Edgar Filing: GENESIS ENERGY LP

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2018

¨ 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		76-0513049
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

919 Milam, Suite 2100, Houston, TX 77002

(Address of principal executive offices) (Zip code)

(713) 860-2500

Registrant’s telephone number, including area code:

Securities registered pursuant to Section 12(b) of the Act:



Title of Each Class		Name of Each Exchange on Which Registered
Common Units		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(§232.45 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.005 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 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	x	Accelerated filer	¨
Non-accelerated filer	o	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 o No x

The aggregate market value of the Class A common units held by non-affiliates of the Registrant on June 30, 2018(the last business day of Registrant’s most recently completed second fiscal quarter) was approximately $2.3 billion based on $21.91 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% beneficial owners are affiliates. On February 28, 2019, the Registrant had 122,539,221 Class A Common Units and 39,997 Class B Common Units outstanding.

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GENESIS ENERGY, L.P.

2018 FORM 10-K ANNUAL REPORT

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		Page
Part I
Item 1	Business	5
Item 1A.	Risk Factors	32
Item 1B.	Unresolved Staff Comments	49
Item 2.	Properties	49
Item 3.	Legal Proceedings	49
Item 4.	Mine Safety Disclosures	49
Part II
Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	50
Item 6.	Selected Financial Data	51
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	53
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	80
Item 8.	Financial Statements and Supplementary Data	81
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	81
Item 9A.	Controls and Procedures	81
Item 9B.	Other Information	83
Part III
Item 10.	Directors, Executive Officers and Corporate Governance	83
Item 11.	Executive Compensation	88
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	99
Item 13.	Certain Relationships and Related Transactions, and Director Independence	100
Item 14.	Principal Accountant Fees and Services	100
Part IV
Item 15.	Exhibits and Financial Statement Schedules	102
Item 16.	Form 10-K Summary	108

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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;

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•	our ability to successfully execute our business and financial strategies;


•	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 dividend 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, 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.

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PART I

Item 1. Business

General

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 Coast region of the crude oil and natural gas industry and (ii) one of the leading producers in the world of natural soda ash. Our sulfur removal business results in us being the largest producer, we believe, in the world of sodium hydrosulfide (or NaHS, pronounced “nash”).

Historically, a substantial majority of our focus has been on the midstream segment 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.

On September 1, 2017, we acquired our trona and trona-based exploring, mining, processing, producing, marketing and selling business based in Wyoming (our “Alkali Business”) for approximately $1.325 billion in cash. 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 almost 70 years and has an estimated remaining reserve life of over 100 years.

Within our legacy 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 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 2018.

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 2018,


•	the largest producer and marketer (based on tons produced), we believe, of NaHS in North and South America,


•	one of the leading producers (based on tons produced) of natural soda ash in the world, and


•	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.

On October 11, 2018, we completed the divestiture of our Powder River Basin midstream assets, which were historically reported in our onshore facilities and transportation segment. We received net proceeds of approximately $300 million for the sale.

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.

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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 2018. 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 field in the southern Keathley Canyon area of the Gulf of Mexico.

Our interests in offshore natural gas pipeline systems and related infrastructure includes approximately 970 miles of pipe with an aggregate design capacity of approximately 3,313 MMcf per day. We also own an interest in four offshore hub platforms 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. Our Alkali Business holds leases covering approximately 88,000 acres of land, containing an estimated 903 million metric tonnes 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 almost 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, WY, 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.

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. 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.-based natural soda ash operations: Solvay Chemicals, Ciner Resources, L.P., Tata Chemicals Soda Ash Partners in Wyoming, and Searles Valley Minerals, in California.

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As part of our sulfur removal business, we primarily (i) provide services to 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 primarily involve processing refiners’ high sulfur (or “sour”) gas streams to remove the sulfur. 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 and a half 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 recently completed infrastructure projects in areas such as Louisiana and Texas.

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 four onshore crude oil pipeline systems, with approximately 450 miles of pipe located primarily in Alabama, Florida, Louisiana, Mississippi and Texas. The Federal Energy Regulatory Commission, or FERC, regulates the rates charged by four of our onshore systems to their customers. The rates for the other 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, 404 railcars, and terminals and tankage with 4.6 million barrels of storage capacity (excluding capacity associated with our common carrier crude oil pipelines) in multiple locations along the Gulf Coast.

We own two CO₂ pipelines with approximately 270 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 2018.

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 refined products.

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.

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Our Objectives and Strategies

Our primary objective continues to be to generate and grow stable cash flows while never wavering from our commitment to safe and responsible operations. In 2017, we made the strategic decision to re-set our quarterly distribution and provided a plan for visible, achievable long term distribution growth and a clear path forward to deleveraging. We believe these steps, along with the (i) stable and repeatable cash flows from our Alkali Business, for 2017, 2018 and the foreseeable future, due to its long-lived trona reserves; (ii) the contribution achieved during 2018 from certain of our recent strategic investments, and (iii) proceeds received during 2018 from the sale of certain of our non-core assets located in the Powder River Basin provide a clear path forward to our goal of reducing our overall indebtedness and deleveraging, and further enhancing 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.

On September 1, 2017, we acquired our Alkali Business, which is one of the world's leading producers of natural soda ash. Natural soda ash accounts for approximately 25% 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.

Within our legacy 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, 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; 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. In 2018, refiners were the shippers of approximately 80% 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.

We intend to develop our business by:


•	Identifying and exploiting incremental profit opportunities, including cost synergies, across an increasingly integrated footprint;


•	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;


•	Economically expanding our pipeline and terminal operations by utilizing capacity currently available on our existing assets that requires minimal to no additional investment;


•	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.

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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 previously announced guidance outlying our current and forward path to deleveraging; 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 2018. 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.


•	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 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 are financially flexible and have significant liquidity. As of December 31, 2018, we had $728.7 million available under our $1.7 billion revolving credit agreement, including up to $182.2 million available under the $200 million petroleum products inventory loan sublimit and $98.8 million available for letters of credit. Our inventory borrowing base was $17.8 million at December 31, 2018.

