contents Item 8. Financial Statements and Supplementary Data GENESIS ENERGY, L.P. INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES Page Financial Statements of Genesis Energy, L.P. Report of Independent Registered Public Accounting Firm Report of Independent Registered Public Accounting Firm on Internal Controls Over Financial Reporting Consolidated Balance Sheets Consolidated Statements of Operations Consolidated Statements of Comprehensive Income Consolidated Statements of Partners’ Capital Consolidated Statements of Cash Flows Notes to Consolidated Financial Statements 1. Organization 2. Summary of Significant Accounting Policies 3. Revenue Recognition 4. Lease Accounting 5. Acquisitions 6. Receivables 7. Inventories 8. Fixed Assets, Mineral Leaseholds and Asset Retirement Obligations 9. Equity Investees 10. Intangible Assets, Goodwill and Other Assets 11. Debt 12. Partners' Capital, Mezzanine Equity and Distributions 13. Net Income Per Common Unit 14. Business Segment Information 15. Transactions with Related Parties 16. Supplemental Cash Flow Information 17. Equity-Based Compensation Plans 18. Major Customers and Credit Risk 19. Derivatives 20. Fair-Value Measurements 21. Employee Benefit Plans 22. Commitments and Contingencies 23. Income Taxes 24. Quarterly Financial Data (Unaudited) 25. Condensed Consolidating Financial Information 26. Subsequent Events 105 F-1 F-3 F-4 F-5 F-6 F-7 F-8 F-9 F-9 F-9 F-14 F-17 F-20 F-21 F-22 F-23 F-24 F-25 F-27 F-29 F-35 F-35 F-38 F-39 F-39 F-41 F-41 F-45 F-47 F-49 F-49 F-51 F-52 F-61 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors of Genesis Energy, LLC and Unitholders of Genesis Energy, L.P. Opinion on the Financial Statements We have audited the accompanying consolidated balance sheets of Genesis Energy, L.P. (the Partnership) as of December 31, 2019 and 2018, the related consolidated statements of operations, comprehensive income (loss), partners’ capital and cash flows for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with U.S. generally accepted accounting principles. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 27, 2020 expressed an unqualified opinion thereon. Basis for Opinion These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matter The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. Description of the Matter Revenue recognition -Estimation of variable consideration As described in Note 3 to the consolidated financial statements, the Partnership’s Offshore pipeline transportation segment has certain long-term contracts with customers that include variable consideration that must be estimated at contract inception and re-assessed at each reporting period. Total consideration for these arrangements is recognized as revenue over the performance obligation period, and the difference in timing of revenue recognition and billings results in contract assets and liabilities. As of December 31, 2019, the Partnership has recognized $21.9 million and $54.2 million in current and non-current contract assets, respectively, and $2.9 million and $23.2 million in current and non-current contract liabilities, respectively, in the consolidated financial statements. Auditing the Partnership’s revenue recognition for these contracts is particularly challenging because the estimate of variable consideration for these contracts involves management’s judgments of volumes that customers are expected to produce and transport over the contract term. Changes in this assumption or a contract modification could have a material effect on the amount of variable consideration recognized as revenue. F-1 Table of Contents How We Addressed the Matter in Our Audit We tested controls that address the risk of material misstatement relating to the estimation of variable consideration and associated contract assets and liabilities. For example, we tested controls over the completeness and accuracy of volumes transported and billings during the year and management’s review of estimated production over the performance obligation period. To test the Partnership’s estimates of variable consideration, we performed audit procedures that included, among others, evaluating management’s determination of the performance obligations in each arrangement and information used to establish or reassess the estimates including contractual pipeline capacity reserved, historical actual throughput volumes and third party production forecasts. We tested these assumptions by inspecting contracts, testing completeness and accuracy of production volumes and contract billings, and evaluating information obtained by management from customers and whether the information is consistent with publicly available information. We also performed a retrospective analysis of forecasted production volumes by comparing them to the actual volumes transported, and we performed sensitivity analyses to evaluate the changes in variable consideration that would result from changes in the Partnership's significant assumptions discussed herein. We also recalculated the Partnership’s revenue recognized for these arrangements and the recorded contract assets and liabilities as of and for the year ended December 31, 2019. /s/ Ernst & Young LLP We have served as the Partnership's auditor since 2017. Houston, Texas February 27, 2020 F-2 Table of Contents REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors of Genesis Energy, LLC and Unitholders of Genesis Energy, L.P. Opinion on Internal Control over Financial Reporting We have audited Genesis Energy, L.P.’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Genesis Energy, L.P. (the Partnership) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on the COSO criteria. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Partnership as of December 31, 2019 and 2018, the related consolidated statements of operations, comprehensive income (loss), partners’ capital and cash flows for each of the three years in the period ended December 31, 2019 and the related notes, and our report dated February 27, 2020 expressed an unqualified opinion thereon. Basis for Opinion The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s annual report on internal control over financial reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. Definition and Limitations of Internal Control Over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. /s/ Ernst & Young LLP Houston, TX February 27, 2020 F-3 GENESIS ENERGY, L.P. CONSOLIDATED BALANCE SHEETS (In thousands, except units) ASSETS Table of Contents CURRENT ASSETS: Cash and cash equivalents Restricted cash Accounts receivable—trade, net Inventories Other Total current assets FIXED ASSETS, at cost Less: Accumulated depreciation Net fixed assets MINERALS LEASEHOLDS, net of accumulated depletion NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income EQUITY INVESTEES INTANGIBLE ASSETS, net of amortization GOODWILL RIGHT OF USE ASSETS, net OTHER ASSETS, net of amortization TOTAL ASSETS LIABILITIES AND PARTNERS’ CAPITAL CURRENT LIABILITIES: Accounts payable—trade Accrued liabilities Total current liabilities SENIOR SECURED CREDIT FACILITY SENIOR UNSECURED NOTES, net of debt issuance costs DEFERRED TAX LIABILITIES OTHER LONG-TERM LIABILITIES Total liabilities MEZZANINE CAPITAL December 31, 2019 December 31, 2018 $ 29,128 $ 10,300 27,277 417,002 65,137 54,530 593,074 — 323,462 73,531 35,986 443,279 5,540,596 (1,246,121) 4,294,475 5,440,858 (1,023,825) 4,417,033 555,825 107,702 334,523 138,927 301,959 177,071 94,085 560,481 116,925 355,085 162,602 301,959 — 121,707 $ 6,597,641 $ 6,479,071 $ 218,737 $ 196,758 415,495 959,300 127,327 205,507 332,834 970,100 2,469,937 2,462,363 12,640 393,850 12,576 259,198 4,251,222 4,037,071 Class A Convertible Preferred Units, 25,336,778 and 24,438,022 issued and outstanding at December 31, 2019 and 2018, respectively Redeemable noncontrolling interests, 130,000 preferred units issued and outstanding at December 31, 2019 790,115 761,466 125,133 — COMMITMENTS AND CONTINGENCIES (Note 22) PARTNERS’ CAPITAL: Common unitholders, 122,579,218 and 122,579,218 units issued and outstanding at December 31, 2019 and 2018, respectively Accumulated other comprehensive income (loss) Noncontrolling interests Total partners' capital 1,443,320 (8,431) (3,718) 1,431,171 1,690,799 939 (11,204) 1,680,534 TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL $ 6,597,641 $ 6,479,071 The accompanying notes are an integral part of these consolidated financial statements. F-4 Table of Contents GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands, except per unit amounts) Year Ended December 31, 2019 2018 2017 REVENUES: Offshore pipeline transportation Sodium minerals and sulfur services Marine transportation Onshore facilities and transportation Total revenues COSTS AND EXPENSES: Onshore facilities and transportation product costs Onshore facilities and transportation operating costs Marine transportation operating costs Sodium minerals and sulfur services operating costs Offshore pipeline transportation operating costs General and administrative Depreciation, depletion and amortization Impairment expense Gain on sale of assets Total costs and expenses OPERATING INCOME Equity in earnings of equity investees Interest expense Other income (expense) Income (loss) from operations before income taxes Income tax benefit (expense) NET INCOME (LOSS) Net loss (income) attributable to noncontrolling interests Net income attributable to redeemable noncontrolling interests NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P. Less: Accumulated distributions attributable to Class A Convertible Preferred Units NET INCOME (LOSS) AVAILABLE TO COMMON UNITHOLDERS BASIC AND DILUTED NET INCOME (LOSS) PER COMMON UNIT: Basic and Diluted WEIGHTED AVERAGE OUTSTANDING COMMON UNITS: $ $ $ Basic and Diluted ` $ 318,116 $ 284,544 $ 1,105,987 235,645 821,072 2,480,820 637,699 77,205 178,032 883,692 58,996 52,687 319,806 — — 2,208,117 272,703 56,484 (219,440) (9,026) 100,721 (655) 100,066 (1,834) (2,233) 1,174,434 219,937 1,233,855 2,912,770 1,037,688 89,042 172,527 912,491 66,668 66,898 313,190 126,282 (42,264) 2,742,522 170,248 43,626 (229,191) 5,023 (10,294) (1,498) (11,792) 5,717 — 318,239 462,622 205,287 1,042,229 2,028,377 866,458 102,189 154,606 333,918 72,065 66,421 252,480 — (40,311) 1,807,826 220,551 51,046 (176,762) (16,715) 78,120 3,959 82,079 568 — 95,999 $ (6,075) $ 82,647 (74,467) (69,801) (21,995) 21,532 $ (75,876) $ 60,652 0.18 $ (0.62) $ 0.50 122,579 122,579 121,546 The accompanying notes are an integral part of these consolidated financial statements. F-5 Table of Contents GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (In thousands) Net income (loss) Other comprehensive income (loss): Decrease (increase) in benefit plan liability Total Comprehensive income (loss) Comprehensive (income) loss attributable to noncontrolling interests Comprehensive income attributable to redeemable noncontrolling interests Comprehensive income (loss) attributable to Genesis Energy, L.P. $ Year Ended December 31, 2019 2018 2017 $ 100,066 $ (11,792) $ 82,079 (9,370) 90,696 (1,834) (2,233) 86,629 1,543 (10,249) 5,717 — (4,532) $ (604) 81,475 568 — $ 82,043 The accompanying notes are an integral part of these consolidated financial statements. F-6 Table of Contents GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL (In thousands) Partners' Capital Noncontrolling Interest Accumulated Other Comprehensive Loss Total December 31, 2016 Net income (loss) Cash distributions to partners, net Cash contributions from noncontrolling interests Number of Common Units 117,979 — — — $ $ 2,130,331 82,647 (321,875) — Issuance of common units for cash, net (Note 12) 4,600 140,513 Other comprehensive loss Distributions to preferred unitholders December 31, 2017 Impact of adoption of ASC 606 Partners’ capital, January 1, 2018 Net loss Cash distributions to partners, net Cash contributions from noncontrolling interests Other comprehensive income Distributions to preferred unitholders December 31, 2018 Net income(1) Cash distributions to partners, net Cash contributions from noncontrolling interests Other comprehensive loss Distributions to preferred unitholders December 31, 2019 — — 122,579 — 122,579 — — — — — 122,579 — — — — — 122,579 — (5,469) 2,026,147 (3,550) 2,022,597 (6,075) (257,416) — — (68,307) 1,690,799 95,999 (269,674) — — (73,804) $ 1,443,320 $ (10,281) $ (568) — 2,770 — — — (8,079) — (8,079) (5,717) — 2,592 — — (11,204) 1,834 — 5,652 — — (3,718) $ — $ 2,120,050 82,079 — (321,875) 2,770 — — — (604) — (604) — (604) — — — 1,543 — 939 140,513 (604) (5,469) 2,017,464 (3,550) 2,013,914 (11,792) (257,416) 2,592 1,543 (68,307) 1,680,534 — — 97,833 (269,674) 5,652 (9,370) (73,804) (8,431) $ 1,431,171 — (9,370) — (1) Net income includes $74.5 million attributable to our Class A Convertible preferred unitholders accumulated as of December 31, 2019. The accompanying notes are an integral part of these consolidated financial statements. F-7 Table of Contents GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss) Adjustments to reconcile net income to net cash provided by operating activities - Depreciation, depletion and amortization Provision for leased items no longer in use Gain on sale of assets Impairment expense Amortization and write-off of debt issuance costs and premium or discount Amortization of unearned income and initial direct costs on direct financing leases Payments received under direct financing leases Equity in earnings of investments in equity investees Cash distributions of earnings of equity investees Non-cash effect of long-term incentive compensation plans Deferred and other tax benefits Unrealized (gains) losses on derivative transactions Other, net Net changes in components of operating assets and liabilities, net of acquisitions (See Note 16) Net cash provided by operating activities CASH FLOWS FROM INVESTING ACTIVITIES: Payments to acquire fixed and intangible assets Cash distributions received from equity investees—return of investment Investments in equity investees Acquisitions Contributions in aid of construction costs Proceeds from asset sales Net cash used in (provided by) investing activities CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings on senior secured credit facility Repayments on senior secured credit facility Proceeds from issuance of senior unsecured notes Net proceeds from issuance of preferred units (Note 12) Repayment of senior unsecured notes Debt issuance costs Issuance of common units for cash, net Contributions from noncontrolling interests Distributions to Class A Convertible Preferred unitholders Distributions to common unitholders Other, net Net cash provided by (used in) financing activities Net increase in cash and cash equivalents and restricted cash Cash and cash equivalents and restricted cash at beginning of period Cash and cash equivalents and restricted cash at end of period Year Ended December 31, 2018 2017 2019 $ 100,066 $ (11,792) $ 82,079 319,806 — — — 10,766 (12,247) 20,668 (56,484) 56,081 8,496 65 12,586 (6,418) 313,190 — (42,264) 126,282 12,165 (13,035) 20,668 (43,626) 42,735 3,941 663 (11,795) (4,941) 252,480 12,589 (40,311) — 13,103 (13,747) 20,668 (51,046) 47,316 (5,775) (4,060) 10,943 (10,839) (71,098) 382,287 (2,152) 390,039 10,156 323,556 (163,248) 21,250 — — — 1,187 (140,811) 815,100 (825,900) — 122,900 — — — 5,652 (43,506) (269,674) 57 (195,371) 46,105 10,300 $ 56,405 (195,367) 28,979 (3,018) (250,593) 35,582 (4,647) — (1,325,759) 124 — 85,722 310,099 (1,459,571) 140,693 980,700 (1,109,800) 1,458,700 (1,637,700) — 1,000,000 726,419 — (204,830) (145,170) (25,913) (242) 140,513 — 2,592 2,770 — (257,416) (137) (529,473) 1,259 9,041 — (321,875) (57) 1,138,027 2,012 7,029 $ 10,300 $ 9,041 The accompanying notes are an integral part of these consolidated financial statements. F-8 Table of Contents 1. Organization GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS We are a growth-oriented master limited partnership founded in Delaware in 1996 and focused on the midstream segment of the crude oil and natural gas industry in the Gulf Coast region of the United States and in the Gulf of Mexico. We provide an integrated suite of services to refiners, crude oil and natural gas producers, and industrial and commercial enterprise and have a diverse portfolio of assets, including pipelines, offshore hub and junction platforms, our trona and trona-based exploring, mining, processing, producing, marketing, and selling business based on Wyoming (our "Alkali Business"), refinery- related plants, storage tanks and terminals, railcars, rail unloading facilities, barges and other vessels, and trucks. We are owned 100% by our limited partners. Genesis Energy, LLC, our general partner, is a wholly-owned subsidiary. Our general partner has sole responsibility for conducting our business and managing our operations. We conduct our operations and own our operating assets through our subsidiaries and joint ventures. We currently manage our businesses through four divisions that constitute our reportable segments: • • • Offshore pipeline transportation, which includes processing of crude oil and natural gas in the Gulf of Mexico; Sodium minerals and sulfur services involving trona and trona-based exploring, mining, processing, soda ash production, marketing and selling activities, as well as processing of high sulfur (or “sour”) gas streams for refineries to remove the sulfur, and selling the related by-product, sodium hydrosulfide (or “NaHS,” commonly pronounced "nash"); Onshore facilities and transportation, which include terminaling, blending, storing, marketing, and transporting crude oil, petroleum products, and CO2; and • Marine transportation to provide waterborne transportation of petroleum products and crude oil throughout North America 2. Summary of Significant Accounting Policies Basis of Consolidation and Presentation The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2019 and 2018 and our results of operations, statements of comprehensive income (loss), changes in partners’ capital and cash flows for the years ended December 31, 2019, 2018 and 2017. All intercompany balances and transactions have been eliminated. The accompanying Consolidated Financial Statements include Genesis Energy, L.P. and its subsidiaries. Except per unit amounts, or as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars. Joint Ventures We participate in several joint ventures, including, in our offshore pipeline transportation segment, a 64% interest in Poseidon Oil Pipeline Company, L.L.C. (or "Poseidon"), a 25.7% interest in Neptune Pipeline Company, LLC and a 29% interest in Odyssey Pipeline L.L.C. (or "Odyssey"). We account for our investments in these joint ventures by the equity method of accounting. See Note 9. Use of Estimates The preparation of our Consolidated Financial Statements 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 based these estimates and assumptions on historical experience and other information that we believed to be reasonable under the circumstances. Significant estimates that we make include: (1) liability and contingency accruals, (2) estimated fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets, (3) estimates of future net cash flows from assets for purposes of determining whether impairment of those assets has occurred, and (4) estimates of future asset retirement obligations. Additionally, for purposes of the calculation of the fair value of awards under equity-based compensation plans, we make estimates regarding expected forfeiture rates of the rights and expected future distribution yield on our units. While we believe these estimates are reasonable, actual results could differ from these estimates. Changes in facts and circumstances may result in revised estimates. Cash and Cash Equivalents Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of three months or less. We periodically assess the financial condition of the institutions where these funds are held and believe that our credit risk is minimal. F-9 Table of Contents Restricted Cash Our restricted cash balance represents cash held to be used for purposes of our Granger expansion project, as well as a minimum working capital balance we are required to maintain at our unrestricted subsidiary level under contractual agreement and is classified as current on our Consolidated Balance Sheets (Note 12). Accounts Receivable We review our outstanding accounts receivable balances on a regular basis and record an allowance for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. Inventories Our inventories are valued at the lower of cost and net realizable value. With the exception of our Alkali Business, cost is determined principally under the average cost method within specific inventory pools. Within our Alkali Business, the cost of inventories are determined using the FIFO, except for materials and supplies which are recorded at average cost, and raw materials which are recorded at standard cost, which approximates actual cost. Fixed Assets and Mineral Leaseholds Property and equipment are carried at cost. Depreciation of property and equipment is provided using the straight-line method over the respective estimated useful lives of the assets. Asset lives are 5 to 40 years for pipelines and related assets, 20 to 30 years for marine vessels, 3 to 30 years for machinery and equipment, 3 to 7 years for transportation equipment, and 3 to 20 years for buildings and improvements, office equipment, furniture and fixtures and other equipment. Interest is capitalized in connection with the construction of major facilities. The capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset’s estimated useful life. Maintenance and repair costs are charged to expense as incurred. Costs incurred for major replacements and upgrades are capitalized and depreciated over the remaining useful life of the asset. Certain volumes of crude oil and refined products are classified in fixed assets, as they are necessary to ensure efficient and uninterrupted operations of the gathering businesses. These crude oil and refined products volumes are carried at their weighted average cost. Long-lived assets are reviewed for impairment. An asset is tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to be generated from the use and ultimate disposal of the asset. If the carrying value is determined to not be recoverable under this method, an impairment charge equal to the amount the carrying value exceeds the fair value is recognized. Fair value is generally determined from estimated discounted future net cash flows. Mineral leaseholds are depleted over their useful lives as determined under the units of production method. When it has been determined that a mineral property can be economically developed as a result of establishing proven and probable reserves, the costs incurred to develop such property through the commencement of production are capitalized. Deferred Charges on Marine Transportation Assets Our marine vessels are required by US Coast Guard regulations to be re-certified after a certain period of time, usually every five years. The US Coast Guard states that vessels must meet specified "seaworthiness" standards to maintain required operating certificates. To meet such standards, vessels must undergo regular inspection, monitoring, and maintenance, referred to as "dry-docking." Typical dry-docking costs include costs incurred to comply with regulatory and vessel classification inspection requirements, blasting and steel coating, and steel replacement. We defer and amortize these costs to maintenance and repair expense over the length of time that the certification is supposed to last. Asset Retirement Obligations Some of our assets have contractual or regulatory obligations to perform dismantlement and removal activities, and in some instances remediation, when the assets are abandoned. In general, our asset retirement obligations relate to future costs associated with the disconnecting or removing of our crude oil and natural gas pipelines and platforms, CO2 pipelines, barge decommissioning, removal of equipment and facilities from leased acreage and land restoration. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using our credit adjusted risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long- lived asset. The capitalized cost is depreciated over the useful life of the related asset. An ongoing expense is recognized for changes in fair value of the liability as a result of the passage of time, which is recorded as accretion expense and included within offshore pipeline transportation operating costs in the Consolidated Statements of Operations. See Note 8. F-10 Table of Contents Lease Accounting We enter into operating lease contracts for the right to utilize certain transportation equipment, facilities and equipment, and office space from third parties. For contracts that extend for a period greater than 12 months, we recognize a right of use asset and a corresponding lease liability on our Consolidated Balance Sheet. The present value of each lease is based on the future minimum lease payments in accordance with ASC 842 and is determined by discounting these payments using an incremental borrowing rate. From time to time, we enter into agreements in which we are lessors of our property or equipment. For operating leases, revenue is recorded once payment is received. For our direct finance lease we record the gross finance receivable, unearned income and the estimated residual value of the leased pipelines. Unearned income represents the excess of the gross receivable plus the estimated residual value over the costs of the pipelines. Unearned income is recognized as financing income using the interest method over the term of the transaction and is included in onshore facilities and transportation revenue in the Consolidated Statements of Operations. The pipeline cost is not included in fixed assets. Refer to Note 4 for additional information. Intangible and Other Assets Intangible assets with finite useful lives are amortized over their respective estimated useful lives on a straight line basis. 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 test intangible assets periodically to determine if impairment has occurred. An impairment loss is recognized for intangibles if the carrying amount of an intangible asset is not recoverable and its carrying amount exceeds its fair value. No impairment has occurred of intangible assets in any of the periods presented. Costs incurred in connection with our credit facilities and their related amendments have historically been capitalized and amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the “effective interest” method of amortization. Certain of our capitalized debt issuance costs related to our respective issuances of notes are classified as reductions in long-term debt. Goodwill Goodwill represents the excess of purchase price over fair value of net assets acquired. We evaluate, and test if necessary, goodwill for impairment annually at October 1, and more frequently if indicators of impairment are present. During the evaluation, we may perform a qualitative assessment of relevant events and circumstances to determine the likelihood of goodwill impairment. If it is deemed more likely than not that 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 necessary. 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. If the calculated fair value of the reporting unit exceeds its carrying value including associated goodwill amounts, the goodwill is considered to be unimpaired and no impairment charge is required. If the fair value of the reporting unit is less than its carrying value including associated goodwill amounts, the goodwill of that reporting unit is considered to be impaired and a charge to earnings must be recorded. The impact to earnings is the excess amount of carrying value over fair value, however the charge is not to exceed the total amount of goodwill allocated to the reporting unit under evaluation. See Note 10 for further information. Environmental Liabilities We provide for the estimated costs of environmental contingencies when liabilities are probable to occur and a reasonable estimate of the associated costs can be made. Ongoing environmental compliance costs, including maintenance and monitoring costs, are charged to expense as incurred. Equity-Based Compensation Our phantom units issued under our 2010 Long-Term Incentive Plan result in the payment of cash to our employees or directors of our general partner upon exercise or vesting of the related award. The fair value of our phantom units is equal to the market price of our common units. Our phantom units include both service-based and performance-based awards. For our performance-based awards, our fair value estimates are weighted based on probabilities for each performance condition applicable to the award. See Note 17 for more information. Revenue Recognition We recognize revenue across our operating segments upon the satisfaction of their respective performance obligations. Refer to Note 3 for additional details on what constitutes a performance obligation in each of our businesses. F-11 Table of Contents Cost of Sales and Operating Expenses Onshore facilities and transportation operating and product costs include the cost to acquire the product and the associated costs to transport it to our terminal facilities, including storing, or to a customer for sale. Other than the cost of the products, the most significant costs we incur relate to transportation utilizing our fleet of trucks, railcars, terminals, barges and other vessels, including personnel costs, fuel and maintenance of our or third-party owned equipment. Additionally, costs to operate and maintain the integrity of our onshore pipelines are included herein. When we enter into buy/sell arrangements concurrently or in contemplation of one another with a single counterparty, we reflect the amounts of revenues and purchases for these transactions on a net basis in our Consolidated Statements of Operations as onshore facilities and transportation revenues. Marine operating costs consist primarily of employee and related costs to man the boats, barges, and vessels, maintenance and supply costs related to general upkeep of the boats, barges, and vessels, and fuel costs which are often rebillable and passed through to the customer. The most significant operating costs in our sodium minerals and sulfur services segment consist of the costs to operate our trona extraction and soda ash processing facilities, NaHS processing plants located at various refineries, caustic soda used in the process of processing the refiner’s sour gas, and costs to transport the soda ash, other alkali products, NaHS and caustic soda. Pipeline operating costs consist primarily of power costs to operate pumping and platform equipment, personnel costs to operate the pipelines and platforms, insurance costs and costs associated with maintaining the integrity of our pipelines. Income Taxes We are a limited partnership, organized as a pass-through entity for federal income tax purposes. As such, we do not directly pay federal income tax. Our taxable income or loss, which may vary substantially from the net income or net loss we report in our Consolidated Statements of Operations, is included in the federal income tax returns of each partner. Some of our corporate subsidiaries pay U.S. federal, state, and foreign income taxes. Deferred income tax assets and liabilities for certain operations conducted through corporations are recognized for temporary differences between the assets and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance for the amount of any tax benefit not expected to be realized. Penalties and interest related to income taxes will be included in income tax expense in the Consolidated Statements of Operations. Derivative Instruments and Hedging Activities When we hold inventory positions in crude oil and petroleum products, we use derivative instruments to hedge exposure to price risk. Derivative transactions, which can include forward contracts and futures positions on the NYMEX, are recorded in the Consolidated Balance Sheets as assets and liabilities based on the derivative’s fair value. Changes in the fair value of derivative contracts are recognized currently in earnings unless specific hedge accounting criteria are met. We must formally designate the derivative as a hedge and document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting. Accordingly, changes in the fair value of derivatives are included in earnings in the current period for (i) derivatives accounted for as fair value hedges; (ii) derivatives that do not qualify for hedge accounting and (iii) the portion of cash flow hedges that is not highly effective in offsetting changes in cash flows of hedged items. Changes in the fair value of cash flow hedges are deferred in Accumulated Other Comprehensive Income (“AOCI”) and reclassified into earnings when the underlying position affects earnings. In addition, we have determined that certain provisions in our Class A Convertible Preferred units represent an embedded derivative which must be bifurcated and recorded at fair value, with changes in fair value in respective periods being recorded in our Consolidated Statements of Operations. See Note 19 for further information on these items. Fair Value of Current Assets and Current Liabilities The carrying amount of other current assets and other current liabilities approximates their fair value due to their short-term nature. Pension benefits We sponsor a defined benefit plan for employees of our Alkali Business. The defined benefit plan is accounted for using actuarial valuations as required by GAAP. We recognize the funded status of the defined pension plan on the balance sheet and recognize changes in the funded status that arise during the period but are not recognized as components of net periodic benefit cost within other comprehensive income (loss). F-12 Table of Contents Business Acquisitions For acquired businesses, we apply the acquisition method and generally recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the date of acquisition. See Note 5 for more information regarding our acquisition accounting and recording of acquisition costs. Recent and Proposed Accounting Pronouncements In June 2016, the FASB issued ASU 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” ("ASU 2016-13"). ASU 2016-13 changes 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 will be required to use a new forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. The guidance also requires increased disclosures. ASU 2016-13 is effective for interim and annual periods beginning after December 15, 2019. The standard requires varying transition methods for the different categories of amendments. We have performed an assessment which consisted of reviewing current and historical information pertaining to our trade accounts receivable and existing contract assets and we anticipate no material impact to our consolidated financial statements as of the adoption date. We have adopted guidance under ASC Topic 606, Revenue from Contracts with Customers, and all related ASUs (collectively "ASC 606") as of January 1, 2018 utilizing the modified retrospective method of adoption. Refer to Note 3 for further details. 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. In August 2016, the FASB issued guidance that addresses how certain cash receipts and payments are presented and classified in the statement of cash flows under Topic 230, Statement of Cash flow, and other Topics. The guidance is effective for annual reporting periods, and interim periods therein, beginning after December 15, 2017. We have adopted this guidance as of January 1, 2018 using the retrospective transition method to each period presented on the Consolidated Statements of Cash Flows. We reclassified $15.3 million from operating cash flows to investing cash flows for the year ended December 31, 2017. In March 2017, the FASB issued ASU 2017-07, Compensation-Retirement Benefits (Topic 715). ASU 2017-07 requires employers to separate the service cost component from the other components of net benefit cost in the period. The new standard requires the other components of net benefit costs (excluding service costs), be reclassified to "Other expense" from "General and administrative." We adopted this standard as of January 1, 2018. This standard is applied retrospectively. The effect was not material to our financial statements for the year ended December 31, 2018. In January 2017, the FASB issued guidance to simplify the goodwill impairment testing at annual or interim periods. The guidance eliminates Step 2 from the goodwill impairment testing process, and any identified impairment charge would be simplified to be the difference between the carrying value and fair value of a reporting unit, but would not exceed the total amount of goodwill allocated to the reporting unit in question. The guidance is effective for annual reporting periods, and interim periods therein, beginning after December 15, 2019. We elected to early adopt this standard as of January 1, 2017. See Note 10 for further information. F-13 Table of Contents 3. Revenue Recognition Revenue from Contracts with Customers The following table reflects the disaggregation of our revenues by major category for the years ended December 31, 2019 and December 31, 2018, respectively: Fee-based revenues Product Sales Refinery Services Fee-based revenues Product Sales Refinery Services Year Ended December 31, 2019 Onshore Facilities & Transportation Sodium Minerals & Sulfur Services Offshore Pipeline Transportation Marine Transportation Consolidated $ 160,431 $ — $ 318,116 $ 235,645 $ 714,192 660,641 1,023,667 — $ 821,072 82,320 $ 1,105,987 — — — — $ 318,116 $ 235,645 1,684,308 82,320 $ 2,480,820 Year Ended December 31, 2018 Onshore Facilities & Transportation Sodium Minerals & Sulfur Services Offshore Pipeline Transportation Marine Transportation Consolidated $ 156,266 $ — $ 284,544 $ 219,937 $ 660,747 1,077,589 1,071,634 — $ 1,233,855 102,800 $ 1,174,434 — — — — $ 284,544 $ 219,937 2,149,223 102,800 $ 2,912,770 The Company recognizes revenue upon the satisfaction of its performance obligations under its contracts. The timing of revenue recognition varies for the revenue streams described in more detail below. In general, the timing includes recognition of revenue over time as services are being performed as well as recognition of revenue at a point in time, for delivery of products. Fee-based Revenues We provide a variety of fee-based transportation and logistics services to our customers across several of our reportable segments as outlined below. Service contracts generally contain a series of distinct services that are substantially the same and have the same pattern of transfer to the customer over the contract period, and therefore qualify as a single performance obligation that is satisfied over time. The customer receives and consumes the benefit of our services simultaneously with the provision of those services. Offshore Pipeline Transportation Revenue from our offshore pipelines is generally based upon a fixed fee per unit of volume (typically per Mcf of natural gas or per barrel of crude oil) gathered, transported, or processed for each volume delivered. Fees are based either on contractual arrangements or tariffs regulated by the FERC. Certain of our contracts include a single performance obligation to stand ready, on a monthly basis, to provide capacity on our assets. Revenue associated with these fee-based services is recognized as volumes are delivered over the performance obligation period. In addition to the offshore pipeline transportation revenue discussed above, we also have certain contracts with customers in which we earn either demand-type fees or firm capacity reservation fees. These fees are charged to a customer regardless of the volume the customer actually delivers to the platform or through the pipeline. In addition to these offshore pipeline transportation revenue streams, we also have certain customer contracts in which the transportation fee has a tiered pricing structure based on cumulative milestones of throughput on the related pipeline asset and contract, or on a specified date. The performance obligation for these contracts is to transport, gather or process commodity volumes for the customer based on firm (stand ready) service or from monthly nominations made by our customers, which can also be on an interruptible basis. While our transportation rate changes when milestones are achieved for certain F-14 Table of Contents cumulative throughput, our performance obligation does not change throughout the life of the contract. Therefore revenue is recognized on an average rate basis throughout the life of the contract. We have estimated the total consideration to be received under the contract beginning at the contract inception date based on the estimated volumes (including certain minimum volumes we are required to stand ready for), price indexing, estimated production or contracted volumes, and the contract period. We have constrained the estimates of variable consideration such that it is probable that a significant reversal of previously-recognized revenue will not occur throughout the life of the contract. These estimates will be reassessed at each reporting period as required. Billings to our customers are reflected at the contract rate. The difference between the consideration received from our customers from invoicing compared to the revenue recognized creates a contract asset or liability. In circumstances where the estimated average contract rate is less than the billed current price tier in the contract, we will recognize a contract liability. In circumstances where the estimated average contract rate is higher than the billed current price tier in the contract, we will recognize a contract asset. Onshore Facilities and Transportation Within our onshore facilities and transportation segment, we provide our customers with pipeline transportation, terminalling services, and rail unloading services, among others, primarily on a per barrel fee basis. Revenues from contracts for the transportation of crude oil by our pipelines are based on actual volumes at a published tariff and some contain minimum throughput provisions which reset within one year. We recognize revenues for transportation and other services over the performance obligation period, which is the contract term. Revenues for both firm and interruptible transportation and other services are recognized over time as the product is delivered to the agreed upon delivery point or at the point of receipt because they specifically relate to our efforts to transfer the distinct services. Pricing for our services is determined through a variety of mechanisms, including specified contract pricing or regulated tariff pricing. The consideration we receive under these contracts is variable, as the total volume of the commodity to be transported is unknown at contract inception. At the end of a day or month (as specified in the contract), both the price and volume are known (or “fixed”) in order to allow us to accurately calculate the amount of consideration we are entitled to invoice. The measurement of these services and invoicing occurs on a monthly basis. Pipeline Loss Allowances To compensate us for bearing the risk of volumetric losses of crude oil in transit in our pipelines (for our onshore and offshore pipelines) due to temperature, crude quality, and the inherent difficulties of measurement of liquids in a pipeline, our tariffs and agreements allow for us to make volumetric deductions for quality and volumetric fluctuations. We refer to these deductions as pipeline loss allowances ("PLA"). We compare these allowances to the actual volumetric gains and losses of the pipeline and the net gain or loss is recorded as revenue or a reduction of revenue. As the allowance is related to our pipeline