•

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

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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 2018.


•	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, 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, 2017. Additional information regarding most of these items may be found elsewhere in this report.

Baton Rouge Area Infrastructure Expansion

We expanded our existing Baton Rouge area infrastructure to allow for greater capacity and flexibility in servicing our major refinery customer in the region. This expansion included the construction of an additional 500,000 barrels of crude oil tankage at our existing Baton Rouge Terminal. Additionally, this expansion includes the upgrading of pumping and other infrastructure capabilities in order to allow for the efficient handling of expected increases in crude oil volumes received at our Baton Rouge area facilities. These assets became operational in the first half of 2018.

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. The net proceeds were used to reduce the balance outstanding under our revolving credit facility.

Inland Marine Barge Delivery

In 2018, we accepted delivery of the final two new-build barges ordered during 2016. As of December 31, 2018, we have accepted delivery of all barges and boats on order.

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.

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The following chart depicts our organizational structure at December 31, 2018.

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 energy-related services. 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, storage tanks and terminals, railcars, rail loading and 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 byproducts. 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.

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 2018.

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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	Genesis	380	500,000	100	%	202,121	202,121
Poseidon	Genesis	358	350,000	64	%	234,960	150,374
Odyssey	Shell Pipeline	120	200,000	29	%	115,239	33,419
Eugene Island Pipeline and Other	Genesis/Shell Pipeline	184	39,000	29	%	10,147	10,147
Total		1,042	1,089,000			562,467	396,061

Lateral Lines ⁽²⁾
SEKCO	Genesis	149	115,000	100	%
Shenzi Crude Oil Pipeline	Genesis	83	230,000	100	%
Allegheny Crude Oil Pipeline	Genesis	40	140,000	100	%
Marco Polo Crude Oil Pipeline	Genesis	37	120,000	100	%
Constitution Crude Oil Pipeline	Genesis	67	80,000	100	%
Tarantula	Genesis	4	30,000	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 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 located in the southern Keathley Canyon area of the Gulf of Mexico. SEKCO has crude oil transportation agreements with five Gulf of Mexico producers, including Anadarko U.S. Offshore Corporation, Exxon Mobil Corporation, Eni Petroleum US LLC, Petrobras America and Inpex Corporation. Those producers have dedicated their production from Lucius to that pipeline for the life of the reserves. We expect the SEKCO pipeline to also provide capacity for additional projects in the deepwater Gulf of Mexico in the future.

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•	Shenzi Crude Oil. 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. 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. 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. The Constitution Crude Oil Pipeline gathers crude oil from the Constitution, 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	Operator	System Miles	Design Capacity (MMcf/day) ⁽¹⁾	Interest Owned
Independence Trail	Genesis	135	1,000	100	%
High Island Offshore System	Genesis	287	500	100	%
Anaconda Gathering System	Genesis	183	300	100	%
Green Canyon Laterals	Genesis	27	113	Various ⁽²⁾
Manta Ray Offshore Gathering System	Enbridge	237	800	25.7	%
Nautilus System	Enbridge	101	600	25.7	%
Total		970	3,313


(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.

•

Independence Trail. The Independence Trail pipeline transports natural gas from certain pipeline interconnects to the Tennessee Gas Pipeline at a pipeline interconnect on the West Delta 68 pipeline junction platform. Natural gas transported on the Independence Trail Pipeline can originate from production fields in the Atwater Valley, DeSoto Canyon, Lloyd Ridge and Mississippi Canyon areas of the Gulf of Mexico.

•

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

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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 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	Operator	Water Depth (Feet)	Natural Gas Capacity (MMcf/day) ⁽¹⁾	Crude Oil Capacity (Bbls/day) ⁽¹⁾	Interest Owned
Marco Polo	Anadarko	4,300	300	120,000	100	%
Garden Banks 72 ⁽²⁾	Genesis	518	216	36,000	54	%
East Cameron 373	Genesis	441	195	3,000	100	%
Total			711	159,000


(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.

Revenues from customers of our offshore pipeline transportation segment did not account for 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 legacy sulfur removal business, as well as those of our newly acquired Alkali Business as discussed in further detail below.

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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 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 one-quarter of global soda ash is produced from trona, 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 segment 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 segment 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 of Wyoming, United States.

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).

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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 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 nearly 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 sodium minerals and sulfur services segment, through our legacy sulfur removal 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 and a half 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.

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Customers

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.

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.

Competition

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., 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 32% of total sales in the 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.

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.

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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.

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 certain of our recently completed growth initiatives 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. We attempt to limit our direct commodity price risk in our onshore facilities and transportation segment by utilizing back-to-back purchases and sales, matching sale and purchase volumes on a monthly basis and hedging unsold volumes (primarily with NYMEX derivatives to offset the remaining price risk); however, we cannot completely eliminate commodity price risks. 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 45,000 barrels per day 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.

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	Texas System	Jay System	Mississippi System	Louisiana System
Product	Crude Oil	Crude Oil	Crude Oil	Crude Oil Intermediates Refined Products
Interest Owned	100%	100%	100%	100%
Design Capacity (Bbls/day)	Existing 8" - 60,000 Looped 18" - 275,000	150,000	45,000	350,000
2018 Throughput (Bbls/day)	33,303	14,036	6,359	159,754
System Miles	47	135	220	51
Approximate owned tankage storage capacity (Bbls)	1,100,000	230,000	247,500	330,000
Location	Hastings Junction, TX to Webster, TX Texas City, TX to Webster, TX	Southern AL/FL to Mobile, AL	Soso, MS to Liberty, MS	Port Hudson, LA to Baton Rouge, LA Baton Rouge, LA to Port Allen, LA
Rate Regulated	FERC/TXRRC	FERC	FERC	FERC

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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.

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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 43 wells, additional crude oil storage capacity of 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.

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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.

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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.

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.

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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 loading or 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. See further discussion of these facilities above.

Within our onshore facilities and transportation business segment, we employ many types of logistically flexible assets. These assets include approximately 200 trucks, 300 trailers, 404 railcars, and terminals and other tankage with 4.6 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 leased railcars consist of approximately 7 refined product railcars and 397 crude oil railcars.

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.



	Free State Pipeline
Product	CO₂
Interest owned	100%
System miles	86
Pipeline diameter	20"
Location	Jackson Dome near Jackson, MS to East Mississippi
Rate Regulated	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 2018, 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

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production. Additionally, the shipper on our Free State pipeline is required to use our Free State pipeline for any transportation of CO₂within 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 until 2020. The below table includes operational information relating to our marine transportation fleet:



	Inland	Offshore	American Phoenix
Aggregate Fleet Design Capacity (Bbls) (in thousands)	2,285	884	330
Individual Vessel Capacity Range (Bbls) (in thousands) ⁽¹⁾	23-39	65-135	330

Number of:
Push/Tug Boats	33	9	—
Barges	82	9	—
Product Tankers	—	—	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 2018, 2017 and 2016. 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 2018, 2017 and 2016, approximately 62%, 64% and 62%, respectively, of our marine transportation revenues were from term contracts and 38%, 36% 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.

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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, Trafigura, Anadarko Petroleum Corporation and ANSAC.

Employees

To carry out our business activities, we employed approximately 2,100 employees at December 31, 2018. 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 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.

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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.

Railcar Regulation

We operate a number of railcar loading and 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

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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 an affiliate of Anadarko Petroleum (“Anadarko”). 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. Anadarko 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 Anadarko. 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 Anadarko 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, 2018, 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 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

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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. It has until March 2019 to determine whether any revisions are necessary. 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 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

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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 June 16, 2017, the EPA published a proposed rule to stay for two years certain requirements of the 2016 regulations, including fugitive emission requirements. 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.

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.

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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. These findings served as a statutory prerequisite for EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the CAA. The EPA also adopted two sets of related rules, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the motor vehicle rule in April 2010 and it became effective in July 2010. The EPA adopted the stationary source rule, also known as the "Tailoring Rule," in May 2010, and it became effective in January 2011. The tailoring rule established new GHG emissions thresholds that determine when stationary sources must obtain permits under the PSD and Title V programs of the Clean Air Act. On June 23, 2014, in Utility Air Regulatory Group v. EPA (“UARG v. EPA”), the Supreme Court held that stationary sources could not become subject to PSD or Title V permitting solely by reason of their GHG emissions. The Court ruled, however, that the EPA may require installation of best available control technology for GHG emissions at sources otherwise subject to the PSD and Title V programs. On August 26, 2016, the EPA proposed changes needed to bring the EPA’s air permitting regulations in line with the Supreme Court’s decision on GHG permitting. The proposed rule was published in the Federal Register on October 3, 2016 and the public comment period closed on December 16, 2016.

Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., beginning in 2011 for emissions occurring in 2010. Further, in November 2010, the EPA expanded its existing GHG reporting rule to include onshore and offshore crude oil and natural gas production and onshore processing, transmission, storage and distribution facilities, which may include certain of our facilities, beginning in 2012 for emissions occurring in 2011. In October 2015, the EPA amended the GHG reporting rule to add the reporting of GHG emissions from gathering and boosting systems, completions and workovers of crude oil wells using hydraulic fracturing, and blowdowns of natural gas transmission pipelines. As a result of this continued regulatory focus, future GHG regulations of the crude oil and natural gas industry remain a possibility.

Further, the U.S. Congress has from time to time considered various proposals to reduce GHG emissions, and 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 legislation 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. It is not clear what steps the Trump Administration plans to take to withdraw from the Paris Agreement, whether a new agreement can be negotiated, or what terms would be included in such an agreement. Furthermore, in response to the 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.

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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.

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 has proposed additional regulations for gas pipeline safety. For example, in March 2016, the PHMSA proposed a rule that would expand IM requirements beyond HCAs to gas pipelines in newly defined Moderate Consequence Areas. The public comment period closed in July 2016. Also, in January 2017, the PHMSA released an advance copy of its final rules to expand safety regulations for hazardous liquid pipelines by, among other things, expanding the required use of leak detection systems, requiring more frequent testing for corrosion and other flaws, and requiring companies to inspect pipelines in areas affected by extreme weather or natural disasters. The final rule was withdrawn by the PHMSA in January 2017, and it is unclear whether and to what extent the PHMSA will move forward with its regulatory reforms.

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.

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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. 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, 2018, 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 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%), Anadarko Petroleum (38%) and the State of Wyoming (6%). Anadarko’s acquisition in 2000 of the Union Pacific Resources Group (“UPRG”) included the land and mineral ownership originally granted to UPRG’s parent company, the Union Pacific Railroad.

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

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area of 700,000 acres (283,280 hectares) as the Known Sodium Leasing Area (“KSLA”). In 1993, the BLM established a 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

In 2017 we acquired our Alkali Business, making us the 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 88,342 acres (equivalent to 138 sq miles or 357 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 Anadarko 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 40,883 acres from Anadarko Land Corporation, a subsidiary of Anadarko Petroleum. Anadarko’s acquisition of the Union Pacific Railroad Group in 2000 included alternate sections of land for 20 miles on either side of the trans-continental railroad, originally granted to Union Pacific under the Pacific Railroad Act of 1862 and subsequent railroad land grants. We also lease 22,243 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.

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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	Proven	298.3	89.7
	Probable	158.4	89.1
Dry-mining	Total Reserves	456.7	89.5

Solution mining	Proven	—	—
	Probable	446.0	86.3
Solution mining	Total Reserves	446.0	86.3
Alkali	Total Reserves	902.7	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 probably 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 456.7 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 446.0 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.