transportation services, the performance obligation is the obligation to transport and deliver the barrels and is considered a single obligation. When net gains occur, we have crude oil inventory. When net losses occur, we reduce any recorded inventory on hand and record a liability for the purchase of crude oil required to replace the lost volumes. Under ASC 606, we record excess oil as non-cash consideration in the transaction price on a net basis. The net oil recorded is valued at the lower of cost or net realizable value using the market price of crude oil during the month the product was transported. The crude oil in inventory can then be sold at current prevailing market prices, resulting in additional revenue if the sales price exceeds the inventory value when control transfers to the customer. Marine Transportation Our marine transportation business consists of revenues from the inland and offshore marine transportation of heavy refined petroleum products, asphalt and crude oil, using our barges or vessels. This revenue is recognized over the passage of time of individual trips as determined on an individual contract basis. Revenue from these contracts is typically based on a set day-rate or a set fee per cargo movement. The costs of fuel and certain other operational costs may be directly reimbursed by the customer, if stipulated in the contract. Our performance obligation consists of providing transportation services using our vessels for a single day either under a term or spot based contract. The transaction price is usually fixed per the contract either as a day rate or as a lump sum to be allocated over the days required to complete the service. Revenue is recognizable as the transportation service utilizing our vessels occurs, as the customer simultaneously receives and consumes these services as they are provided. If provided in the contract, certain items such as fuel or operational costs can be rebilled to the customer in the same period in which the costs are incurred. In the event the timing of a trip to provide our services crosses a reporting period under a lump sum fee contract, the revenue earned is accrued based on the progress completed in the current period on the related performance obligation as F-15 Table of Contents we are entitled to payment for each day. Customer invoicing occurs at the completion of a trip, or earlier at the customer’s request. Product Sales Sodium Minerals and Sulfur Services Product sales in our sodium minerals and sulfur services segment primarily involve the sales of caustic soda, NaHS, soda ash and other alkali products. As it relates to revenue recognition, these sales transactions contain a single performance obligation, which is the delivery of the product to the customer at the agreed upon point of sale. For some transactions, control of product transfers to the customer at the shipping point, but we are obligated to arrange for shipment of the product as directed by the customer. Rather than treating these shipping activities as separate performance obligations, our policy is to account for them as fulfillment costs in accordance with ASC 606. The transaction price for these product sales are determined by specific contracts, typically at a fixed rate or based on a market or indexed rate. This pricing is known, or is “fixed,” at the time of revenue recognition. Invoicing and related payment terms are in accordance with industry standard or contract specification based on final pricing. The entirety of the transaction price is allocated to the performance obligation, which is delivery of the product at the agreed upon point of sale. As this type of revenue is earned at a point in time, there is no allocation of transaction price to future performance obligations. Onshore Facilities and Transportation Product sales in our onshore facilities and transportation segment primarily involve the sales of crude oil and petroleum products. These contracts contain a single performance obligation, which is the delivery of the product to the customer at a specified location. These contracts are settled on a monthly basis for term contracts, or on a spot basis. Invoicing and related payment terms are in accordance with industry standard or contract specification based on final pricing. Pricing is designated within the contracts and is either fixed, index-based or formulaic, utilizing an average price for the month or for a specified range of days, regardless of when delivery occurs. In either case, pricing is known at the time of invoicing. The entirety of the consideration is allocated to a single performance obligation, which is delivery of the product to a specified location. As this type of revenue is earned at a point in time, there is no allocation of transaction price to future performance obligations. Refinery Services Our refinery services business primarily provides sulfur extraction services to refiners’ high sulfur (or “sour”) gas streams that the refineries have generated from crude oil processing operations. Our process applies our proprietary technology, which uses caustic soda to act as a scrubbing agent at a prescribed temperature and pressure to remove sulfur. The technology returns a clean (sulfur-free) hydrocarbon stream to the refinery for further processing into refined products, and simultaneously produces NaHS. Units of NaHS are produced ratably as a gas stream is processed. We obtain control and ownership of the NaHS immediately upon production, which constitutes the sole consideration that we received for our sulfur removal services. We later market this product to third parties as part of our product sales, as described above. As part of some of our arrangements, we pay a refinery access fee (“RSA fee”) for any benefits received by virtue of our plant’s proximity to the customer’s refinery. Our RSA fee is recorded as a reduction of revenue. Providing sulfur removal services is the singular performance obligation in our refinery service agreements. As our customers simultaneously receive and consume the refinery service benefits, control is transferred and revenue is recognized over time based on the extent of progress towards completion of the performance obligations. We use units of NaHS produced during a period to measure progress as the amount we receive corresponds directly with the efforts to provide our services completed to date. The transaction price for each performance obligation is determined using the fair value of a unit of NaHS on the contract inception date for each refinery services agreement. Accordingly, we record the value of NaHS received as non-cash consideration in inventory until it is subsequently sold to our customers (see Product Sales, above). Contract Assets and Liabilities The table below depicts our contract asset and liability balances at December 31, 2019 and December 31, 2018: Contract Assets Current Contract Assets Non-Current Contract Liabilities Contract Liabilities Current Non-Current Balance at December 31, 2018 $ Balance at December 31, 2019 — $ 21,912 72,241 $ 54,232 — $ 2,896 26,271 23,170 F-16 Table of Contents During the year ended December 31, 2019, $2.0 million that was previously classified as a contract liability at the beginning of the period was recognized as revenue. No such revenues were recognized for the year ended December 31, 2018. Additionally, no revenues were recognized related to performance obligations satisfied or partially satisfied from a previous period for the years ended December 31, 2019 and December 31, 2018 and we did not have any contract modifications during the period that would affect our contract asset and liability balances. Accounts receivable-trade, net does not include consideration received in kind from our refinery services process. Transaction Price Allocations to Remaining Performance Obligations We are required to disclose the amount of our transaction prices that are allocated to unsatisfied performance obligations as of December 31, 2019. However, ASC 606 provides the following practical expedients and exemptions that we utilized: 1) Performance obligations that are part of a contract with an expected duration of one year or less; 2) Revenue recognized from the satisfaction of performance obligations where we have a right to consideration in an amount that corresponds directly with the value provided to customers; and 3) Contracts that contain variable consideration, such as index-based pricing or variable volumes, that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that is part of a series. We apply these practical expedients and exemptions to our revenue streams recognized over time. The majority of our contracts qualify for one of these expedients or exemptions. After considering these practical expedients and identifying the remaining contract types that involve revenue recognition over a long-term period and include long-term fixed consideration (adjusted for indexing as required), we determined our allocations of transaction price that relate to unsatisfied performance obligations. As it relates to our tiered pricing offshore transportation contracts, we provide firm capacity for both fixed and variable consideration over a long term period. Therefore, we have allocated the remaining contract value (as estimated and discussed above) to future periods. In our onshore facilities and transportation segment, we have certain contractual arrangements in which we receive fixed minimum payments for our obligation to provide minimum capacity on our pipelines and related assets. The following chart depicts how we expect to recognize revenues for future periods related to these contracts: Offshore Pipeline Transportation Onshore Facilities and Transportation 2020 2021 2022 2023 2024 Thereafter Total $ $ 75,021 $ 58,623 69,134 58,540 52,812 154,899 469,029 $ 57,615 20,269 4,283 — — — 82,167 4. Lease Accounting Lessee Arrangements We lease a variety of transportation equipment (including trucks, trailers, and railcars), terminals, land and facilities, and office space and equipment. Lease terms vary and can range from short term (under 12 months) to long term (greater than 12 months). A majority of our leases contain options to extend the life of the lease at our sole discretion. We considered these options when determining the lease terms used to derive our right of use asset and associated lease liability. Leases with a term of less than 12 months are not recorded on our consolidated balance sheet and we recognize lease expense for these leases on a straight line basis over the lease term. Certain lease agreements include lease and non-lease components. We have elected to combine lease and non-lease components for all of our underlying assets for the purpose of deriving our right of use asset and lease liability. Additionally, F-17 Table of Contents certain lease payments are driven by variable factors, such as plant production or indexing rates. Variable costs are expensed as incurred and are not included in our determination for our lease liability and right of use asset. As a lessee, we do not have any finance leases and none of our leases contain material residual value guarantees or material restrictive covenants. In addition, most of our leases do not provide an implicit rate, and as such, we determined our incremental borrowing rate based on the information available at January 1, 2019 in determining the present value of lease payments. Our lease portfolio consists of operating leases within three major categories: Leases Assets Total Right of Use Assets, net Liabilities Current Non-Current Total Lease Liability Classification Financial Statement Caption December 31, 2019 January 1, 2019 Transportation Equipment Office Space & Equipment Facilities and Equipment Right of Use Assets, net Right of Use Assets, net Right of Use Assets, net $ 98,588 $ 117,727 11,085 14,194 67,398 77,008 $ 177,071 $ 208,929 Accrued liabilities Other long-term liabilities 28,406 144,910 33,016 171,348 $ 173,316 $ 204,364 Our Right of Use Assets, net balance above includes our unamortized initial direct costs associated with certain of our transportation equipment leases. Additionally, it includes our unamortized prepaid rents, our deferred rents, and our previously classified intangible asset associated with a favorable lease (Note 10). Our lease liability includes our remaining provision for each period presented for our cease-use provision for railcars no longer in use. We recorded total operating lease expense of $27.2 million, $30.8 million, and $36.9 million for the years ended December 31, 2019, 2018, and 2017. The total operating lease expense is net of our variable railcar mileage credits we receive in our Alkali Business of $24.8 million, $26.2 million, and $8.4 million for the years ended December 31, 2019, 2018, and 2017, for which we only owned our Alkali Business for four months. The total operating cost includes the amounts associated with our existing lease liabilities, along with both short term and variable lease costs incurred during the period which are not significant to the operating lease cost individually, or in the aggregate. The maturities of our operating lease liabilities as of December 31, 2019 on an undiscounted cash flow basis reconciled to the present value recorded on our Consolidated Balance Sheet: Maturity of Lease Liabilities Transportation Equipment Office Space and Equipment Facilities and Equipment Operating Leases 2020 2021 2022 2023 2024 $ Thereafter Total Lease Payments Less: Interest Present value of operating lease liabilities $ 26,355 $ 20,282 18,022 17,160 16,355 27,163 125,337 (23,428) 101,909 $ F-18 4,119 $ 3,163 2,453 678 689 1,723 12,825 (1,619) 11,206 $ 9,309 $ 6,696 5,383 5,325 4,801 123,897 155,411 (95,210) 60,201 $ 39,783 30,141 25,858 23,163 21,845 152,783 293,573 (120,257) 173,316 Table of Contents The following table presents the weighted average remaining term and discount rate related to our right of use assets: Lease Term and Discount Rate Weighted-average remaining lease term Weighted-average discount rate December 31, 2019 12.53 years 7.61% The following table provides information regarding the cash paid and right of use assets obtained related to our operating leases: Cash Flows Information Cash paid for amounts included in the measurement of lease liabilities $ Leased assets obtained in exchange for new operating lease liabilities December 31, 2019 44,046 198,389 Lessor Arrangements We have the following contracts in which we act as a lessor. We also, from time to time, sublease certain of our transportation and facilities equipment to third parties. Operating Leases We act as a lessor in our revenue contract associated with the M/T American Phoenix, within our marine transportation segment. The M/T American Phoenix ocean tanker is currently under charter along the Gulf Coast with a large refining customer. We recorded lease revenue of $27.0 million for the year ended December 31, 2019, $27.0 million for the year ended December 31, 2018 and $25.1 million for the year ended December 31, 2017, respectively, which is recorded in marine transportation revenues on the Consolidated Statements of Operations. Additionally, we act as a lessor on our Free State pipeline system, which is included in the onshore and facilities transportation segment. The Free State pipeline is an 86 mile pipeline in Eastern Mississippi used to transport CO2 that is recovered in the area downstream to several delivery points in and around the Mississippi region. Our Free State pipeline is currently under lease through 2028 to an affiliate of an independent crude oil company. We receive fixed installments through the life of the lease as well as variable consideration that is determined by average daily volumes of throughput. We recorded total revenue of $6.1 million for the year ended December 31, 2019, $6.6 million for the year ended December 31, 2018 and $5.2 million for the year ended December 31, 2017, respectively, which is recorded in onshore facilities and transportation revenues on the Consolidated Statements of Operations. Direct Finance Lease Our direct finance lease includes a lease of the Northeast Jackson Dome ("NEJD") Pipeline. Under the terms of the agreement, we are paid a quarterly payment, which commenced in August 2008. These payments are fixed at approximately $5.2 million per quarter during the lease term at an interest rate of 10.25%. At the end of the lease term in 2028, we will convey all of our interest in the NEJD Pipeline to the lessee for a nominal payment. F-19 Table of Contents The following table details the fixed lease payments we will receive for our lessor arrangements as of December 31, 2019: Maturity of Lessor Receipts Marine Transportation Onshore Facilities and Transportation Operating Leases Direct Financing Lease Onshore Facilities and Transportation 2020 2021 2022 2023 2024 Thereafter Total Lease Receipts Less: Interest Total Net Lease Receipts $ $ 20,128 $ — — — — — 20,128 — 20,128 $ 1,200 $ 1,200 1,200 1,200 1,200 4,100 10,100 — 10,100 $ 20,668 20,668 20,668 20,668 20,668 72,336 175,676 (58,680) 116,996 The present value of our lease receivables for our direct finance lease includes a current portion of $9.3 million and $8.4 million, which is recorded in other current assets on the Consolidated Balance Sheets as of December 31, 2019 and December 31, 2018, respectively. 5. Acquisitions Alkali Business On September 1, 2017, we acquired our Alkali Business for approximately $1.325 billion (inclusive of approximately $105 million in working capital). Our Alkali Business mines and processes trona from which it produces natural soda ash, also known as sodium carbonate (Na2CO3), as 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. To finance that transaction and the related costs, we used proceeds from (i) a $550 million public offering of 6.50% senior unsecured notes due 2025 in August 2017, generating net proceeds of $540.1 million after issuance and underwriting fees, (ii) a $750 million private placement of Class A Convertible Preferred units in September 2017, generating net proceeds of $726.4 million, (iii) borrowings under our revolving credit facility and (iv) cash on hand. We have reflected the financial results of our Alkali Business in our sodium minerals and sulfur services segment from the date of acquisition. The purchase price has been allocated to the assets acquired and liabilities assumed and the fair values were developed by management with the assistance of a third-party valuation firm. Our finalized purchase price allocation remains unchanged from what was disclosed in the financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2017. The allocation of the purchase price, as presented on our Consolidated Balance Sheet, is summarized as follows: Accounts receivable Inventories Other current assets Fixed assets Mineral leaseholds Intangible assets Other assets Accounts payable Accrued Liabilities Other long-term liabilities Total Purchase Price F-20 $ $ 138,258 34,929 13,254 663,217 566,019 800 3,612 (44,547) (36,884) (13,658) 1,325,000 Table of Contents Fixed assets identified in connection with our valuation and purchase price allocation include the related facilities, machinery and equipment associated with our Alkali Business, principally at our Green River, Wyoming operations. These assets will be depreciated under the straight line method and have useful lives ranging from 2 to 30 years. Mineral leaseholds include the trona reserves at our Green River, Wyoming facility and are depleted over their useful lives as determined by the units of production method. Other long-term liabilities contains various items including assumed employee benefit plan obligations. Other items principally consist of working capital items of our Alkali Business as acquired on September 1, 2017. Our Consolidated Financial Statements include the results of our Alkali Business since September 1, 2017, the closing date of the acquisition. The following table presents selected financial information included in our Consolidated Financial Statements for the periods presented: Revenues Net income Year Ended December 31 2017 $ 277,011 42,014 The table below presents selected unaudited pro forma financial information incorporating the historical results of our Alkali Business. The pro forma financial information below has been prepared as if the acquisition had been completed on January 1, 2016 and is based upon assumptions deemed appropriate by us and may not be indicative of actual results. This pro forma information was prepared using historical financial data of our trona and trona-based exploring, mining, processing, producing, marketing and selling business and reflects certain estimates and assumptions made by our management. Our unaudited pro forma financial information is not necessarily indicative of what our consolidated financial results would have been had our Alkali Business acquisition been completed on January 1, 2017. Pro forma net income includes the effects of distributions on preferred units and interest expense on incremental borrowings. The dilutive effect of our Class A Convertible Preferred Units is calculated using the if-converted method. Pro forma consolidated financial operating results: Revenues Net Income Attributable to Genesis Energy, L.P. Net Income Available to Common Unitholders Basic and diluted earnings per common unit: As reported net income per common unit Pro forma net income per common unit, basic and dilutive Year Ended December 31 2017 $ $ $ 2,549,438 108,392 42,768 0.50 0.35 As relating to our Alkali Business acquisition, we incurred approximately $12.0 million in acquisition related costs through December 31, 2017, and incurred an additional $2.0 million during the year ended December 31, 2018. Such costs are included as "General and Administrative costs" on our Consolidated Statement of Operations. 