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The sum of our total proven and probable reserves estimated as of December 31, 2018, was 902.7 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 2014-2018. 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 1.65:1.


•	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 2014-2018 actual results.


•	Mine and plant overhead and administration costs remain similar to recent actual performance.


•	Average selling prices remain the same as the 2014-2018 average as estimated in the January 2019 USGS Mineral Commodity Summary, at approximately $138 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 2017 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 and 2018 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, 2018, 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;

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•	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 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 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 energy infrastructure 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 energy infrastructure business, and increase our market position and,

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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 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 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, 2018) 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 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;


•	the level of competition;

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•	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;


•	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. 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 beginning in late 2014, which continued into 2018 has forced most 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 sources 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. 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.

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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 available to our shippers on these interconnecting pipelines as a result of testing, pipeline repair, reduced operating pressures or

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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, recovered to approximately $76 per barrel in October 2018, and dropped to approximately $45 per barrel as of the end of December 2018, 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.

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We cannot cause our joint ventures to take or not to take certain actions unless some or all of the joint venture 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 corporate 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.

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 performance and ability of third parties to satisfy their obligations under joint venture arrangements 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.

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.

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, 2018, our marine transportation segment received approximately 62% 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 38% 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”.

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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.

Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S. beginning in 2011 for emissions occurring in 2010. Further, in November 2010, the EPA expanded its existing GHG reporting rule to include onshore and offshore crude oil and natural gas production and onshore processing, transmission, storage and distribution facilities, which may include certain of our facilities, beginning in 2012 for emissions occurring in 2011. In October 2015, the EPA amended the GHG reporting rule to add the reporting of GHG emissions from gathering and boosting systems, completions and workovers of crude oil wells using hydraulic fracturing, and blowdowns of natural gas transmission pipelines. As a result of this continued regulatory focus, future GHG regulations of the crude oil and natural gas industry remain a possibility.

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

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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. It is not clear what steps the Trump Administration plans to take to withdraw from the Paris Agreement, whether a new agreement can be negotiated, or what terms would be included in such an agreement. Furthermore, in response to the 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.

Restrictions on drilling or mining activities to protect certain species of wildlife could adversely affect our business.

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.

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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 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, accident, terrorist attack or other interruption event involving us could result in severe personal injury, property damage and/or environmental damage, which could curtail our operations and 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 and 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 is damaged or otherwise affected by severe weather or any other disaster, 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 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.

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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. Although the impact of this legislation is not yet determinable, 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.

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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.

The lifting of the U.S. crude oil export ban could adversely impact our U.S. Flag Fleet.

In December 2015, Congress voted to lift the four decade crude oil export ban. Although the impact of this legislation on our U.S. Flag fleet’s operations is not determinable, the easing of the crude oil export ban could result in reduced coastwise transportation of crude oil, which may have an adverse impact on our U.S. Flag segment.

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, 2018, 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 10.3% 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

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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.

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

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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.

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. Distributions from our joint ventures are subject to the discretion of their respective management committees. Further, certain joint ventures’ charter documents may vest in their management committees’ certain discretion regarding cash distributions. Accordingly, our joint ventures 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 Common 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 common 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.”

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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 common 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 common 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 common 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. Although there is no current legislative proposal, a prior legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.

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 common units.

A successful IRS contest of the federal income tax positions we take may adversely affect the market for our common 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 common 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.

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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 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 common 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 common units could be more or less than expected.

If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if it sells such common units at a price greater than its tax basis in those common 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 common 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 common units that may result in adverse tax consequences to them.

Investment in common 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. Allocations and/or distributions to non-U.S. persons will be subject to withholding taxes at the highest applicable effective tax rate and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. Tax-exempt entities and non-U.S. persons should consult their tax advisors before investing in our common units.

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Recently enacted legislation provides that if a unitholder sells or otherwise disposes of a common unit, the transferee is 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. However, the IRS has determined that this withholding requirement should not apply to any disposition of a publicly traded interest in a publicly traded partnership (such as us) until regulations or other guidance have been issued clarifying the application of this withholding requirement to dispositions of interests in publicly traded partnerships. Accordingly, while this new withholding requirement does not currently apply to interests in us, there can be no assurance that such requirement will not apply in the future.

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 the common 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 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.

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 prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred.

We prorate our items of income, gain, loss, and deduction between transferors and transferees of our common units each month based upon the ownership of our common 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 certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. The U.S. Department of the Treasury adopted final Treasury Regulations allowing 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.

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

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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.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

See Item 1. “Business.” We also have various operating leases for rental of office space, office and field equipment and vehicles. See “Commitments and Off-Balance Sheet Arrangements” in Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Note 22 to our Consolidated Financial Statements in Item 8 for the future minimum rental payments. 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.

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.

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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 28, 2019, we had 122,539,221 Class A common units outstanding. As of December 31, 2018, the closing price of our common units was $18.47 and we had approximately 28,000 record holders of our Class A common units, which include holders who own units through their brokers “in street name.” Additionally, we have issued 24,438,022 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.

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Item 6. Selected Financial Data

The table below includes selected financial and other data for the Partnership for the years ended December 31, 2018, 2017, 2016, 2015 and 2014 (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.”