6. Receivables Accounts receivable – trade, net consisted of the following: Accounts receivable - trade Allowance for doubtful accounts Accounts receivable - trade, net December 31, 2019 2018 $ $ 418,064 (1,062) 417,002 $ $ 330,855 (7,393) 323,462 The following table presents the activity of our allowance for doubtful accounts for the periods indicated: F-21 Table of Contents Balance at beginning of period Charged to costs and expenses, net of recoveries Amounts written off Balance at end of period 7. Inventories The major components of inventories were as follows: Petroleum products Crude oil Caustic soda NaHS Raw materials - Alkali Operations Work-in-process - Alkali Operations Finished goods, net - Alkali Operations Materials and supplies, net - Alkali Operations Other Total 2019 December 31, 2018 2017 $ $ 7,393 (5,572) (759) 1,062 $ $ 8,468 31 (1,106) 7,393 $ $ 6,505 2,001 (38) 8,468 December 31, 2019 2018 $ 2,721 $ 5,271 5,965 10,845 6,238 8,579 14,168 11,350 — 12,203 8,379 10,372 12,400 5,952 2,322 11,402 10,490 11 $ 65,137 $ 73,531 Inventories are valued at the lower of cost or net realizable value. The net realizable value of inventories were not recorded below cost as of December 31, 2019 and were recorded below cost by $1.0 million as of December 31, 2018; therefore we reduced the value of inventory in our Consolidated Financial Statements for this difference in 2018. Materials and supplies include chemicals, maintenance supplies, and spare parts which will be consumed in the mining of trona ore and production of soda ash processes. F-22 Table of Contents 8. Fixed Assets, Mineral Leaseholds and Asset Retirement Obligations Fixed Assets Fixed assets consisted of the following: Crude oil pipelines and natural gas pipelines and related assets Alkali facilities, machinery, and equipment Onshore facilities, machinery, and equipment Transportation equipment Marine vessels Land, buildings and improvements Office equipment, furniture and fixtures Construction in progress Other Fixed assets, at cost Less: Accumulated depreciation Net fixed assets Mineral Leaseholds December 31, 2019 2018 $ 2,891,489 $ 2,918,285 591,547 640,376 19,864 979,171 238,451 22,645 115,162 41,891 533,924 639,023 20,102 951,597 222,242 20,505 94,025 41,155 5,540,596 (1,246,121) 4,294,475 $ 5,440,858 (1,023,825) 4,417,033 $ Our Mineral Leaseholds, relating to our acquired Alkali Business, consist of the following: Mineral leaseholds Less: Accumulated depletion Mineral leaseholds, net December 31, 2019 December 31, 2018 $ $ 566,019 (10,194) 555,825 $ $ 566,019 (5,538) 560,481 Depreciation expense was $295.6 million, $286.0 million and $226.0 million for the years ended December 31, 2019, 2018, and 2017, respectively. Depletion expense was $4.7 million, $4.0 million, and $1.5 million for the years ended December 31, 2019, 2018 and 2017, respectively. On October 11, 2018, we completed the divestiture of our Powder River Basin midstream assets, included in our Onshore Facilities and Transportation segment, and received total net proceeds of approximately $300 million. This sale resulted in a gain of $38.9 million recorded in Gains on assets sales in the Consolidated Statements of Operations. Additionally, we recorded an impairment expense of $21.2 million on our remaining non-core midstream assets in the Powder River Basin as the carrying value exceeded the fair value in the current market at December 31, 2018. We divested these assets during the fourth quarter of 2019. During 2018, we also recorded impairment expense of $82.0 million associated with certain of our non-core offshore gas assets in the Gulf of Mexico due to a change in contractual arrangements during the fourth quarter. Included in this amount is the acceleration in timing of the abandonment of one of our offshore hub platforms and pipelines and the write-off of its associated asset retirement obligation assets. The fair value of our assets was determined based on present value techniques. F-23 Table of Contents Asset Retirement Obligations We record AROs in connection with legal requirements to perform specified retirement activities under contractual arrangements and/or governmental regulations. For any AROs acquired, we record AROs based on the fair value measurement assigned during the preliminary purchase price allocation. A reconciliation of our liability for asset retirement obligations is as follows: December 31, 2017 Accretion expense Revisions in timing and estimated costs of AROs Settlements December 31, 2018 Accretion expense Revisions in timing and estimated costs of AROs Settlements December 31, 2019 $ 198,187 10,509 44,319 (13,150) 239,865 9,402 (20,529) (53,657) 175,081 $ At December 31, 2019 and December 31, 2018, $26.6 million and $67.5 million are included as current in "Accrued liabilities" on our Consolidated Balance Sheets, respectively. Revisions in timing and estimated costs during 2019 and 2018 are primarily attributable to the accelerated timing and revised costs associated with the abandonment of certain of our non-core offshore gas assets in the Gulf of Mexico. The remainder of the ARO liability at each period is included in "Other long-term liabilities" on our Consolidated Balance Sheet. With respect to our AROs, the following table presents our forecast of accretion expense for the periods indicated: 2020 $ 2021 $ 2022 $ 2023 $ 2024 $ 8,860 8,939 9,417 10,081 10,792 Certain of our unconsolidated affiliates have AROs recorded at December 31, 2019 relating to contractual agreements and regulatory requirements. These amounts are immaterial to our Consolidated Financial Statements. 9. Equity Investees We account for our ownership in our joint ventures under the equity method of accounting (see Note 2 for a description of these investments). The price we pay to acquire an ownership interest in a company may exceed or be less than the underlying book value of the capital accounts we acquire. At December 31, 2019 and 2018, the unamortized differences in carrying value totaled $350.9 million and $366.4 million, respectively. We amortize the differences in carrying value as a change in equity earnings. The following table presents information included in our Consolidated Financial Statements related to our equity investees. Genesis’ share of operating earnings Amortization of differences attributable to Genesis' carrying value of equity investments Net equity in earnings Distributions received Year Ended December 31, 2019 2018 2017 71,975 $ 59,255 $ 66,814 (15,491) 56,484 77,331 $ $ (15,629) 43,626 71,714 $ $ (15,768) 51,046 82,898 $ $ $ F-24 Table of Contents The following tables present the combined balance sheet information for the last two years and income statement data for the last three years for our equity investees (on a 100% basis): BALANCE SHEET DATA: Assets Current assets Fixed assets, net Other assets Total assets Liabilities and equity Current liabilities Other liabilities Equity Total liabilities and equity INCOME STATEMENT DATA: Revenues Operating Income Net Income Poseidon's revolving credit facility December 31, 2019 2018 $ $ $ $ 44,129 $ 321,752 16,739 382,620 20,081 252,331 110,208 $ $ 382,620 $ 34,005 346,864 15,469 396,338 18,897 250,742 126,699 396,338 Year Ended December 31, 2019 2018 2017 $ $ $ 209,674 155,920 139,436 $ $ $ 180,056 129,160 115,669 $ $ $ 191,078 139,604 134,479 Borrowings under Poseidon’s revolving credit facilities, which was amended and restated in March 2019, are primarily used to fund spending on capital projects. The March 2019 credit facility is non-recourse to Poseidon’s owners and secured by its assets. The March 2019 credit facility contains customary covenants such as restrictions on debt levels, liens, guarantees, mergers, sale of assets and distributions to owners. A breach of any of these covenants could result in acceleration of the maturity date of Poseidon’s debt. Poseidon was in compliance with the terms of its credit agreement for all periods presented in these consolidated financial statements. 10. Intangible Assets, Goodwill and Other Assets Intangible Assets The following table reflects the components of intangible assets being amortized at December 31, 2019 and 2018: December 31, 2019 December 31, 2018 Weighted Amortization Period in Years Gross Carrying Amount Accumulated Amortization Carrying Value Intangible associated with lease (1) Marine contract intangibles Offshore pipeline contract intangibles Other Total 15 5 19 9 — 27,800 158,101 34,291 $220,192 — 23,033 36,752 21,480 $ 81,265 Gross Carrying Amount 13,260 27,800 — 4,767 121,349 158,101 12,811 $138,927 31,747 $230,908 Accumulated Amortization Carrying Value 5,407 17,593 28,431 16,875 $ 68,306 7,853 10,207 129,670 14,872 $162,602 (1) Intangible assets associated with a lease in our onshore facilities & transportation segment are now classified as part of our Right or Use Assets, net as part of our adoption of ASC 842 as of January 1, 2019 (Note 4). The marine contract intangible primarily relates to the contracts we assumed in the purchase of the M/T American Phoenix in November 2014. F-25 Table of Contents The offshore pipeline contract intangibles relate to customer contracts surrounding certain transportation agreements with producers in the Lucius production area in Southeast Keathley Canyon, which support our SEKCO pipeline. We are recording amortization of our intangible assets based on the period over which the asset is expected to contribute to our future cash flows. All of our current intangible assets are being amortized on a straight-line basis. Amortization expense on intangible assets was $18.7 million, $21.8 million and $23.6 million for the years ended December 31, 2019, 2018 and 2017, respectively. The following table reflects our estimated amortization expense for each of the five subsequent fiscal years: Marine contract intangibles Offshore pipeline contract intangibles Other Total Goodwill 2020 2021 2022 2023 2024 4,538 8,321 2,453 37 8,321 2,168 35 8,321 2,010 34 8,321 1,621 $ 15,312 $ 10,526 $ 10,366 $ 9,976 $ 33 8,321 1,421 9,775 The carrying amount of goodwill in our sodium minerals and sulfur services segment was $301.9 million in December 31, 2019 and 2018. During 2018, we recognized a goodwill impairment loss of $23.1 million related to our onshore facilities and transportation segment during the period. The goodwill impairment was specifically related to our supply and logistics reporting unit, that primarily includes our legacy crude oil and refined products marketing and trucking businesses. Due to our efforts to rightsize these businesses, along with the volatility of crude oil prices and the impact this volatility has on the availability of crude oil and heavy refined products for us to market, the fair value of the reporting unit was determined to be lower than the carrying value of the reporting unit, including goodwill. The fair value was derived using a discounted cash flow present value technique. Other Assets Other assets consisted of the following: CO2 volumetric production payments, net of amortization Deferred marine charges, net (1) Contract assets (2) Other deferred costs Other assets, net of amortization December 31, 2019 2018 — $ 24,098 54,232 15,755 890 28,175 72,241 20,401 94,085 $ 121,707 $ $ (1) See discussion of deferred charges on marine transportation assets in the Summary of Accounting Policies (Note 2) (2) See Revenue Recognition (Note 3) for discussion on the circumstances that result in the recognition of contract assets. The CO2 assets were being amortized on a units-of-production method and became fully amortized as of December 31, 2019. F-26 Table of Contents 11. Debt At December 31, 2019 and 2018, our obligations under debt arrangements consisted of the following: Senior secured credit facility 6.750% senior unsecured notes 6.000% senior unsecured notes 5.625% senior unsecured notes 6.500% senior unsecured notes 6.250% senior unsecured notes Total long-term debt December 31, 2019 December 31, 2018 Unamortized Discount and Debt Issuance Costs (1) Principal Net Value Principal Unamortized Discount and Debt Issuance Costs (1) Net Value $ 959,300 750,000 $ — $ 959,300 740,651 9,349 $ 970,100 750,000 $ — $ 970,100 737,237 12,763 400,000 350,000 550,000 450,000 $3,459,300 $ $ 3,557 3,923 7,020 6,214 30,063 396,443 346,077 542,980 400,000 350,000 550,000 443,786 $ 3,429,237 450,000 $3,470,100 4,624 4,820 8,241 7,189 $ 37,637 395,376 345,180 541,759 442,811 $3,432,463 (1) Unamortized debt issuance costs associated with our senior secured credit facility (included in Other Long Term Assets on the Consolidated Balance Sheet) were $7.6 million and $10.8 million as of December 31, 2019 and December 31, 2018, respectively. Senior Secured Credit Facility The key terms for rates under our $1.7 billion senior secured credit facility, which are dependent on our leverage ratio (as defined in the credit agreement), are as follows: • • The interest rate on borrowings may be based on an alternate base rate or a Eurodollar rate, at our option. The alternate base rate is equal to the sum of (a) the greatest of (i) the prime rate as established by the administrative agent for the credit facility, (ii) the federal funds effective rate plus 0.5% of 1% and (iii) the LIBOR rate for a one-month maturity plus 1% and (b) the applicable margin. The Eurodollar rate is equal to the sum of (a) the LIBOR rate for the applicable interest period multiplied by the statutory reserve rate and (b) the applicable margin. The applicable margin varies from 1.50% to 3.00% on Eurodollar borrowings and from 0.50% to 2.00% on alternate base rate borrowings, depending on our leverage ratio. Our leverage ratio is recalculated quarterly and in connection with each material acquisition. At December 31, 2019, the applicable margins on our borrowings were 1.50% for alternate base rate borrowings and 2.50% for Eurodollar rate borrowings. Letter of credit fees range from 1.50% to 3.00% based on our leverage ratio as computed under the credit facility. The rate can fluctuate quarterly. At December 31, 2019, our letter of credit rate was 2.50%. • We pay a commitment fee on the unused portion of the $1.7 billion maximum facility amount. The commitment fee on the unused committed amount will range from 0.25% to 0.50% per annum depending on our leverage ratio (0.50% at December 31, 2019). • Our credit facility contains a $300 million accordion feature, giving us the ability to expand the size of the facility up to $2.0 billion for acquisitions or growth projects, subject to lender consent. Our credit facility contains customary covenants (affirmative, negative and financial) that could limit the manner in which we may conduct our business. As defined in our credit facility, we are required to meet three primary financial metrics— a maximum leverage ratio, a maximum senior secured leverage ratio and a minimum interest coverage ratio. Our credit agreement provides for the temporary inclusion of certain pro forma adjustments to the calculations of the required ratios following material acquisitions. In general, our leverage ratio calculation compares our consolidated funded debt (including outstanding notes we have issued) to EBITDA (as defined and adjusted in accordance with the credit facility) and cannot exceed 5.50 to 1.00 as of December 31, 2019. Our senior secured leverage ratio excludes outstanding debt under senior unsecured notes and cannot exceed 3.75 to 1.00. Our interest coverage ratio calculation compares EBITDA (as defined and adjusted in accordance with the credit facility) to interest expense and must be greater than 3.00 to 1.00 (2.75 to 1.00 during an acquisition period). At December 31, 2019, we had $959.3 million borrowed under our credit facility, with $4.3 million of the borrowed amount designated as a loan under the inventory sublimit. Our credit agreement allows up to $100 million of the capacity to be used for letters of credit, of which $1.1 million was outstanding at December 31, 2019. Due to the revolving nature of loans under our credit facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date of May 9, 2022. The total amount available for borrowings under our credit facility at December 31, 2019 was $739.6 million, subject to compliance with covenants. Our credit facility does not include a “borrowing base” limitation except with respect to our inventory loans. F-27 Table of Contents Senior Unsecured Notes On February 8, 2013 , we issued $350 million of aggregate principal amount of 5.75% senior unsecured notes due February 15, 2021 (the "2021 Notes"). On December 11, 2017, $204.8 million of these notes were validly tendered and repaid upon the issuance of our $450 million unsecured notes issued on December 11, 2017 as discussed below. A total loss of approximately $6.2 million for the tender is recorded to "Other income/(expense), net" in our Consolidated Statements of Operations as of December 31, 2017. On February 15, 2018, we redeemed our remaining 2021 Notes in full at a redemption price of 101.438% of the principal amount, plus accrued and unpaid interest up to, but not including, the redemption date. We incurred a total loss of approximately $3.3 million relating to the extinguishment of those notes (including the write-off of the related unamortized debt issuance costs), which loss is recorded as "Other income/(expense), net" in our Consolidated Statements of Operations for the year ended December 31, 2018. On May 15, 2014, we issued $350 million in aggregate principal amount of 5.625% senior unsecured notes due December 15, 2024 (the "2024 Notes"). Our 2024 Notes were sold at face value. Interest payments are due on June 15 and December 15 of each year with the initial interest payment due December 15, 2014. Our 2024 Notes mature on June 15, 2024. The net proceeds were used to repay borrowings under our credit facility and for general partnership purposes. On May 21, 2015, we issued $400 million in aggregate principal amount of 6.00% senior unsecured notes due May 15, 2023 (the "2023 Notes"). Interest payments are due on May 15 and November 15 of each year with the initial interest payment due November 15, 2015. Our 2023 Notes mature on May 15, 2023. We used a portion of the proceeds from those notes to effectively redeem all of our outstanding $350 million, 7.875% senior unsecured notes due 2018, using a combination of public tender offer and our redemption rights relating to those notes. On July 23, 2015, we issued $750 million in aggregate principal amount of 6.75% senior unsecured notes due August 1, 2022 (the "2022 Notes"). Interest payments are due on February 1 and August 1 of each year with the initial interest payment due February 1, 2016. Our 2022 Notes mature on August 1, 2022. That issuance generated net proceeds of $728.6 million net of issuance discount and underwriting fees. The net proceeds were used to fund a portion of the purchase price for our Enterprise acquisition. On August 14, 2017, we issued $550 million in aggregate principal amount of 6.50% senior unsecured notes due October 1, 2025 (the "2025 Notes"). Interest payments are due April 1 and October 1 of each year with the initial interest payment due April 1, 2018. That issuance generated net proceeds of $540.1 million, net of issuance costs incurred. Our 2025 Notes mature on October 1, 2025. The net proceeds were used to fund a portion of the purchase price for our acquisition of our Alkali Business. On December 11, 2017, we issued $450 million in aggregate principal amount of 6.25% senior unsecured notes due May 15, 2026 (the "2026 Notes"). Interest payments are due May 15 and November 15 of each year with the initial interest payment due May 15, 2018. That issuance generated net proceeds of $441.8 million, net of issuance costs incurred. We used $204.8 million of the net proceeds to redeem the portion of the 5.75% senior unsecured notes due February 15, 2021 (the "2021 Notes") that were validly tendered and the remaining net proceeds to repay a portion of the borrowings outstanding under our revolving credit facility. 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. Redemption right beginning on 2022 Notes(1) August 1, 2018 2023 Notes 2024 Notes 2025 Notes 2026 Notes May 15, 2018 June 15, 2019 October 1, 2020 February 15, 2021 Redemption of up to 35% of the principal amount of notes with the proceeds of an equity offering permitted prior to August 1, 2018 (1) Refer to Note 26 for discussion surrounding our tender and redemption of our 2022 Notes, along with the issuance of our 2028 Notes during the first quarter of 2020. October 1, 2020 June 15, 2019 May 15, 2018 February 15, 2021 Guarantees of our 2022, 2023, 2024, 2025 and 2026 Notes will be released under certain circumstances, including (i) in connection with any sale or other disposition of (a) all or substantially all of the properties or assets of a guarantor (including by way of merger or consolidation) or (b) all of the capital stock of such guarantor, in each case, to a person that is not a restricted subsidiary of the Partnership (ii) if the Partnership designates any restricted subsidiary that is a guarantor as an unrestricted subsidiary, (iii) upon legal defeasance, covenant defeasance or satisfaction and discharge of the applicable F-28 Table of Contents indenture, (iv) upon the liquidation or dissolution of such guarantor, or (v) at such time as such guarantor ceases to guarantee any other indebtedness of either of the issuers and any other guarantor. Covenants and Compliance Our credit agreement and the indentures governing the senior notes contain cross-default provisions. Our credit documents prohibit distributions on, or purchases or redemptions of, units if any default or event of default is continuing. In addition, those agreements contain various covenants limiting our ability to, among other things: • • • • incur indebtedness if certain financial ratios are not maintained; grant liens; engage in sale-leaseback transactions; and sell substantially all of our assets or enter into a merger or consolidation. A default under our credit documents would permit the lenders thereunder to accelerate the maturity of the outstanding debt. As long as we are in compliance with our credit facility, our ability to make distributions of “available cash” is not restricted. As of December 31, 2019, we were in compliance with the financial covenants contained in our credit facility and indentures. 12. Partners’ Capital, Mezzanine Equity and Distributions At December 31, 2019, our outstanding equity consisted of 122,539,221 Class A common units and 39,997 Class B common units. The Class A units are traditional common units in us. The Class B units are identical to the Class A units and, accordingly, have voting and distribution rights equivalent to those of the Class A units, and, in addition, the Class B units have the right to elect all of our board of directors and are convertible into Class A units under certain circumstances, subject to certain exceptions. At December 31, 2019, we had 25,336,778 Class A Convertible Preferred Units outstanding, which are discussed below in further detail. Distributions Generally, we will distribute 100% of our available cash (as defined by our partnership agreement) 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. F-29 Table of Contents We paid common unitholders distributions in 2020, 2019 and 2018 as follows: Distribution For 2017 4th Quarter 2018 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter 2019 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Date Paid Per Unit Amount Total Amount February 14, 2018 $ 0.5100 May 15, 2018 $ August 14, 2018 $ November 14, 2018 $ February 14, 2019 $ May 15, 2019 $ August 14, 2019 $ November 14, 2019 $ February 14, 2020 $ 0.5200 0.5300 0.5400 0.5500 0.5500 0.5500 0.5500 0.5500 $ $ $ $ $ $ $ $ $ 62,515 63,741 64,967 66,193 67,419 67,419 67,419 67,419 67,419 Equity Issuances and Contributions Our partnership agreement authorizes our general partner to cause us to issue additional limited partner interests and other equity securities, the proceeds from which could be used to provide additional funds for acquisitions or other needs. On March 24, 2017, we issued 4,600,000 Class A common units in a public offering at a price of $30.65 per unit, which included the exercise by the underwriters of an option to purchase up to 600,000 additional common units from us. We received proceeds, net of offering costs, of approximately $140.5 million from that offering. The new common units issued in 2017 to the public for cash were as follows: Period March 2017 Purchaser of Common Units Public Units Gross Unit Price Issuance Value Costs Net Proceeds 4,600 $ 30.65 $ 140,990 $ (477) $ 140,513 Class A Convertible Preferred Units On September 1, 2017, we sold $750 million of Class A convertible preferred units ("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 preferred units. Our 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 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 preferred units. Each of our preferred units accumulate quarterly distribution amounts in arrears at an annual rate of 8.75% (or $2.9496), yielding a quarterly rate of 2.1875% (or $0.7374), subject to certain adjustments. With respect to any quarter ending on or prior to March 1, 2019, we had the option to pay to the holders of our preferred units the applicable distribution amount in cash, preferred units, or any combination thereof. If we elected to pay all or any portion of a quarterly distribution amount in preferred units, the number of such preferred units would equal the product of (i) the number of then outstanding preferred units and (ii) the quarterly rate. We elected to pay all distributions from inception through March 1, 2019 with additional preferred units. For the quarter ended March 31, 2019, we paid a portion of our distribution in cash, and a portion in preferred units. For each quarter ending after March 1, 2019, we paid all distribution amounts in respect of our preferred units in cash. From time to time after September 1, 2020, we will have the right to cause the conversion of all or a portion of outstanding preferred units into our common units, subject to certain conditions; provided, however, that we will not be permitted to convert more than 7,416,498 of our preferred units in any consecutive twelve-month period. At any time after F-30 Table of Contents September 1, 2020, if we have fewer than 592,768 of our preferred units outstanding, we will have the right to convert each outstanding preferred unit into our common units at a conversion rate equal to the greater of (i) the then-applicable conversion rate and (ii) the quotient of (a) the Issue Price and (b) 95% of the volume-weighted average price of our common units for the 30-trading day period ending prior to the date that we notify the holders of our outstanding preferred units of such conversion. Upon certain events involving certain changes of control in which more than 90% of the consideration payable to the holders of our common units is payable in cash, our preferred units will automatically convert into common units at a conversion ratio equal to the greater of (a) the then applicable conversion rate and (b) the quotient of (i) the product of (A) the sum of (1) the Issue Price and (2) any accrued and accumulated but unpaid distributions on our preferred units, and (B) a premium factor (ranging from 115% to 101% depending on when such transaction occurs) plus a prorated portion of unpaid partial distributions, and (ii) the volume weighted average price of the common units for the 30 trading days prior to the execution of definitive documentation relating to such change of control. In connection with other change of control events that do not meet the 90% cash consideration threshold described above, each holder of our preferred units may elect to (a) convert all of its preferred units into our common units at the then applicable conversion rate, (b) if we are not the surviving entity (or if we are the surviving entity, but our common units will cease to be listed), require us to use commercially reasonable efforts to cause the surviving entity in any such transaction to issue a substantially equivalent security (or if we are unable to cause such substantially equivalent securities to be issued, to convert its preferred units into common units in accordance with clause (a) above or exchanged in accordance with clause (d) below or convert at a specified conversion rate), (c) if we are the surviving entity, continue to hold our preferred units or (d) require us to exchange our preferred units for cash or, if we so elect, our common units valued at 95% of the volume-weighted average price of our common units for the 30 consecutive trading days ending on the fifth trading day immediately preceding the closing date of such change of control, at a price per unit equal to the sum of (i) the product of (x) 101% and (y) the Issue Price plus (ii) accrued and accumulated but unpaid distributions and (iii) a prorated portion of unpaid partial distributions. For a period of 30 days following (i) September 1, 2022 and (ii) each subsequent anniversary thereof, the holders of our preferred units may make a one-time election to reset the quarterly distribution amount (a “Rate Reset Election”) to a cash amount per preferred unit equal to the amount that would be payable per quarter if a preferred unit accrued interest on the Issue Price at an annualized rate equal to three-month LIBOR plus 750 basis points; provided, however, that such reset rate shall be equal to 10.75% if (i) such alternative rate is higher than the LIBOR-based rate and (ii) the then market price for our common units is then less than 110% of the Issue Price. To become effective, the Rate Reset Election requires approval of holders of at least a majority of our then outstanding preferred units and such majority must include each of our initial purchasers (or any affiliate to whom they have transferred their preferred units) if such initial purchaser (including its affiliates) holds at least 25% of the then outstanding preferred units. Upon the occurrence of a Rate Reset Election, we may redeem our preferred units for cash, in whole or in part (subject to certain minimum value limitations) for an amount per preferred unit equal to such preferred unit’s liquidation value (equal to the Issue Price plus any accrued and accumulated but unpaid distributions, plus a prorated portion of certain unpaid partial distributions in respect of the immediately preceding quarter and the current quarter) multiplied by (i) 110%, prior to September 1, 2024, and (ii) 105% thereafter. Each holder of our preferred units may elect to convert all or any portion of its preferred units into common units initially on a one-for-one basis (subject to customary adjustments and an adjustment for accrued and accumulated but unpaid distributions and limitations) at any time after September 1, 2019 (or earlier upon a change of control, liquidation, dissolution or winding up), provided that any conversion is for at least $50 million or such lesser amount if such conversion relates to all of a holder’s remaining preferred units or has otherwise been approved by us. If we fail to pay in full any preferred unit distribution amount after March 1, 2019 in respect of any two quarters, whether or not consecutive, then until we pay such distributions in full, we will not be permitted to (a) declare or make any distributions (subject to a limited exceptions for pro rata distributions on our preferred units and parity securities), redemptions or repurchases of any of our limited partner interests that rank junior to or pari passu with our preferred units with respect to rights upon distribution and/or liquidation (including our common units), or (b) issue any such junior or parity securities. If we fail to pay in full any preferred unit distribution after March 1, 2019 in respect of any two quarters, whether or not consecutive, then the preferred unit distribution amount will be reset to a cash amount per preferred unit equal to the amount that would be payable per quarter if a preferred unit accrued interest on the Issue Price at an annualized rate equal to the then-current annualized distribution rate plus 200 basis points until such default is cured. In addition to their right to veto a Rate Reset Election under certain circumstances, we have granted each initial purchaser (including its applicable affiliate transferees) certain rights, including (i) the right to appoint an observer, who shall have the right to attend our board meetings for so long as an initial purchaser (including its affiliates) owns at least $200 million of our preferred units; (ii) the right to purchase up to 50% of any parity securities on substantially the same terms offered to other purchasers for so long as an initial purchaser (including its affiliates) owns at least 11,124,747 of our preferred units, and (iii) the right to appoint two directors to our general partner’s board of directors if (and so long as) we fail to pay in full any three quarterly distribution amounts, whether or not consecutive, attributable to any quarter ending after March 1, 2019. F-31 Table of Contents The Rate Reset Election of these preferred units represents an embedded derivative that must be bifurcated from the related host contract and recorded at fair value on our Consolidated Balance Sheet. See further information in Note 19. The preferred units themselves are classified as mezzanine capital on our Consolidated Balance Sheet. Accounting for the Class A Convertible Preferred Units Our preferred units are considered redeemable securities under GAAP due to the existence of redemption provisions upon a deemed liquidation event which is outside of our control. Therefore, we present them as temporary equity in the mezzanine section of the Consolidated Balance Sheet. The preferred units have been recorded at their issuance date fair value, net of issuance costs. Because our preferred units are not currently redeemable and we do not have plans or expect any events which constitute a change of control in our partnership agreement, we present our preferred units at their initial carrying amount. However, we would be required to adjust that carrying amount if it becomes probable that we would be required to redeem our preferred units. Initial and Subsequent Measurement We initially recognized our preferred units at their issuance date fair value, net of issuance costs. We will not be required to adjust the carrying amount of our preferred units until it becomes probable that they would become redeemable. Once redemption becomes probable, we would adjust the carrying amount of our preferred units to the redemption value over a period of time comprising the date the redemption first becomes probable and the date the units can first be redeemed. As discussed above, a portion of the net proceeds were allocated to the Preferred Distribution Rate Reset Election and recorded in Other long term liabilities on the Consolidated Balance Sheet as described below (as of the inception date): Transaction price, gross Transaction cost to other third parties Transaction price, net Allocation of Net Transaction Price Preferred Units, net Preferred Distribution Rate Reset Election (Note 19) September 1, 2017 750,000 (23,581) 726,419 691,969 34,450 726,419 $ $ Preferred unit distributions are recognized on the date in which they are declared. Paid in kind distributions were declared and issued as follows: Distribution Declared 2017 November 2017 2018 January 2018 April 2018 July 2018 October 2018 2019 January 2019 April 2019 Date Issued Number of Units Total Amount November 14, 2018 February 14, 2018 May 15, 2018 August 14, 2018 November 14, 2018 February 14, 2019 May 15, 2019 162,234 490,252 500,967 511,934 523,132 534,576 364,180 $ $ $ $ $ $ $ 5,469 16,526 16,888 17,257 17,635 18,021 12,277 F-32 Table of Contents We paid the following cash distributions to our preferred unitholders: Distribution For 2019 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Date Paid Per Unit Amount Total Amount May 15, 2019 August 14, 2019 November 14, 2019 February 14, 2020 $ $ $ $ 0.2458 0.7374 0.7374 0.7374 $ $ $ $ 6,138 18,684 18,684 18,684 The following table shows the change in our Class A Convertible Preferred Units from initial measurement at September 1, 2017 to December 31, 2019: December 31, 2016 Issuance of Preferred Units, net Allocation to Preferred Distribution Rate Reset Election (Note 19) Distributions paid-in-kind Allocation of Distributions paid-kind to Preferred Distribution Rate Reset Election (Note 19) Balance as of December 31, 2017 Distributions paid-in-kind Allocation of Distributions paid-kind to Preferred Distribution Rate Reset Election (Note 19) Balance as of December 31, 2018 Distributions paid-in-kind Allocation of Distributions paid-kind to Preferred Distribution Rate Reset Election (Note 19) Balance as of December 31, 2019 Class A Convertible Preferred Units Units $ — $ 22,249,494 — 162,234 — 22,411,728 $ 2,026,294 — 24,438,022 $ 898,756 — 25,336,778 $ — 726,419 (34,450) 5,469 (287) 697,151 68,306 (3,991) 761,466 30,298 (1,649) 790,115 Net income (loss) attributable to common unitholders is reduced by Preferred Unit distributions that accumulated during the period. During 2019, net income attributable to common unitholders was reduced by $74.5 million as a result of distributions that accumulated during the period. Redeemable Noncontrolling Interests On September 23, 2019, we, through a subsidiary, Genesis Alkali Holdings Company, LLC (“Alkali Holdings”), entered into an amended and restated Limited Liability Company Agreement of Alkali Holdings (the "LLC Agreement") and a Securities Purchase Agreement (the "Securities Purchase Agreement") whereby certain investment fund entities affiliated with GSO Capital Partners LP (collectively, the “Sponsor”) purchased $55,000,000 and committed to purchase, during a three-year commitment period, up to a total of $350,000,000 (the “Preferred Commitment”) of preferred units in Alkali Holdings, the entity that holds our trona and trona-based exploring, mining, processing, producing, marketing and selling business, including its Granger facility near Green River, Wyoming. Alkali Holdings will use the net proceeds from the preferred units to fund up to 100% of the anticipated cost of expansion of the Granger facility. As of December 31, 2019, we received cash of $122.9 million for the $130 million of preferred units issued to date net of issuance costs, which was inclusive of our transaction related expenses and one-time commitment fee. The Sponsor has the right to a quarterly distribution equal to 10% per annum on the liquidation preference of each preferred unit. The liquidation preference is defined as one thousand dollars per preferred unit, plus any accrued and unpaid distributions (including as a result of any distributions paid in kind). Distributions are payable quarterly within 45 days after the end of the fiscal quarter. Distributions may be paid in-kind in lieu of cash distributions during the first 36 months following the September 23, 2019 initial closing date. Subsequent to the payment-in-kind period, all distributions must be paid in cash. In addition to the quarterly distributions paid to the Sponsor, Alkali Holdings will distribute all of its distributable cash to the Partnership each quarter, which is equal to all cash and cash equivalents in the operating accounts of Alkali Holdings less cash reserves and a minimum $5 million cash balance to be maintained for working capital needs. F-33 Table of Contents From time to time after we have drawn at least $250 million of our Preferred Commitment, 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 $250 million of our Preferred Commitment, and the Sponsor is not a "defaulting member" under the LLC Agreement, the Sponsor has the right to a make-whole amount on the number of undrawn preferred units. The Sponsor is obligated to purchase a minimum of $250 million of preferred units unless certain customary closing conditions are not satisfied, including the existence of a triggering event or a material uncured breach of the Securities Purchase Agreement by Alkali Holdings. A triggering event would occur if Alkali Holdings fails to pay cash distributions subsequent to the paid-in-kind period, fails to redeem preferred units when required to by a change of control event, or if any preferred units remain outstanding on the six year anniversary date, amongst other events. The preferred units must be redeemed, in whole or in part, following certain change of control events, fundamental changes, or the liquidation, winding up, or dissolution of Alkali Holdings and, as applicable, the Partnership. If such an event were to occur, the preferred units would rank senior to Alkali Holdings common units and any class or series of equity of Alkali Holdings established after the issuance of the preferred units. At any time following the sixth 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, the Sponsor has the right to gain control of the board of Alkali Holdings and effectuate a monetization event using its reasonable good faith efforts to maximize the consideration received to the holders of our common units, including the sale of Alkali Holdings (including all of its equity or assets and all of its equity in its subsidiaries), the proceeds of which would first be used to redeem the preferred units at the Base Preferred Return prior to any distribution to us. Pursuant to the LLC Agreement, the Board of Managers (the "Board") for Alkali Holdings will consist of 5 managers, including 3 designated by the Partnership, 1 designated by the Sponsor, and 1 independent manager. The independent manager is entitled to only attend Board meetings if the Board is required to vote on matters related to a bankruptcy of Alkali Holdings, and is permitted to only vote on such matters. See Note 25 for additional information regarding our non-guarantor subsidiaries. Accounting for Redeemable Noncontrolling Interests Classification The preferred units issued and outstanding are accounted for as a redeemable noncontrolling interest in the mezzanine section on our Consolidated Balance Sheet due to the redemption features for a change of control. Initial and Subsequent Measurement We recorded the preferred units at their issuance date fair value, net of issuance costs. The fair value as of December 31, 2019 represents the carrying amount based on the issued and outstanding preferred units most probable redemption event on the six year anniversary of the closing, which is the predetermined internal rate of return measure accreted using the effective interest method to the redemption value. Net Income Attributable to Genesis Energy, L.P. for the year ended December 31, 2019 includes $2.3 million of adjustments, of which $1.8 million was allocated to the distribution paid in-kind on the outstanding preferred units and $0.5 million was attributable to redemption accretion value adjustments from the closing date to December 31, 2019. We elected to pay distributions for the period ending September 30, 2019 and December 31, 2019 in-kind to our preferred unitholders. These in-kind distributions increase the unitholders liquidation preference on each preferred unit. As of the reporting date, there are no triggering, change of control, early redemption or monetization events that are probable that would require us to revalue the preferred units. If the preferred units were redeemed on the reporting date of December 31, 2019, the redemption amount would be equal to $192.5 million, which would be the multiple of invested capital metric applied to the preferred units outstanding plus the make-whole amount on the undrawn minimum preferred units. F-34 Table of Contents The following table shows the change in our redeemable noncontrolling interests from initial measurement at September 23, 2019 to December 31, 2019: Issuance of Preferred Units Issuance costs Balance as of September 23, 2019 Issuance of preferred units, net of issuance costs Distribution paid-in-kind Redemption