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	Year Ended December 31,
	2018 ⁽¹⁾			2017 ⁽¹⁾			2016 ⁽¹⁾			2015 ⁽¹⁾			2014 ⁽¹⁾
Income Statement Data:
Revenues:
Offshore pipeline transportation	284,544			318,239			334,679			140,230			3,296
Sodium minerals and sulfur services	1,174,434			462,622			171,503			177,880			207,401
Marine transportation	219,937			205,287			213,021			238,757			229,282
Onshore facilities and transportation	1,233,855			1,042,229			993,290			1,689,662			3,406,185
Total revenues	$	2,912,770		$	2,028,377		$	1,712,493		$	2,246,529		$	3,846,164
Equity in earnings of equity investees	$	43,626		$	51,046		$	47,944		$	54,450		$	43,135
Income (loss) from continuing operations after income taxes	$	(11,792	)	$	82,079		$	111,082		$	421,585		$	106,202
Net income (loss) attributable to Genesis Energy, L.P.	$	(6,075	)	$	82,647		$	113,249		$	422,528		$	106,202
Net income (loss) available to Common Unitholders	$	(75,876	)	$	60,652		$	113,249		$	422,528		$	106,202
Net income (loss) attributable to Common Unitholders per Common Unit: Basic and Diluted	$	(0.62	)	$	0.50		$	1.00		$	4.10		$	1.18
Cash distributions declared per Common Unit	$	2.1000		$	2.6525		$	2.7175		$	2.4700		$	2.2300
Balance Sheet Data (at end of period):
Current assets	$	443,279		$	636,033		$	359,569		$	306,316		$	355,366
Total assets ⁽²⁾	$	6,479,071		$	7,137,481		$	5,702,592		$	5,459,599		$	3,210,624
Long-term liabilities ⁽²⁾	$	3,704,237		$	3,966,602		$	3,321,739		$	3,136,712		$	1,618,276
Class A Convertible Preferred Units	$	761,466		$	697,151		$	—		$	—		$	—
Partners' capital:
Common unitholders	1,690,799			2,026,147			2,130,331			2,029,101			1,229,203
Accumulated Other Comprehensive Income (Loss)	939			(604		)	—			—			—
Noncontrolling interests	(11,204		)	(8,079		)	(10,281		)	(8,350		)	—
Total partners’ capital	$	1,680,534		$	2,017,464		$	2,120,050		$	2,020,751		$	1,229,203
Other Data:
Volumes:
Offshore crude oil pipeline (barrels per day)	562,467			591,667			581,763			518,211			446,548
Onshore crude oil pipeline (barrels per day)	247,409			212,768			114,130			144,084			116,225
Natural gas transportation volumes (MMBtus/d)	432,261			496,302			679,862			708,556			—
CO₂ pipeline (Mcf per day)	107,674			77,921			97,955			161,409			173,770
NaHS sales (DST)	150,671			133,404			125,766			127,063			150,038
Soda Ash volumes (short tons sold)	3,669,206			1,274,421			—			—			—
NaOH sales (DST)	110,107			84,816			80,021			86,914			94,693
Crude oil and petroleum products sales (barrels per day)	45,845			51,771			62,484			91,704			99,139

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(1)	Our operating results and financial position have been affected by acquisitions and divestitures. For additional information regarding our acquisitions and divestitures during 2018, 2017 and 2016, see Note 4, related to our acquisitions, and Note 7, related to our divestitures, to our Consolidated Financial Statements included in Item 8.

(2)

As relating to new accounting guidance issued by the FASB which we adopted in 2015, our long-term liabilities and total assets for the years 2015 and after are presented to reflect changes in presentation of debt issuance costs as a direct reduction of related debt liabilities with amortization of debt issuance costs reported as interest expense. Prior to 2015, our debt liabilities were presented as a component of other long term assets.


(3)	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.

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 Coast region of the crude oil and natural gas industry and (ii) one of the leading producers in the world of natural soda ash. Our sulfur removal business results in us being the largest producer, we believe, in the world of sodium hydrosulfide (or NaHS, pronounced “nash”).

Historically, a substantial majority of our focus has been 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 enterprises and have a diverse portfolio of assets, including pipelines, offshore hub and junction platforms, refinery-related plants, storage tanks and terminals, railcars, rail loading and unloading facilities, barges and other vessels, and trucks.

On September 1, 2017, we acquired our trona and trona-based exploring, mining, processing, producing, marketing and selling business based in Wyoming (our “Alkali Business”) for approximately $1.325 billion in cash. 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 almost 70 years and has an estimated remaining reserve life (based on 2018 production) of over 100 years.

Within our legacy 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 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 2018. Our legacy midstream business has a diverse portfolio of customers, operations and assets, including pipelines, offshore hub and junction platforms, refinery-related plants, storage tanks and terminals, railcars, rail loading and unloading facilities, barges and other vessels, and trucks.

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


•	Overview of 2018 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

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Overview of 2018 Results

We reported Net Loss Attributable to Genesis Energy, L.P. of $6.1 million, or $0.62 per common unit, in 2018 compared to Net Income Attributable to Genesis Energy, L.P. of $82.6 million, or $0.50 per common unit, in 2017. The decrease was principally due to impairment expense of $126.3 million recognized during 2018. Additionally, we had an increase in depreciation and interest expense during 2018 of $60.7 million and $52.4 million, respectively, primarily attributable to owning our Alkali assets for a full year and the interest on the debt associated with that acquisition.

These decreases to net income were offset by an increase in our reported Segment Margin (as defined below in "Financial Measures") of $118.2 million principally due to twelve months of contribution from our Alkali Business during 2018 relative to four months during 2017 and the increase in volumes in our onshore facilities and transportation segment, primarily in Louisiana. Additionally, we recorded an unrealized gain of approximately $8.4 million associated with the valuation of our embedded derivative on our Class A Convertible Preferred Units recognized during 2018 compared to an unrealized loss reported in 2017 of approximately $10.5 million (both of which are recorded in Other income (expense) in the Consolidated Statements of Operations).

Cash flow from operating activities was $390.0 million for the 2018 period compared to $323.6 million for 2017, primarily driven by an increase in Segment Margin of $118.2 million during 2018 relative to 2017, partially offset by an increase in working capital effects of $12.3 million during 2018 relative to 2017.

Available Cash before Reserves (as defined below in "Financial Measures") increased $77.1 million in 2018 to $466.1 million as compared to 2017 Available Cash before Reserves of $389.0 million. See "Financial Measures" below for additional information on Available Cash before Reserves.