accretion Balance as of December 31, 2019 Year Ended December 31 2019 $ $ 55,000 (5,600) 49,400 73,500 1,778 455 125,133 13. Net Income (Loss) Per Common Unit Basic net income per common unit is computed by dividing Net Income Attributable to Genesis Energy, L.P., after considering income attributable to our Class A preferred unitholders, by the weighted average number of common units outstanding. The dilutive effect of the Class A Convertible Preferred units is calculated using the if-converted method. Under the if-converted method, the Class A Preferred units are assumed to be converted at the beginning of the period (beginning with their respective issuance date), and the resulting common units are included in the denominator of the diluted net income per common unit calculation for the period being presented. Distributions declared in the period and undeclared distributions that accumulated during the period are added back to the numerator for purposes of the if-converted calculation. For the years ended December 31, 2019, 2018, and 2017, the effect of the assumed conversion of our Class A convertible preferred units was anti-dilutive and was not included in the computation of diluted earnings per unit. The following table reconciles net income (loss) and weighted average units used in computing basic and diluted net income (loss) per common unit (in thousands, except per unit amounts): Net Income (Loss) Attributable to Genesis Energy L.P. Less: Accumulated distributions attributable to Class A Convertible Preferred Units Net Income (Loss) Available to Common Unitholders Weighted Average Outstanding Units Basic and Diluted Net Income (Loss) per Common Unit Year Ended December 31 2019 2018 2017 95,999 $ (6,075) $ 82,647 (74,467) 21,532 $ (69,801) (75,876) $ (21,995) 60,652 122,579 122,579 121,546 0.18 $ (0.62) $ 0.50 $ $ $ 14. Business Segment Information We currently manage our businesses through four divisions that constitute our reportable segments: • • Offshore pipeline transportation – offshore transportation of crude oil and natural gas in the Gulf of Mexico; Sodium minerals and sulfur services – trona and trona-based exploring, mining, processing, producing, marketing and selling activities, as well as processing of high sulfur (or “sour”) gas streams for refineries to remove the sulfur, and selling the related by-product, NaHS; F-35 Table of Contents • Onshore facilities and transportation – terminaling, blending, storing, marketing, and transporting crude oil, petroleum products (primarily fuel oil, asphalt, and other heavy refined products), and CO2; and • Marine transportation – marine transportation to provide waterborne transportation of petroleum products and crude oil throughout North America. Substantially all of our revenues are derived from, and substantially all of our assets are located in, the United States. We define Segment Margin as revenues less product costs, operating expenses (excluding non-cash charges, such as depreciation, depletion, and amortization), and segment general and administrative expenses, plus our equity in distributable cash generated by our equity investees. In addition, our Segment Margin definition excludes the non-cash effects of our long- term incentive compensation plan and includes the non-income portion of payments received under direct financing leases. 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. Segment information for each year presented below is as follows: Offshore Pipeline Transportation Sodium Minerals & Sulfur Services Onshore Facilities & Transportation Marine Transportation Total Year Ended December 31, 2019 Segment Margin (a) Capital expenditures (b) Revenues: External customers Intersegment (c) $ $ $ Total revenues of reportable segments $ Year Ended December 31, 2018 Segment Margin (a) Capital expenditures (b) Revenues: $ $ 320,023 17,809 $ $ 223,908 107,837 318,116 — 318,116 $ 1,113,623 (7,636) $ 1,105,987 285,014 4,703 $ $ 260,488 74,712 $ $ $ $ $ $ 111,412 6,576 824,148 (3,076) 821,072 119,918 51,110 External customers Intersegment (c) Total revenues of reportable segments $ Year Ended December 31, 2017 Segment Margin (a) Capital expenditures (b) Revenues: $ $ $ 284,544 — 284,544 $ 1,181,578 (7,144) $ 1,174,434 $ 1,240,382 (6,527) $ 1,233,855 317,540 8,815 130,333 $ $ 1,354,469 $ $ 96,376 149,123 External customers Intersegment (c) $ Total revenues of reportable segments $ 319,455 (1,216) 318,239 $ $ 470,789 (8,167) 462,622 $ 1,044,083 (1,854) $ 1,042,229 Total assets by reportable segment were as follows: $ $ $ $ $ $ $ $ $ $ $ $ 57,919 40,820 $ $ 713,262 173,042 224,933 10,712 235,645 $ 2,480,820 — $ $ 2,480,820 47,338 30,868 $ $ 712,758 161,393 206,266 13,671 219,937 $ 2,912,770 — $ $ 2,912,770 50,294 68,414 594,543 $ $ 1,580,821 194,050 11,237 205,287 $ 2,028,377 — $ $ 2,028,377 Offshore pipeline transportation Sodium minerals and sulfur services Onshore facilities and transportation Marine transportation Other assets Total consolidated assets December 31, 2019 $ 2,306,946 2,019,905 December 31, 2018 $ 2,359,013 1,844,845 December 31, 2017 $ 2,486,803 1,848,188 1,457,190 1,431,910 1,927,976 772,383 41,217 $ 6,597,641 800,243 43,060 $ 6,479,071 824,777 49,737 $ 7,137,481 F-36 Table of Contents (a) A reconciliation of total Segment Margin to net income (loss) attributable to Genesis Energy, L.P. for each year is presented below. (b) Capital expenditures include maintenance and growth capital expenditures, such as fixed asset additions (including enhancements to existing facilities and construction of growth projects) as well as acquisitions of businesses and contributions to equity investees related to same. In addition to construction of growth projects, capital spending in our sodium minerals and sulfur services segment included $1.3 billion during the year ended December 31, 2017 related to the acquisition of our Alkali Business. (c) Intersegment sales were conducted under terms that we believe were no more or less favorable than then-existing market conditions. Reconciliation of total Segment Margin to net income (loss) attributable to Genesis Energy, L.P.: Total Segment Margin Corporate general and administrative expenses Depreciation, depletion, amortization and accretion Interest expense Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income (1) Non-cash items not included in Segment Margin Cash payments from direct financing leases in excess of earnings Loss on extinguishment of debt Differences in timing of cash receipts for certain contractual arrangements (2) Gain on sales of assets Other, net Non-cash provision for leased items no longer in use Income tax (expense) benefit Redeemable noncontrolling interest redemption value adjustments(3) Impairment expense Net income (loss) attributable to Genesis Energy, L.P. $ Year Ended December 31 2019 $ 713,262 (52,755) (308,115) (219,440) 2018 $ 712,758 (64,683) (317,186) (229,191) 2017 $ 594,543 (60,029) (262,021) (176,762) (20,847) (14,642) (8,421) — 8,478 — — 1,367 (655) (2,233) — 95,999 (28,088) 9,698 (7,633) (3,339) 6,629 42,264 — 476 (1,498) — (126,282) $ (6,075) $ (31,852) (14,305) (6,921) (6,242) 17,540 40,311 (2,985) (12,589) 3,959 — — 82,647 (1) Includes distributions attributable to the period and received during or promptly following such period. (2) Includes 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. (3) Includes distributions paid in kind attributable to the period and accretion on the redemption feature. F-37 Table of Contents 15. Transactions with Related Parties Transactions with related parties were as follows: Year Ended December 31, 2019 2018 2017 Revenues: Sales of CO2 to Sandhill Group, LLC (1) Revenues from services and fees to Poseidon Oil Pipeline Company, LLC (2) Revenues from product sales to ANSAC $ — $ 1,233 $ 12,669 367,133 12,557 373,606 2,820 12,357 124,536 Expenses: Amounts paid to our CEO in connection with the use of his aircraft Charges for products purchased from Poseidon Oil Pipeline Company, LLC (2) Charges for services from ANSAC $ $ 660 975 4,446 $ 660 994 5,284 660 986 2,242 (1) We owned a 50% interest in Sandhill Group, LLC which was sold in the third quarter of 2018. (2) We own a 64% interest in Poseidon Oil Pipeline Company, LLC. Our CEO, Mr. Sims, owns an aircraft which is used by us for business purposes in the course of operations. We pay Mr. Sims a fixed monthly fee and reimburse the aircraft management company for costs related to our usage of the aircraft, including fuel and the actual out-of-pocket costs. Based on current market rates for chartering of private aircraft under long- term, priority arrangements with industry recognized chartering companies, we believe that the terms of this arrangement are no worse than what we could have expected to obtain in an arms-length transaction. Transactions with Unconsolidated Affiliates Poseidon We provide management, administrative and pipeline operator services to Poseidon under an Operation and Management Agreement . Currently, that agreement renews automatically annually unless terminated by either party (as defined in the agreement). Our revenues for the years ended December 31, 2019, 2018 and 2017 reflect $8.9 million, $8.6 million and $8.4 million, respectively, of fees we earned through the provision of services under that agreement. At December 31, 2019, and 2018, Poseidon Oil Pipeline Company, LLC owed us $2.4 million for services rendered. ANSAC We (through a subsidiary of our Alkali Business) are a member of the American Natural Soda Ash Corp. (ANSAC), an organization whose purpose is promoting and increasing the use and sale of natural soda ash and other refined or processed sodium products produced in the U.S. and consumed in specified countries outside of the U.S. Members sell products to ANSAC to satisfy ANSAC’s sales commitments to its customers. ANSAC passes its costs through to its members using a pro rata calculation based on sales. Those costs include sales and marketing, employees, office supplies, professional fees, travel, rent, and certain other costs. Those transactions do not necessarily represent arm's length transactions and may not represent all costs we would otherwise incur if we operated the Alkali Business on a stand-alone basis. We also benefit from favorable shipping rates for our direct exports when using ANSAC to arrange for ocean transport. ANSAC is considered a variable interest entity (VIE) as we do experience certain risks and rewards from our relationship with them. As we do not exercise control over ANSAC and are not considered its primary beneficiary, we do not consolidate ANSAC. The ANSAC membership agreement provides that in the event an ANSAC member exits or the ANSAC cooperative is dissolved, the exiting members are obligated for their respective portion of the residual net assets or deficit of the cooperative. As of December 31, 2019, such amount is not estimable. Net sales to ANSAC were $367.1 million, $373.6 million and $124.5 million for the years ended December 31, 2019, 2018 and 2017. The costs charged to us by ANSAC, included in operating costs, were $4.4 million, $5.3 million and $2.2 million for the years ended December 31, 2019, 2018 and 2017. The 2017 period includes net sales and costs from September 1, 2017 (our acquisition date) to December 31, 2017. F-38 Table of Contents As of December 31, 2019 and 2018, our receivables from and payables to ANSAC were: Receivables: ANSAC Payables: ANSAC December 31 December 31 2019 2018 $ $ 68,075 2,103 $ $ 60,594 815 16. Supplemental Cash Flow Information The following table provides information regarding the net changes in components of operating assets and liabilities: (Increase) decrease in: Accounts receivable Inventories Deferred charges Other current assets Increase (decrease) in: Accounts payable Accrued liabilities Net changes in components of operating assets and liabilities Year Ended December 31, 2019 2018 2017 $ $ (80,126) $ 7,659 4,093 (4,874) $ 130,573 20,963 (5,826) 9,337 (140,948) 49,055 (3,622) (410) 81,915 (79,765) (71,098) $ (130,991) (26,208) (2,152) $ 97,569 8,512 10,156 Payments of interest and commitment fees were $212.4 million, $228.3 million and $168.3 million during the years ended December 31, 2019, 2018 and 2017, respectively. We capitalized interest of $3.7 million, $3.4 million and $15.0 million during the years ended December 31, 2019, 2018 and 2017. During the years ended December 31, 2019, 2018 and 2017, we paid taxes of $0.8 million, $0.2 million and $1.0 million. At December 31, 2019, 2018 and 2017, we had incurred liabilities for fixed and intangible asset additions totaling $22.6 million, $9.4 million and $39.7 million, respectively, which had not been paid at the end of the year. Therefore, these amounts were not included in the caption “Payments to acquire fixed and intangible assets” under Cash Flows from Investing Activities in the Consolidated Statements of Cash Flows. 17. Equity-Based Compensation Plans 2010 Long Term Incentive Plan In 2010, we adopted the 2010 Long-Term Incentive Plan (the “2010 Plan”). The 2010 Plan provides for the awards of phantom units and distribution equivalent rights to members of our board of directors and employees who provide services to us. Phantom units are notional units representing unfunded and unsecured promises to pay to the participant a specified amount of cash based on the market value of our common units should specified vesting requirements be met. Distribution equivalent rights (“DERs”) are tandem rights to receive on a quarterly basis a cash amount per phantom unit equal to the amount of cash distributions paid per common unit. The 2010 Plan is administered by the Governance, Compensation and Business Development Committee (the “G&C Committee”) of our board of directors. The G&C Committee (at its discretion) designates participants in the 2010 Plan, determines the types of awards to grant to participants, determines the number of units to be covered by any award, and determines the conditions and terms of any award including vesting, settlement and forfeiture conditions. The compensation cost associated with the phantom units is re-measured each reporting period based on the market value of our common units, and is recognized over the vesting period. The liability recorded for the estimated amount to be paid to the participants under the 2010 Plan is adjusted to recognize changes in the estimated compensation cost and F-39 Table of Contents vesting. Management’s estimates of the fair value of these awards granted in 2019 are adjusted for assumptions about expected forfeitures of units prior to vesting. For our performance-based awards, our fair value estimates are weighted based on probabilities for each performance condition applicable to the award. During 2019, we granted 29,606 phantom units with tandem DERs at a weighted average grant fair value of $21.28 per unit. During 2018, we granted 28,484 phantom units with tandem DERs at a weighted average grant date fair value of $22.12 per unit. During 2017, we granted 297,214 phantom units with tandem DERs at a weighted average grant date fair value of $32.37 per unit. The phantom units granted during 2019 and 2018 were made only to directors. Awards to management and other key employees during 2019 and 2018 were made under the 2018 LTIP plan, and were non-equity based awards. The phantom units granted during 2017 were both service-based and performance-based awards. The service-based awards vest on the third anniversary of the date of grant. Performance-based phantom unit awards granted in 2017 will vest on the third anniversary of issuance, in an amount ranging from 0% to 150% of the targeted number of phantom units, if certain quarterly cash distribution per common unit targets are achieved in the fourth quarter of 2020. If the quarterly cash distribution per common unit is below the threshold target, all of the performance-based phantom units granted will be forfeited. A summary of our phantom unit activity for our service-based and performance-based awards is set forth below: Service-Based Awards Performance-Based Awards Number of Phantom Units Average Grant Date Fair Value Total Value (in thousands) Number of Phantom Units Average Grant Date Fair Value Total Value (in thousands) Unvested at December 31, 2018 195,939 $ 30.40 $ 5,958 Granted Forfeited Settled Unvested at December 31, 2019 29,606 $ (1,098) $ (76,370) $ 148,077 $ 21.28 32.43 31.79 27.85 $ 630 (36) (2,428) 4,124 378,006 $ — $ (1,653) $ (213,582) $ 162,771 $ 31.09 $ 11,754 — 32.43 30.37 32.02 $ — (54) (6,486) 5,214 At December 31, 2019, we estimated the unrecognized compensation cost of our phantom awards to be approximately $0.2 million to be recognized over a weighted average period of approximately 0.3 years. We recorded a charge of $1.8 million and $2.1 million to compensation expense for the years ended December 31, 2019 and 2018, respectively. Our liability for these awards totaled $2.8 million and $3.3 million at December 31, 2019 and 2018, respectively. Equity-Based Compensation Plan Expense Equity-based compensation expense during the three years ended December 31, 2019 was as follows: Consolidated Statement of Operations Onshore facilities and transportation operating costs Marine transportation operating costs Sodium minerals and sulfur services operating costs Offshore pipeline operating costs General and administrative expenses Total Expense Related to Equity-Based Compensation Plans 2019 2018 2017 $ $ 250 173 140 269 140 183 112 297 1,087 $ 1,919 1,239 $ 1,971 $ (1,137) (483) (533) (152) (2,272) $ (4,577) F-40 Table of Contents 18. Major Customers and Credit Risk Due to the nature of our onshore facilities and transportation operations, a disproportionate percentage of our trade receivables constitute obligations of refiners, large crude oil producers and integrated oil companies. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers could be affected by similar changes in economic, industry or other conditions. However, we believe that the credit risk posed by this industry concentration is offset by the creditworthiness of our customer base. Our portfolio of accounts receivable is comprised in large part of accounts owed by integrated and large independent energy companies with stable payment histories. The credit risk related to contracts which are traded on the NYMEX is limited due to daily margin requirements and other NYMEX requirements. We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits, collateral requirements and rights of offset. Letters of credit, prepayments and guarantees are also utilized to limit credit risk to ensure that our established credit criteria are met. In 2019 and 2018 our largest customer was ANSAC, which accounted for 15% and 13% of total consolidated revenues, respectively. As discussed in Note 15, we are a member of ANSAC, an organization whose purpose is promoting and increasing the use and sale of natural soda ash and other refined or processed sodium products produced in the U.S. and consumed in specified countries outside of the U.S. Members sell products to ANSAC to satisfy ANSAC’s sales commitments to its customers. Given this relationship, a large portion of our soda ash production is sold to ANSAC. As such, a disproportionate amount of our trade receivables and sales in our sodium minerals and sulfur services segment are related to ANSAC. During 2019, 2018 and 2017, Shell Oil Company was one of our largest customers, which accounted for 8%, 11% and 13% of total revenues, respectively. The revenues from Shell Oil Company in all years relate primarily to our onshore facilities and transportation operations. 19. Derivatives Commodity Derivatives We have exposure to commodity price changes related to our inventory and purchase commitments. We utilize derivative instruments (primarily futures and options contracts traded on the NYMEX) to hedge our exposure to commodity prices, primarily of crude oil, fuel oil and petroleum products. Our decision as to whether to designate derivative instruments as fair value hedges for accounting purposes relates to our expectations of the length of time we expect to have the commodity price exposure and our expectations as to whether the derivative contract will qualify as highly effective under accounting guidance in limiting our exposure to commodity price risk. Most of the petroleum products, including fuel oil that we supply cannot be hedged with a high degree of effectiveness with derivative contracts available on the NYMEX; therefore, we do not designate derivative contracts utilized to limit our price risk related to these products as hedges for accounting purposes. Typically we utilize crude oil and other petroleum products futures and option contracts to limit our exposure to the effect of fluctuations in petroleum products prices on the future sale of our inventory or commitments to purchase petroleum products, and we recognize any changes in fair value of the derivative contracts as increases or decreases in our cost of sales. The recognition of changes in fair value of the derivative contracts not designated as hedges for accounting purposes can occur in reporting periods that do not coincide with the recognition of gain or loss on the actual transaction being hedged. Therefore we will, on occasion, report gains or losses in one period that will be partially offset by gains or losses in a future period when the hedged transaction is completed. We have designated certain crude oil futures contracts as hedges of crude oil inventory due to our expectation that these contracts will be highly effective in hedging our exposure to fluctuations in crude oil prices during the period that we expect to hold that inventory. We account for these derivative instruments as fair value hedges under the accounting guidance. Changes in the fair value of these derivative instruments designated as fair value hedges are used to offset related changes in the fair value of the hedged crude oil inventory. Any hedge ineffectiveness in these fair value hedges and any amounts excluded from effectiveness testing are recorded as a gain or loss in the Consolidated Statement of Operations. In accordance with NYMEX requirements, we fund the margin associated with our loss positions on commodity derivative contracts traded on the NYMEX. The amount of the margin is adjusted daily based on the fair value of the commodity contracts. The margin requirements are intended to mitigate a party’s exposure to market volatility and the associated contracting party risk. We offset fair value amounts recorded for our NYMEX derivative contracts against margin funding as required by the NYMEX in Current Assets - Other in our Consolidated Balance Sheets. Additionally, we utilize swap arrangements. Our Alkali Business relies on natural gas to generate heat and electricity for operations. We use a combination of commodity price swap contracts and future purchase contracts to manage our exposure F-41 Table of Contents to fluctuations in natural gas prices. The swap contracts fix the basis differential between NYMEX Henry Hub and NW Rocky Mountain posted prices. We do not designate these contracts as hedges for accounting purposes. We recognize any changes in fair value of the derivative contracts as increases or decreases in our operating costs. At December 31, 2019, we had the following outstanding derivative commodity contracts that were entered into to economically hedge inventory or fixed price purchase commitments. Designated as hedges under accounting rules: Crude oil futures: Contract volumes (1,000 bbls) Weighted average contract price per bbl Not qualifying or not designated as hedges under accounting rules: Crude oil futures: Contract volumes (1,000 bbls) Weighted average contract price per bbl Natural gas swaps: Contract volumes (10,000 MMBTU) Weighted average price differential per MMBTU Natural gas futures: Contract volumes (10,000 MMBTU) Weighted average contract price per MMBTU Crude oil options: Contract volumes (1,000 bbls) Weighted average premium received/paid Sell (Short) Contracts Buy (Long) Contracts 19 58.57 — — 79 60.25 $ 80 60.25 503 0.38 92 2.27 $ 40 1.03 $ — — 576 2.60 18 0.66 $ $ $ $ $ F-42 Table of Contents Financial Statement Impacts The following table summarizes the accounting treatment and classification of our derivative instruments on our Consolidated Financial Statements. Impact of Unrealized Gains and Losses Consolidated Balance Sheets Consolidated Statements of Operations Derivative Instrument Hedged Risk Designated as hedges under accounting guidance: Crude oil futures contracts (fair value hedge) Volatility in crude oil prices - effect on market value of inventory Derivative is recorded in Other current assets (offset against margin deposits) and offsetting change in fair value of inventory is recorded in Inventories Not qualifying or not designated as hedges under accounting guidance: Commodity hedges consisting of crude oil, heating oil and natural gas futures, forward contracts, swaps and call options Volatility in crude oil, natural gas and petroleum products prices - effect on market value of inventory or purchase commitments Derivative is recorded in Other current assets (offset against margin deposits) or Accrued liabilities Preferred Distribution Rate Reset Election This instrument is not related to a risk, but is rather part of a host contract with the issuance of our Preferred Units Derivative is recorded in Other long-term liabilities Excess, if any, over effective portion of hedge is recorded in Onshore facilities and transportation costs - product costs Effective portion is offset in cost of sales against change in value of inventory being hedged Entire amount of change in fair value of derivative is recorded in Onshore facilities and transportation costs - product costs and Sodium minerals and sulfur services - operating costs Entire amount of change in fair value of derivative is recorded in Other income (expense) Unrealized gains are subtracted from net income and unrealized losses are added to net income in determining cash flows from operating activities. To the extent that we have fair value hedges outstanding, the offsetting change recorded in the fair value of inventory is also eliminated from net income in determining cash flows from operating activities. Changes in margin deposits necessary to fund unrealized losses also affect cash flows from operating activities. F-43 Table of Contents The following tables reflect the estimated fair value gain (loss) position of our derivatives at December 31, 2019 and 2018: Fair Value of Derivative Assets and Liabilities Asset Derivatives: Commodity derivatives—futures and call options (undesignated hedges): Gross amount of recognized assets Gross amount offset in the Consolidated Balance Sheets Net amount of assets presented in the Consolidated Balance Sheets Natural Gas Swap (undesignated hedge) Commodity derivatives—futures and call options (designated hedges): Gross amount of recognized assets Gross amount offset in the Consolidated Balance Sheets Net amount of assets presented in the Consolidated Balance Sheets Liability Derivatives: Preferred Distribution Rate Reset Election (2) Natural Gas Swap (undesignated hedge) Commodity derivatives—futures and call options (undesignated hedges): Gross amount of recognized liabilities Gross amount offset in the Consolidated Balance Sheets Net amount of liabilities presented in the Consolidated Balance Sheets Commodity derivatives—futures and call options (designated hedges): Gross amount of recognized liabilities Gross amount offset in the Consolidated Balance Sheets Net amount of liabilities presented in the Consolidated Balance Sheets Consolidated Balance Sheets Location Current Assets - Other Current Assets - Other Current Assets - Other Current Assets - Other Current Assets - Other Other Long-Term Liabilities (2) Current Liabilities - Accrued Liabilities Current Assets - Other (1) Current Assets - Other (1) Current Assets - Other (1) Current Assets - Other (1) Fair Value December 31, 2019 December 31, 2018 $ $ $ $ $ $ $ $ $ 207 (207) — 1,382 4 (4) — (51,515) — (2,079) 1,064 (1,015) (50) 50 — $ $ $ $ $ $ $ $ $ 3,431 (1,361) 2,070 1,274 469 (44) 425 (40,840) (125) (1,361) 1,361 — (44) 44 — (1) These derivative liabilities have been funded with margin deposits recorded in our Consolidated Balance Sheets under Current Assets - Other. (2) Refer to Note 12 and Note 20 for additional discussion surrounding the Preferred Distribution Rate Reset Election derivative. Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting arrangement exists. Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin. Our exchange-traded derivatives are transacted through brokerage accounts and are subject to margin requirements as established by the respective exchange. On a daily basis, our account equity (consisting of the sum of our cash balance and the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin. As of December 31, 2019, we had a net broker receivable of approximately $0.9 million (consisting of initial margin F-44 Table of Contents of $0.8 million increased by $0.1 million of variation margin). As of December 31, 2018, we had a net broker receivable of approximately $2.2 million (consisting of initial margin of $3.1 million decreased by $0.9 million of variation margin). At December 31, 2019 and December 31, 2018, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings. Preferred Distribution Rate Reset Election A derivative feature embedded in a contract that does not meet the definition of a derivative in its entirety must be bifurcated and accounted for separately if the economic characteristics and risks of the embedded derivative are not clearly and closely related to those of the host contract. For a period of 30 days following (i) September 1, 2022 and (ii) each subsequent anniversary thereof, the holders of our preferred units may make a Rate Reset Election to a cash amount per preferred unit equal to the amount that would be payable per quarter if a preferred unit accrued interest on the Issue Price at an annualized rate equal to three-month LIBOR plus 750 basis points; provided, however, that such reset rate shall be equal to 10.75% if (i) such alternative rate is higher than the LIBOR-based rate and (ii) the then market price for our common units is then less than 110% of the Issue Price. The Rate Reset Election of the preferred units represents an embedded derivative that must be bifurcated from the related host contract and recorded at fair value on our Consolidated Balance Sheet. Corresponding changes in fair value are recognized in Other Income (Expense) in our Consolidated Statement of Operations. At December 31, 2019, the fair value of this embedded derivative was a liability of $51.5 million. See Note 12 for additional information regarding our Class A convertible preferred units and the Rate Reset Election. Effect on Operating Results Commodity derivatives—futures and options: Contracts designated as hedges under accounting guidance Contracts not considered hedges under accounting guidance Total commodity derivatives Natural Gas Swaps Amount of Gain (Loss) Recognized in Income Year Ended December 31 Consolidated Statements of Operations Location 2019 2018 2017 Onshore facilities and transportation product costs Onshore facilities and transportation product costs, sodium minerals and sulfur services operating costs $ (786) $ (544) $ 5,116 (7,790) (8,576) $ 3,914 3,370 $ (1,314) 3,802 $ Sodium minerals and sulfur services operating costs 1,941 $ 1,906 $ — Preferred Distribution Rate Reset Election (Note 20) Other Income (Expense) $ (9,026) $ 8,360 $ (10,472) We have no derivative contracts with credit contingent features. 20. Fair-Value Measurements We classify financial assets and liabilities into the following three levels based on the inputs used to measure fair value: (1) and liabilities; Level 1 fair values are based on observable inputs such as quoted prices in active markets for identical assets (2) and liabilities and are either directly or indirectly observable as of the measurement date; and Level 2 fair values are based on pricing inputs other than quoted prices in active markets for identical assets (3) Level 3 fair values are based on unobservable inputs in which little or no market data exists. As required by fair value accounting guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value requires judgment and may affect the placement of assets and liabilities within the fair value hierarchy levels. F-45 Table of Contents The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2019 and 2018. Recurring Fair Value Measures Commodity derivatives: Assets Liabilities Preferred Distribution Rate Reset Election December 31, 2019 December 31, 2018 Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 $ $ $ 211 $ (2,129) $ — $ 1,382 — $ $ — $ — $ — $ (51,515) $ 3,900 $ (1,405) $ — $ — 1,274 $ (125) $ — — $ (40,840) Rollforward of Level 3 Fair Value Measurements The following table provides a reconciliation of changes in fair value at the beginning and ending balances for our derivatives classified as level 3: Balance as of December 31, 2017 Net gain for the period including earnings Allocation of Distribution Paid-in-kind Balance as of December 31, 2018 Net loss for the period included in earnings Allocation of Distribution Paid-in-kind Balance as of December 31, 2019 $ $ (45,209) 8,360 (3,991) (40,840) (9,026) (1,649) (51,515) Our commodity derivatives include exchange-traded futures and exchange-traded options contracts. The fair value of these exchange-traded derivative contracts is based on unadjusted quoted prices in active markets and is, therefore, included in Level 1 of the fair value hierarchy. The fair value of the swaps contracts was determined using market price quotations and a pricing model. The swap contracts were considered a level 2 input in the fair value hierarchy at December 31, 2019. The fair value of embedded derivative feature is based on a valuation model that estimates the fair value of the convertible preferred units with and without a Rate Reset Election. This model contains inputs, including our common unit price, a ten year history of the dividend yield, default probabilities and timing estimates which involve management judgment. A significant increase or decrease in the value of these inputs could result in a material change in fair value to this embedded derivative feature. We report unrealized gains and losses associated with this embedded derivative in our Consolidated Statements of Operations as Other income (expense), net. See Note 19 for additional information on our derivative instruments. Nonfinancial Assets and Liabilities We utilize fair value on a non-recurring basis to perform impairment tests as required on our property, plant and equipment, goodwill and intangible assets. Assets and liabilities acquired in business combinations are recorded at their fair value as of the date of acquisition. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified in Level 3, in the event that we were required to measure and record such assets within our Consolidated Financial Statements. Additionally, we use fair value to determine the inception value of our asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition, and would generally be classified in Level 3. Other Fair Value Measurements We believe the debt outstanding under our credit facility approximates fair value as the stated rate of interest approximates current market rates of interest for similar instruments with comparable maturities. At December 31, 2019 our senior unsecured notes had a carrying value and fair value of $2.5 billion, compared to $2.5 billion and $2.3 billion, respectively at December 31, 2018. The fair value of the senior unsecured notes is determined based on trade information in the financial markets of our public debt and is considered a Level 2 fair value measurement. F-46 Table of Contents 21. Employee Benefit Plans We sponsor a defined benefit pension plan for employees of our Alkali Business. We account for the Alkali Business pension plan as a single employer pension plan that benefits only employees of our Alkali Business, and thus, the related assets and liability costs of the plan are recorded in the Consolidated Balance Sheet. Under the Alkali Business pension plan, each eligible employee will automatically become a participant upon completion of one year of credited service. Retirement benefits under this plan are calculated based on the total years of service of an eligible participant, multiplied by a specified benefit rate in effect at the termination of the plan participant's years of service. During 2019, we completed collective bargaining negotiations with our union employees. As a result, the pension plan was amended to increase the future benefit rate and pension supplement amounts. The change in benefit obligations, plan assets and funded status along with amounts recognized in the Consolidated Balance Sheet are as follows: December 31, 2019 2018 Change in benefit obligation: Benefit Obligation, beginning of year $ 24,511 $ Service Cost Interest Cost Plan Amendment Actuarial (Gain) Loss Benefits Paid Benefit Obligation, end of year Change in plan assets: Fair Value of Plan Assets, beginning of year Actual Return (loss) on Plan Assets Employer Contributions Benefits Paid Fair Value of Plan assets, end of year Funded Status at end of period Amounts recognized in the Consolidated Balance Sheet: Non-current assets Current liabilities Non-current Liabilities Net Liability at end of year Amounts recognized in accumulated other comprehensive income (loss): Prior Service Cost Net actuarial (gain) loss $ $ $ 4,351 1,340 6,569 5,981 (461) 42,291 15,716 4,025 4,771 (461) 24,051 (18,240) $ — $ — (18,240) (18,240) $ 6,163 2,268 Amounts recognized in accumulated other comprehensive income ( loss:) $ 8,431 $ 22,530 5,153 862 — (3,816) (218) 24,511 13,306 (1,300) 3,928 (218) 15,716 (8,795) — — (8,795) (8,795) — (939) (939) F-47 Table of Contents Estimated Future Cash Flows- The following employer contributions and benefit payments, which reflect expected future service, are expected to be paid as follows: Employer Contributions Expected 2020 Contributions by Employer Future Expected Benefit Payments 2020 $ $ 2021 2022 2023 2024 2025-2029 5,850 824 1,112 1,343 1,537 1,714 11,250 Net Periodic Pension Costs- The components of net periodic pension costs for the Alkali benefit plan are as follows: Service Cost Interest Cost Expected Return on Assets Amortization of Prior Service Cost Total Net Periodic Benefit Costs (1) December 31, 2019 2018 2017 $ 4,351 $ 5,153 $ 1,749 1,340 (1,252) 406 862 (973) — 267 (259) — $ 4,845 $ 5,042 $ 1,757 (1) On September 1, 2017, we acquired our Alkali Business including the Company's defined benefit plan. The 2017 Net Periodic Benefit Cost represents the period of the year subsequent to our purchase of the Alkali Business resulting in a lower annual cost compared to 2019 and 2018, respectively. Significant Assumptions- Discount rates are determined annually and are based on rates of return of high-quality long-term fixed income securities currently available and expected to be available during the maturity of the pension benefits. The long-term rate of return estimation for the Alkali Business pension plan is based on a capital asset pricing model using historical data and a forecasted earnings model. An expected return on plan assets analysis is performed which incorporates the current portfolio allocation, historical asset-class returns and an assessment of expected future performance using asset-class risk factors. The Alkali Business pension plan is administered by a Board-appointed committee that has fiduciary responsibility for the plan's management. The committee is responsible for the oversight and management of the plan's investments. The committee maintains an investment policy that provides guidelines for selection and retention of investment managers or funds, allocation of plan assets and performance review procedures and updating of the policy. The objective of the committee's investment policy is to manage the plan assets in such a way that will allow for the on-going payment of the Company's obligation to the beneficiaries. Weighted average assumptions used to determine benefit obligation: December 31, 2019 Discount Rate Expected Long-term Rate of Return Rate of Compensation Increase 3.56% 6.06% N/A December 31, 2018 4.62% 6.41% N/A The discount rate used to determine the net periodic cost at the beginning of the period was 4.62%. F-48 Table of Contents Pension Plan Assets - We maintain target allocation percentages among various asset classes based on an investment policy established for the pension plan. The target allocation is designed to achieve long term objectives of return, mitigating risk, and considering expected cash flows. Pension plan asset allocations at December 31, 2019 by asset category are as follows: December 31, 2019 Target % Actual % Equity securities Fixed income securities and other 41-60% 40-60% 55% 45% A summary of total investments for our pension plan assets measured at fair value is presented as of December 31 for the periods below: Cash and cash equivalents Equity securities Mutual and other exchange traded funds 2019 2018 Level 1 1,311 13,192 9,548 24,051 Level 2 — — — — Level 3 Total — $ 1,311 — $ 13,192 Level 1 506 8,038 — $ 9,548 — $ 24,051 7,172 15,716 Level 2 — — — — Level 3 Total — $ — $ 506 8,038 — $ 7,172 — $ 15,716 22. Commitments and Contingencies Commitments and Guarantees We are subject to various environmental laws and regulations. Policies and procedures are in place to monitor compliance and to detect and address any releases of crude oil from our pipelines or other facilities; however no assurance can be made that such environmental releases may not substantially affect our business. Other Matters Our facilities and operations may experience damage as a result of an accident or natural disaster. These hazards can cause personal injury or loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain insurance that we consider adequate to cover our operations and properties, in amounts we consider reasonable. Our insurance does not cover every potential risk associated with operating our facilities, including the potential loss of significant revenues. The occurrence of a significant event that is not fully-insured could materially and adversely affect our results of operations. We believe we are adequately insured for public liability and property damage to others and that our coverage is similar to other companies with operations similar to ours. No assurance can be made that we will be able to maintain adequate insurance in the future at premium rates that we consider reasonable. We are subject to lawsuits in the normal course of business and examination by tax and other regulatory authorities. We do not expect such matters presently pending to have a material effect on our financial position, results of operations or cash flows. 