Segment Margin was $712.8 million in 2018, an increase of $118.2 million, or 20%, as compared to 2017. This increase resulted primarily from higher contributions from our sodium minerals and sulfur services segment (principally due to owning our Alkali Business for a full year in 2018 as compared to four months during 2017) and our onshore facilities and transportation segment, primarily attributable to our increased volumes during 2018 from our recently constructed assets in Louisiana and Texas, partially offset by smaller decreases in our other segments.

In 2018, we continued our path to de-leveraging our balance sheet and maintaining our financial flexibility to continue building long term value to stakeholders. We continued to find opportunities to right size our businesses and, during 2018, divested certain of our non-core assets to accelerate our goal to de-leverage our balance sheet. These steps, along with stable cash flows from our recently completed acquisition of our Alkali Business and the contribution from our recent strategic investments, we believe further enhance our financial flexibility to opportunistically pursue accretive organic projects and acquisitions should they present themselves. Additionally, we have situated ourselves well for future increases in volumes in our offshore business due to the long-lived reserves in the Gulf of Mexico that requires little or no additional investment from us. Overall, we believe these actions to strengthen our balance sheet and enhance our financial flexibility are the best actions we can take to allow us to generate strong optimal returns for our unitholders in the years ahead.

A more detailed discussion of our segment results and other costs is included below in "Results of Operations".

Distributions to Unitholders

On February 14, 2019, we paid a distribution of $0.55 per unit related to the fourth quarter of 2018.

With respect to our Class A Convertible Preferred Units, we have declared a payment-in-kind or PIK of the quarterly distribution, which resulted in the issuance of an additional 534,576 Class A Convertible Preferred Units. This PIK amount equates to a distribution of $0.7374 per Class A Convertible Preferred Unit for the 2018 Quarter, or $2.9496 annualized. These distributions were paid on February 14, 2019 to unitholders holders of record at the close of business January 31, 2019.

Acquisitions, Divestitures and Growth Initiatives

Alkali Business Acquisition

On September 1, 2017, we acquired our trona and trona-based exploring, mining, processing, producing, marketing and selling business based in Wyoming (our “Alkali Business”) for approximately $1.325 billion in cash. During 2018, we continued to integrate the Alkali business and the results of the business have exceeded our expectations to date.

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Baton Rouge Area Infrastructure Expansion

We expanded our existing Baton Rouge area infrastructure to allow for greater capacity and flexibility in servicing our major refinery customer in the region. This expansion included the construction of an additional 500,000 barrels of crude oil tankage at our existing Baton Rouge Terminal. Additionally, this expansion included the upgrading of pumping and other infrastructure capabilities in order to allow for the efficient handling of expected increases in crude oil volumes received at our Baton Rouge area facilities. These assets became operational in the first half of 2018.

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, 2018 increased $884.4 million, or 44%, from the year ended December 31, 2017. Additionally, our costs and expenses (excluding gains on sale of assets and impairment expense) increased $810.4 million, or 45%, between the two periods. These increases are primarily attributable to the effects of a full year of results from our Alkali Business during 2018, along with the increase in crude oil prices during 2018 that proportionately impacted our revenues and cost of sales.

The addition of our Alkali Business resulted in a large increase in revenues and costs relative to 2017 (which are reflected in our sodium minerals and sulfur services segment). Those increases are principally derived from mining trona ore and processing the entrained mineral sodium carbonate, also known as naturally occurring soda ash. Natural soda ash has significant cost advantages over synthetically produced soda ash, which we believe will exist for the foreseeable future. Natural soda ash accounts for only about 25% of the world's production; thus, we believe we should be able to somewhat mitigate the effects of market-specific factors (e.g., changes in sales prices for our products, our operating costs, and other economic considerations) on Net Income(loss), Available Cash before Reserves, and Segment Margin in the soda ash market in which we operate.

In addition to our Alkali Business, we continue to operate in our other legacy 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; 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. Refiners are the shippers of approximately 80% 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(loss), Available Cash before Reserves or Segment Margin derived from our offshore Gulf of Mexico crude oil and natural gas pipeline transportation and handling operations in the same manner in which they impact our revenues and costs derived from the purchase and sale of crude oil and petroleum products.

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. In addition, our revenues and costs between these two periods have been impacted by increases in market prices associated with our crude oil and petroleum product sales as discussed further below. In general, we do not expect fluctuations in prices for crude oil and natural gas to materially affect our net income, Available Cash before Reserves or Segment Margin to the same extent they affect our revenues and costs. 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

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would proportionately impact both our revenues and our costs, with a disproportionately smaller net impact on our Segment Margin.

As discussed throughout this document, we 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”.

Prices of crude oil have increased since December 31, 2017. The average closing prices for West Texas Intermediate ("WTI") crude oil on the New York Mercantile Exchange ("NYMEX") increased 27% to $64.74 per barrel on a year to date average for 2018, as compared to $50.95 per barrel for 2017. 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 from those operations. However, due to the indirect exposure to changes in prices discussed above and in the discussion surrounding our onshore facilities and transportation segment, crude oil and petroleum product sales volumes decreased 11% in 2018 as compared to 2017.

Additionally, changes in certain of our operating costs between the respective periods, including those associated with our offshore pipeline and marine transportation segments, are not directly correlated with commodity 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:



	Year Ended December 31,
	2018		2017		2016
	(in thousands)
Offshore pipeline transportation	285,014		317,540		336,620
Sodium minerals and sulfur services	260,488		130,333		79,508
Onshore facilities and transportation	119,918		96,376		83,364
Marine transportation	47,338		50,294		70,079
Total Segment Margin	$	712,758	$	594,543	$	569,571

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Year Ended December 31, 2018 Compared with Year Ended December 31, 2017

Offshore Pipeline Transportation Segment

Operating results and volumetric data for our offshore pipeline transportation segment are presented below:



	Year Ended December 31,
	2018			2017
	(in thousands)
Offshore crude oil pipeline revenue, excluding non-cash revenues	$	243,049		$	267,658
Offshore natural gas pipeline revenue, excluding non-cash revenues	47,048			50,582
Offshore pipeline operating costs, excluding non-cash expenses	(57,256		)	(63,231		)
Distributions from equity investments⁽¹⁾	70,072			80,639
Other	(17,899		)	(18,108		)
Offshore pipeline transportation Segment Margin	$	285,014		$	317,540

Volumetric Data 100% basis:
Crude oil pipelines (average barrels/day unless otherwise noted):
CHOPS	202,121			213,527
Poseidon	234,960			253,547
Odyssey	115,239			116,408
GOPL ⁽²⁾	10,147			8,185
Total crude oil offshore pipelines	562,467			591,667

Natural gas transportation volumes (MMBtus/d)	432,261			496,302

Volumetric Data net to our ownership interest ⁽³⁾:
Crude oil pipelines (average barrels/day unless otherwise noted):
CHOPS	202,121			213,527
Poseidon	150,374			162,270
Odyssey	33,419			33,758
GOPL ⁽²⁾	10,147			8,185
Total crude oil offshore pipelines	396,061			417,740

Natural gas transportation volumes (MMBtus/d)	164,706			222,729


(1)	Offshore pipeline transportation Segment Margin includes distributions received from our offshore pipeline joint ventures accounted for under the equity method of accounting in 2018 and 2017, 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 2018 decreased $32.5 million, or 10%, from 2017, primarily due to lower volumes. During 2018, we experienced a greater amount of scheduled and unscheduled downtime at several of the production facilities connected to our offshore infrastructure. Additionally, during 2018, three particular major fields underperformed our expectations. Offsetting this in future years are two subsea tie-backs to the same dedicated in-field production facility scheduled to come on-line during the second half of 2019, which requires minimal to no additional capital investment from the partnership. We believe that one of the fields is underperforming as a result of reservoir quality degradation, and not due to mechanical factors. We believe that the other two large underperforming fields are predominately underperforming as the result of slower production rates than those that were communicated to us last year due to the operator's

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reserve recovery maximization efforts. Notwithstanding these short term negatives, we are currently seeing increasing demand for our assets from production that is currently dedicated to 3rd party pipelines but is unable to get to shore due to a lack of capacity on such pipelines. Given our excess capacity and connectivity on certain of our systems, we expect to benefit from this takeaway capacity constraint in future periods.

In addition, the minimum bill reservation fees we collect on one of our offshore oil pipelines had a prior year step down, and we collected approximately $4.4 million less in segment margin in 2018 relative to 2017. Lastly, 2017 included contributions of approximately $2.0 million from certain of our previously owned gas pipeline and platform assets that were divested during the second quarter of 2017.

Sodium Minerals and Sulfur Services Segment

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



	Year Ended December 31,
	2018			2017
Volumes sold :
NaHS volumes (Dry short tons "DST")	150,671			133,404
Soda Ash volumes (short tons sold) ⁽¹⁾	3,669,206			1,274,421
NaOH (caustic soda) volumes (dry short tons sold) ⁽¹⁾	110,107			84,816
Total	3,929,984			1,492,641

Revenues (in thousands):
NaHS revenues, excluding non-cash revenues	$	181,391		$	149,392
NaOH (caustic soda) revenues	61,344			42,725
Revenues associated with Alkali Business	829,023			273,288
Other revenues	7,020			5,384
Total external segment revenues, excluding non-cash revenues	$	1,078,778		$	470,789

Sodium minerals and sulfur services operating costs, excluding non-cash items	(818,290		)	(340,456		)

Segment Margin (in thousands)	$	260,488		$	130,333

Average index price for NaOH per DST ⁽²⁾	$	768		$	635


(1)	Includes sales volumes from September 1, 2017, the date on which we acquired our Alkali Business.


(2)	Source: IHS Chemical

Sodium minerals and sulfur services Segment Margin for 2018 increased $130.2 million, or 100%, from 2017. This increase is principally due to the inclusion of contributions from our Alkali Business for twelve months during 2018 compared to four months during 2017, beginning with the acquisition date of September 1, 2017. The contributions thus far from our Alkali Business have exceeded our expectations and we expect continued strong performance into 2019. Costs impacting the results of our Alkali Business, many of which are similar in nature to costs related to our sulfur removal business, include costs associated with processing and producing soda ash (and other Alkali products) and marketing and selling activities. In addition, costs include activities associated with mining and extracting trona ore (including energy costs and employee compensation). Additionally, our refinery services business continues to perform well with increased NaHS volumes of approximately 13% during 2018 as they benefited from increased demand from certain of our international mining customers, primarily located in South America and our domestic mining and pulp and paper customers.

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 CO₂pipelines operating

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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;


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


•	storing and blending of crude oil and intermediate and finished refined products;


•	purchasing/selling and/or transporting crude oil from the wellhead to markets for ultimate use in refining; and


•	purchasing products from refiners, transporting those products to one of our terminals and blending those products to a quality that meets the requirements of our customers and selling those products (primarily fuel oil, asphalt and other heavy refined products) to wholesale markets;

We also may use our terminal facilities to take advantage of contango market conditions for crude oil gathering and marketing and to capitalize on regional opportunities which arise from time to time for both crude oil and petroleum products.

Despite crude oil being considered a somewhat homogeneous commodity, many refiners are very particular about the quality of crude oil feedstock they process. Many U.S. refineries have distinct configurations and product slates that require crude oil with specific characteristics, such as gravity, sulfur content and metals content. The refineries evaluate the costs to obtain, transport and process their preferred feedstocks. That particularity provides us with opportunities to help the refineries in our areas of operation identify crude oil sources and transport crude oil meeting their requirements. The imbalances and inefficiencies relative to meeting the refiners’ requirements may also provide opportunities for us to utilize our purchasing and logistical skills to meet their demands. The pricing in the majority of our crude oil purchase contracts contains a market price component and a deduction to cover the cost of transportation and to provide us with a margin. Contracts sometimes contain a grade differential which considers the chemical composition of the crude oil and its appeal to different customers. Typically, the pricing in a contract to sell crude oil will consist of the market price components and the grade differentials. The margin on individual transactions is then dependent on our ability to manage our transportation costs and to capitalize on grade differentials.