23. Income Taxes We are not a taxable entity for federal income tax purposes. As such, we do not directly pay federal income taxes. Other than with respect to our corporate subsidiaries and the Texas Margin Tax, our taxable income or loss is includible in the federal income tax returns of each of our partners. A few of our operations are owned by wholly-owned corporate subsidiaries that are taxable as corporations. We pay federal and state income taxes on these operations. As a result of the Tax Cuts and Jobs Act enacted on December 22, 2017, The Partnership remeasured its U.S. deferred tax assets and liabilities during the year ended December 31, 2017 and recorded a $5.3 million benefit relating to the U.S. federal corporate tax rate change. F-49 Table of Contents Our income tax (benefit) expense is as follows: Current: Federal State Total current income tax expense Deferred: Federal State Total deferred income tax expense (benefit) Total income tax expense (benefit) Year Ended December 31, 2019 2018 2017 $ $ $ $ $ — $ 591 591 $ 930 (866) 64 655 $ $ $ — $ 810 810 $ 114 574 688 1,498 $ $ $ — 100 100 (5,530) 1,471 (4,059) (3,959) Deferred income taxes relate to temporary differences based on tax laws and statutory rates that were enacted at the balance sheet date. Deferred tax assets and liabilities consist of the following: Deferred tax assets: Net operating loss carryforwards Other Total long-term deferred tax asset Valuation allowances Total deferred tax assets Deferred tax liabilities: Long-term: Fixed assets Intangible assets Other Total long-term liability Total deferred tax liabilities Total net deferred tax liability December 31, 2019 2018 12,557 $ 11,057 927 13,484 (2,172) 11,312 $ (1,958) $ (20,730) (1,264) (23,952) (23,952) $ (12,640) $ 434 11,491 (1,758) 9,733 (2,893) (18,209) (1,207) (22,309) (22,309) (12,576) $ $ $ $ $ We record a valuation allowance when it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets depends on the ability to generate sufficient taxable income of the appropriate character in the future and in the appropriate taxing jurisdictions. F-50 Table of Contents The reconciliation between the Partnership's effective tax rate on income (loss) from operations and the statutory tax rate is as follows: Income (loss) from operations before income taxes Partnership income not subject to federal income tax Income subject to federal income taxes Tax expense at federal statutory rate State income taxes, net of federal tax Return to provision, federal and state Other Re-measurement of deferred taxes due to enacted tax rate change Income tax expense (benefit) Effective tax rate on income from operations before income taxes Year Ended December 31, $ $ $ $ $ $ 2019 100,721 (99,832) 889 187 729 (219) (42) — 2018 (10,294) 10,824 530 111 1,285 (128) 230 — 655 $ 1,498 $ 1% (15)% $ $ $ $ 2017 78,120 (77,704) 416 146 1,396 (163) (68) (5,270) (3,959) (5)% At December 31, 2019, 2018 and 2017, we had no uncertain tax positions. 24. Quarterly Financial Data (Unaudited) The table below summarizes our unaudited quarterly financial data for 2019 and 2018. Revenues from continuing operations Operating income Net income Net loss (income) attributable to noncontrolling interest Net income attributable to redeemable noncontrolling interest Net income attributable to Genesis Energy, L.P. Basic and diluted net income (loss) per common unit: Net income (loss) per common unit Cash distributions per common unit (1) Revenues from continuing operations Operating income Net income (loss) Net loss attributable to noncontrolling interest Net income (loss) attributable to Genesis Energy, L.P. Basic and diluted net loss per common unit: Net loss per common unit Cash distributions per common unit (1) 2019 Quarters First Second Third Fourth 620,009 62,029 15,947 $ $ $ 7 $ — $ $ 15,954 634,785 86,948 $ $ 41,652 $ (1,532) $ — $ $ 40,120 621,697 52,787 17,807 $ $ $ 22 $ (272) $ $ 17,557 604,329 70,939 24,660 (331) (1,961) 22,368 (0.02) $ 0.17 0.5500 $ 0.5500 $ $ (0.01) $ 0.03 0.5500 $ 0.5500 2018 Quarters First Second Third Fourth 725,808 59,081 7,898 136 8,034 $ $ $ $ $ 752,388 60,900 10,871 126 10,997 $ $ $ $ $ 745,278 $ 689,296 46,148 $ (1,634) $ 1,311 $ (323) $ 4,119 (28,927) 4,144 (24,783) (0.07) $ (0.05) $ (0.15) $ (0.35) 0.5200 $ 0.5300 $ 0.5400 $ 0.5500 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ (1) Represents cash distributions declared and paid in the applicable period. F-51 Table of Contents 25. Condensed Consolidating Financial Information Our $2.5 billion aggregate principal amount of senior unsecured notes co-issued by Genesis Energy, L.P. and Genesis Energy Finance Corporation are fully and unconditionally guaranteed jointly and severally by all of Genesis Energy, L.P.’s current and future 100% owned domestic subsidiaries, except the subsidiaries that hold our Alkali Business, Genesis Free State Pipeline, LLC, Genesis NEJD Pipeline, LLC and certain other minor subsidiaries. Genesis NEJD Pipeline, LLC is 100% owned by Genesis Energy, L.P., the parent company. The remaining non-guarantor subsidiaries are owned by Genesis Crude Oil, L.P., a guarantor subsidiary. As a general rule, the assets and credit of our unrestricted subsidiaries are not available to satisfy the Partnership's debts, and the liabilities of our unrestricted subsidiaries do not constitute obligations of the Partnership except, in the case of the Alkali Business, to the extent agreed to in the services agreement between the Partnership and Alkali Holdings dated as of September 23, 2019. Genesis Energy Finance Corporation has no independent assets or operations. See Note 11 for additional information regarding our consolidated debt obligations. On September 23, 2019, the Company announced the expansion of its Granger facility which included designating the Alkali Business as unrestricted subsidiaries of the Company under our indentures. Following such designation, the Alkali Business no longer guarantees our notes. The Alkali Business was historically presented as guarantor subsidiaries in footnote 18 and because of such designation will now be presented as non-guarantor subsidiaries. The changes made did not impact the Company's previously reported consolidated net operating results, financial position, or cash flows. The condensed consolidating balance sheet as of December 31, 2018 and the condensed consolidating statements of operations and cash flows for the year ended December 31, 2018 and 2017 have been retrospectively adjusted to reflect these updates to our non-guarantor subsidiaries as though the Alkali Business had been presented as non-guarantor subsidiaries in all periods presented (consistent with our 8-K filed with the SEC on December 19, 2019). The following is condensed consolidating financial information for Genesis Energy, L.P., the guarantor subsidiaries and the non-guarantor subsidiaries: F-52 Table of Contents ASSETS Current assets: Condensed Consolidating Balance Sheet December 31, 2019 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated Cash and cash equivalents $ 6 $ — $ 7,269 $ 21,853 $ — $ Restricted cash Other current assets Total current assets Fixed Assets, at cost Less: Accumulated depreciation Net fixed assets Mineral Leaseholds, net of accumulated depletion Goodwill Other assets, net of amortization Advances to affiliates Equity investees Investments in subsidiaries Right of use assets, net Total assets LIABILITIES AND CAPITAL Current liabilities $ $ — 50 56 — — — — — 7,583 3,039,468 — 2,706,095 — — — — — — — — — — — — — — — 316,166 323,435 4,627,696 (1,089,246) 3,538,450 — 301,959 403,277 — 334,523 1,420,664 83,942 27,277 220,526 269,656 912,900 (156,875) 756,025 555,825 — 109,862 158,798 — — — (73) (73) — — — — — (180,008) (3,198,266) 29,128 27,277 536,669 593,074 5,540,596 (1,246,121) 4,294,475 555,825 301,959 340,714 — — 334,523 (4,126,759) — 93,129 — 177,071 5,753,202 $ — $ 6,406,250 $ 1,943,295 $ (7,505,106) $ 6,597,641 39,015 $ — $ 253,926 $ 122,673 $ (119) $ 415,495 Senior secured credit facility 959,300 Senior unsecured notes, net of debt issuance costs 2,469,937 Deferred tax liabilities Advances from affiliates Other liabilities Total liabilities Mezzanine Capital: Class A Convertible Preferred Units Redeemable noncontrolling interests Partners’ capital, common units Accumulated other comprehensive income (loss)(1) Noncontrolling interests — — 51,515 3,519,767 790,115 — 1,443,320 — — — — — — — — — — — — — — — 12,640 3,198,277 245,424 3,710,267 — — — — — — 276,789 399,462 — 125,133 — — — (3,198,277) 959,300 2,469,937 12,640 — (179,878) 393,850 (3,378,274) 4,251,222 — — 790,115 125,133 2,695,983 1,430,849 (4,126,832) 1,443,320 — — (8,431) (3,718) — — (8,431) (3,718) Total liabilities, mezzanine capital and partners’ capital (1) The entire balance and activity within Accumulated Other Comprehensive Income (loss) is related to our pension plan held within our Non-Guarantor Subsidiaries. (7,505,106) $ 6,406,250 5,753,202 1,943,295 — $ $ $ $ $ 6,597,641 F-53 Table of Contents ASSETS Current assets: Condensed Consolidating Balance Sheet December 31, 2018 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated Cash and cash equivalents $ 6 $ — $ 4,924 $ 5,370 $ — $ 10,300 Other current assets Total current assets Fixed Assets, at cost Less: Accumulated depreciation Net fixed assets Mineral Leaseholds, net of accumulated depletion Goodwill Other assets, net Advances to affiliates Equity investees Investments in subsidiaries Total assets LIABILITIES AND CAPITAL Current liabilities $ $ 50 56 — — — — — 10,776 3,305,568 — 2,648,510 — — — — — — — — — — — 229,411 234,335 4,602,164 (926,830) 3,675,334 — 301,959 435,540 — 355,085 1,413,334 203,683 209,053 838,694 (96,995) 741,699 560,481 — 122,538 105,917 — — (165) (165) — — — — — (167,620) (3,411,485) 432,979 443,279 5,440,858 (1,023,825) 4,417,033 560,481 301,959 401,234 — — 355,085 (4,061,844) — 5,964,910 $ — $ 6,415,587 $ 1,739,688 $ (7,641,114) $ 6,479,071 39,342 $ — $ 177,104 $ 116,498 $ (110) $ 332,834 Senior secured credit facility 970,100 Senior unsecured notes, net of debt issuance costs 2,462,363 Deferred tax liabilities Advances from affiliates Other liabilities Total liabilities Mezzanine Capital — — 40,840 3,512,645 Class A Convertible Preferred Units 761,466 Partners' capital, common units Accumulated other comprehensive income (loss) (1) Noncontrolling interests 1,690,799 — — — — — — — — — — — — — — 12,576 3,411,515 174,249 3,775,444 — — — — — — — (3,411,515) 970,100 2,462,363 12,576 — 211,590 328,088 (167,481) 259,198 (3,579,106) 4,037,071 — — — 761,466 2,640,143 1,421,865 (4,062,008) 1,690,799 — — 939 (11,204) — — 939 (11,204) Total liabilities, mezzanine capital and partners’ capital (1) The entire balance and activity within Accumulated Other Comprehensive Income (loss) is related to our pension plan held within our Non-Guarantor Subsidiaries. (7,641,114) $ 6,415,587 5,964,910 1,739,688 — $ $ $ $ $ 6,479,071 F-54 Table of Contents REVENUES: Offshore pipeline transportation Sodium minerals and sulfur services Marine transportation Onshore facilities and transportation Total revenues COSTS AND EXPENSES: Onshore facilities and transportation costs Marine transportation operating costs Sodium minerals and sulfur services operating costs Offshore pipeline transportation operating costs General and administrative Depreciation, depletion and amortization Total costs and expenses OPERATING INCOME Equity in earnings of equity investees Equity in earnings of subsidiaries Interest expense, net Other expense Income before income taxes Income tax expense NET INCOME Net income attributable to noncontrolling interests Net income attributable to redeemable noncontrolling interests NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P. Less: Accumulated distributions attributable to Class A Convertible Preferred Units NET INCOME AVAILABLE TO COMMON UNIT HOLDERS $ $ Condensed Consolidating Statement of Operations Year Ended December 31, 2019 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated $ — $ — $ 318,116 $ — $ — $ 318,116 — — — — — — — — — — — — — 327,257 (222,232) (9,026) 95,999 — 95,999 — — — — — — — — — — — — — — — — — — — — — — — 260,675 235,645 802,735 1,617,171 713,577 178,032 852,949 (7,637) 1,105,987 — 18,337 871,286 1,327 — — — 235,645 821,072 (7,637) 2,480,820 — — 714,904 178,032 200,845 690,484 (7,637) 883,692 68,167 51,191 242,227 1,454,039 163,132 56,484 96,263 12,211 — (9,171) 1,496 77,579 761,715 109,571 — — (9,419) — — — — 58,996 52,687 319,806 (7,637) 2,208,117 — — (423,520) — — 272,703 56,484 — (219,440) (9,026) 328,090 100,152 (423,520) 100,721 (649) (6) — (655) 327,441 100,146 (423,520) 100,066 — — (1,834) (2,233) — — (1,834) (2,233) 95,999 $ — $ 327,441 $ 96,079 $ (423,520) $ 95,999 (74,467) — — — — (74,467) 21,532 $ — $ 327,441 $ 96,079 $ (423,520) $ 21,532 F-55 Table of Contents REVENUES: Offshore pipeline transportation Sodium minerals and sulfur services Marine transportation Onshore facilities and transportation Total revenues COSTS AND EXPENSES: Onshore facilities and transportation costs Marine transportation operating costs Sodium minerals and sulfur services operating costs Offshore pipeline transportation operating costs General and administrative Depreciation, depletion and amortization Gain on sale of assets Impairment expense Total costs and expenses OPERATING INCOME Equity in earnings of equity investees Equity in earnings of subsidiaries Interest expense, net Other income Income before income taxes Income tax expense NET INCOME (LOSS) Net loss attributable to noncontrolling interests NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P. Less: Accumulated distributions attributable to Class A Convertible Preferred Units NET INCOME (LOSS) AVAILABLE TO COMMON UNIT HOLDERS Condensed Consolidating Statement of Operations Year Ended December 31, 2018 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated $ — $ — $ 284,544 $ — $ — $ 284,544 — — — — — — — — — — — — — — — 219,615 (230,713) 5,023 (6,075) — (6,075) — 259,573 668,200 (15,282) 912,491 — — 333,495 219,937 — 1,214,235 — 2,052,211 — 1,125,528 172,527 — — — — — — — 64,272 65,481 249,820 (42,264) 100,093 — 1,995,030 — — — — — — — — — 57,181 43,626 107,684 13,027 — 221,518 (1,727) 219,791 — 856,221 (15,282) 1,174,434 — 19,620 875,841 1,202 — — — 219,937 1,233,855 (15,282) 2,912,770 — — 1,126,730 172,527 2,396 1,417 63,370 — 26,189 762,774 113,067 — — (11,505) — — — — — — 66,668 66,898 313,190 (42,264) 126,282 (15,282) 2,742,522 — — (327,299) — — 101,562 (327,299) 229 101,791 5,717 — (327,299) — 170,248 43,626 — (229,191) 5,023 (10,294) (1,498) (11,792) 5,717 $ (6,075) $ — $ 219,791 $ 107,508 $ (327,299) $ (6,075) (69,801) — — — — (69,801) $ (75,876) $ — $ 219,791 $ 107,508 $ (327,299) $ (75,876) F-56 Table of Contents REVENUES: Offshore pipeline transportation Sodium minerals and sulfur services Marine transportation Onshore facilities and transportation Total revenues COSTS AND EXPENSES: Onshore facilities and transportation costs Marine transportation operating costs Sodium minerals and sulfur services operating costs Offshore pipeline transportation operating costs General and administrative Depreciation and amortization Gain on sale of assets Total costs and expenses OPERATING INCOME Equity in earnings of equity investees Equity in earnings of subsidiaries Interest expense, net Other expense Income before income taxes Income tax benefit NET INCOME Net loss attributable to noncontrolling interest NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P. Less: Accumulated distributions attributable to Class A Convertible Preferred Units NET INCOME AVAILABLE TO COMMON UNIT HOLDERS $ $ $ $ $ Condensed Consolidating Statement of Operations Year Ended December 31, 2017 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated $ — $ — $ 318,239 $ — $ — $ 318,239 286,263 (9,493) 117,224 226,187 (9,493) 333,918 — — — — — — — — — — — — — — 276,341 (176,979) (16,715) 82,647 — — — — — — — — — — — — — — — — — — — — 185,852 205,287 1,023,293 1,732,671 967,558 154,606 69,225 65,862 232,303 (40,311) 1,566,467 166,204 51,046 41,494 13,825 — 272,569 3,928 — 18,936 305,199 1,089 — 2,840 559 20,177 — 250,852 54,347 — — (13,608) — 462,622 205,287 1,042,229 — — (9,493) 2,028,377 — — 968,647 154,606 — — — — 72,065 66,421 252,480 (40,311) (9,493) 1,807,826 — — (317,835) — — 40,739 (317,835) 31 — 220,551 51,046 — (176,762) (16,715) 78,120 3,959 82,079 568 82,647 $ — $ 276,497 $ 40,770 — $ — $ — $ 568 82,647 $ — $ 276,497 $ 41,338 $ $ $ (317,835) $ — (317,835) $ 82,647 (21,995) $ — $ — $ — $ — (21,995) 60,652 $ — $ 276,497 $ 41,338 $ (317,835) $ 60,652 F-57 Table of Contents Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2019 Net cash (used in) provided by operating activities $ 101,385 $ — $ 585,788 $ 82,070 $ (386,956) $ 382,287 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated CASH FLOWS FROM INVESTING ACTIVITIES: Payments to acquire fixed and intangible assets Cash distributions received from equity investees - return of investment Investments in equity investees Intercompany transfers Repayments on loan to non-guarantor subsidiary Proceeds from asset sales Net cash provided by (used in) provided by investing activities CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings on senior secured credit facility Repayments on senior secured credit facility Proceeds from issuance of preferred units, net Intercompany transfers Distributions to partners/owners Distributions to preferred unitholders Contributions from noncontrolling interest Other, net — — — 222,595 — — 222,595 815,100 (825,900) — — (269,674) (43,506) — — Net cash provided by (used in) financing activities (323,980) Net increase in cash and cash equivalents and restricted cash Cash and cash equivalents and restricted cash at beginning of period Cash and cash equivalents and restricted cash at end of period $ — 6 6 — — — — — — — — — — — — — — — — — — (80,141) (83,107) 21,250 — — 8,281 1,187 — — — — — — — — (222,595) (8,281) — (163,248) 21,250 — — — 1,187 (49,423) (83,107) (230,876) (140,811) — — — (220,897) (269,674) (43,506) — 57 (534,020) 2,345 4,924 — — 122,900 (1,697) (94,375) — 5,652 12,317 44,797 43,760 5,370 — — — 222,594 364,049 43,506 — (12,317) 617,832 — — 815,100 (825,900) 122,900 — (269,674) (43,506) 5,652 57 (195,371) 46,105 10,300 $ — $ 7,269 $ 49,130 $ — $ 56,405 F-58 Table of Contents Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2018 Net cash (used in) provided by operating activities $ 28,784 $ — $ 514,096 $ 207,870 $ (360,711) $ 390,039 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated CASH FLOWS FROM INVESTING ACTIVITIES: Payments to acquire fixed and intangible assets Cash distributions received from equity investees - return of investment Investments in equity investees Intercompany transfers Repayments on loan to non-guarantor subsidiary Proceeds from assets sales Net cash (used in) provided by investing activities CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings on senior secured credit facility Repayments on senior secured credit facility Repayment of senior unsecured notes Debt issuance costs Intercompany transfers Distributions to partners/owners Contributions from noncontrolling interest Other, net — — — 503,144 — — 503,144 980,700 (1,109,800) (145,170) (242) — (257,416) — — Net cash provided by (used in) financing activities (531,928) Net increase in cash and cash equivalents Cash and cash equivalents at beginning of period Cash and cash equivalents at end of period $ — 6 6 — — — — — — — — — — — — — — — — — — (80,480) (510,628) (114,887) (80,480) 28,979 (3,018) — 7,484 310,099 228,657 — — — — (485,506) (257,416) — (137) — — — — — — — — — (17,638) (123,900) 2,592 13,121 (743,059) (125,825) (306) 5,230 1,565 3,805 — — — (503,144) (7,484) — — — — — 503,144 381,316 — (13,121) 871,339 — — (195,367) 28,979 (3,018) — — 310,099 140,693 980,700 (1,109,800) (145,170) (242) — (257,416) 2,592 (137) (529,473) 1,259 9,041 $ — $ 4,924 $ 5,370 $ — $ 10,300 F-59 Table of Contents Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2017 Net cash (used in) provided by operating activities $ 162,980 $ — $ 448,873 $ 30,467 $ (318,764) $ 323,556 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated CASH FLOWS FROM INVESTING ACTIVITIES: Payments to acquire fixed and intangible assets Cash distributions received from equity investees - return of investment Investments in equity investees Acquisitions Intercompany transfers Repayments on loan to non-guarantor subsidiary Contributions in aid of construction costs Proceeds from asset sales — — (140,513) — (1,157,781) — — — Net cash (used in) provided by investing activities (1,298,294) CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings on senior secured credit facility Repayments on senior secured credit facility Proceeds from issuance of senior unsecured notes Proceeds from issuance of Series A convertible preferred Repayment of senior secured notes Debt issuance costs Distribution to partners/owners Contributions from noncontrolling interest Issuance of common units for cash, net Intercompany transfers Other, net 1,458,700 (1,637,700) 1,000,000 726,419 (204,830) (25,913) (321,875) — 140,513 — — Net cash provided by (used in) financing activities 1,135,314 Net increase in cash and cash equivalents Cash and cash equivalents at beginning of period Cash and cash equivalents at end of period $ — 6 6 — — — — — — — — — — — — — — — — — — — — — — — (236,151) (14,442) 35,582 (4,647) — — — — 140,513 (250,593) 35,582 (4,647) (759) (1,325,000) — (1,325,759) (1,325,000) 6,764 124 85,722 — — — — 2,482,781 (6,764) — — — — 124 85,722 (1,438,365) (1,339,442) 2,616,530 (1,459,571) — — — — — — — — — — — — — — — — — — (321,875) (17,500) 339,375 — 140,513 2,770 — — (140,513) 1,169,781 1,313,000 (2,482,781) (57) 13,847 (13,847) 1,458,700 (1,637,700) 1,000,000 726,419 (204,830) (25,913) (321,875) 2,770 140,513 — (57) 988,362 1,312,117 (2,297,766) 1,138,027 (1,130) 6,360 3,142 663 — — 2,012 7,029 9,041 $ — $ 5,230 $ 3,805 $ — $ F-60 Table of Contents 26. Subsequent Events On January 16, 2020, we issued $750 million in aggregate principal amount of our 7.75% senior unsecured notes due February 15, 2028 (the “2028 Notes”). Interest payments are due February 1 and August 1 of each year with the initial interest payment due on August 1, 2020. That issuance generated net proceeds of $738.9 million net of issuance costs incurred. Our 2028 Notes mature on February 15, 2028. The net proceeds were used to purchase $554.8 million of the 6.75% senior unsecured notes due August 1, 2022 (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 net proceeds were used to repay a portion of the borrowings outstanding under our revolving credit facility. On January 17, 2020 we called for redemption the remaining balance of our 2022 Notes with a redemption date of February 16, 2020. We will record the loss associated with our tender and redemption fees and unamortized issuance costs writeoff in the first quarter of 2020. F-61
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