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

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Operating results for our onshore facilities and transportation segment were as follows:



	Year Ended December 31,
	2018			2017
	(in thousands)
Gathering, marketing, and logistics revenue	$	1,154,114		$	971,442
Crude oil and CO₂ pipeline tariffs and revenues from direct financing leases of CO₂ pipelines	74,895			67,226
Payments received under direct financing leases not included in income	7,633			6,921
Crude oil and products costs, excluding unrealized gains and losses from derivative transactions	(1,038,386		)	(866,239		)
Operating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses	(88,391		)	(87,007		)
Other	10,053			4,033
Segment Margin	$	119,918		$	96,376

Volumetric Data (average barrels/day unless otherwise noted):
Onshore crude oil pipelines:
Texas	33,303			32,684
Jay	14,036			14,155
Mississippi	6,359			8,290
Louisiana ⁽¹⁾	159,754			135,310
Wyoming⁽²⁾	33,957			22,329
Onshore crude oil pipelines total	247,409			212,768

CO₂ pipeline (average Mcf/day):
Free State	107,674			77,921

Crude oil and petroleum products sales:
Total crude oil and petroleum products sales	45,845			51,771
Rail unload volumes ⁽³⁾	89,082			52,877


(1)	Total daily volume for the years ended December 31, 2018 and December 31, 2017 includes 55,202 and 56,748 barrels per day respectively of intermediate refined products associated with our Port of Baton Rouge Terminal pipelines which became operational in the fourth quarter of 2016.


(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 increased $23.5 million, or 24% , in 2018 as compared to 2017. The 2018 period includes the effects of the ramp up in volumes on our pipeline, rail and terminal infrastructure on our recently completed infrastructure in the Baton Rouge corridor. This was slightly offset by lower demand for our services in our historical back-to-back, or buy/sell, crude oil marketing business associated with aggregating and trucking crude oil from producers' leases to local or regional re-sale points. Additionally, while volumes were relatively constant on our Texas system between 2018 and 2017, we were able to recognize a full 12 months of minimum volume commitments in segment margin during 2018 compared to 7 months during 2017, as the expansion and re-purposing of our system was completed during the second quarter of 2017.

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Marine Transportation Segment

Within our marine transportation segment, we own a fleet of 91 barges (82 inland and 9 offshore) with a combined transportation capacity of 3.2 million barrels, 42 push/tow boats (33 inland and 9 offshore), and a 330,000 barrel ocean going tanker, the M/T American Phoenix. Operating results for our marine transportation segment were as follows:



	Year Ended December 31,
	2018			2017
Revenues (in thousands):
Inland freight revenues	$	93,091		$	82,354
Offshore freight revenues	70,804			73,540
Other rebill revenues ⁽¹⁾	56,042			49,393
Total segment revenues	$	219,937		$	205,287

Operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses	$	172,599		$	154,993

Segment Margin (in thousands)	$	47,338		$	50,294

Fleet Utilization: ⁽²⁾
Inland Barge Utilization	95.2		%	90.4		%
Offshore Barge Utilization	93.5		%	98.2		%

(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 2018 decreased $3.0 million, or 6%, from 2017. The decrease in Segment Margin is primarily attributable to our offshore barge fleet entering into short term spot price contracts, which can lead to a less favorable rebill structure and higher operating costs, as our last legacy term contract rolled off during the first quarter of 2018. Additionally, we had an increase in operating costs during 2018 relative to 2017 due to the increase in our dry-docking costs. 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 at, or approaching, cyclical lows. While we are reasonably hopeful that we've reached a bottom for the quarterly segment margin from our entire fleet of assets, we have no expectation of the fundamentals for marine transportation showing any significant improvement through at least the next several years. This excludes the M/T American Phoenix which is under long term contract through September 2020. These decreases were partially offset by increased segment margin in the 2018 period related to the M/T American Phoenix. During 2017, the M/T American Phoenix underwent its planned regulatory dry-docking inspections which negatively impacted segment margin. Additionally, the 2018 period also had higher utilization on our inland barge operation.

Other Costs and Interest

General and administrative expenses



	Year Ended December 31,
	2018		2017
	(in thousands)
General and administrative expenses not separately identified below:
Corporate	$	50,918	$	51,160
Segment	4,532		3,684
Long-term incentive based compensation plan expense	2,345		(2,272		)
Third party costs related to business development activities and growth projects	9,103		13,849
Total general and administrative expenses	$	66,898	$	66,421

Total general and administrative expenses increased $0.5 million between 2018 and 2017. This is primarily attributable to an increase in our overall long term incentive compensation plan expense due to valuation assumptions used

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between the two periods. This increase was partially offset by lower third party financing, legal and accounting costs surrounding our acquisition and disposition activities in 2018 relative to 2017, including the acquisition of our Alkali Business.

Depreciation, depletion, and amortization expense



	Year Ended December 31,
	2018		2017
	(in thousands)
Depreciation and depletion expense	$	290,070	$	227,540
Amortization of intangible assets	21,835		23,612
Amortization of CO₂volumetric production payments	1,285		1,328
Total depreciation, depletion and amortization expense	$	313,190	$	252,480

Total depreciation, depletion, and amortization expense increased $60.7 million between 2018 and 2017 primarily as a result of placing additional assets into service, including those acquired as a part of our Alkali Business and certain of our organic growth projects that were recently placed in service.

Interest expense, net



	Year Ended December 31,
	2018			2017
	(in thousands)
Interest expense, senior secured credit facility (including commitment fees)	$	62,439		$	51,587
Interest expense, senior unsecured notes	159,175			128,983
Amortization and write-off of debt issuance costs and discount	10,914			11,214
Capitalized interest	(3,337		)	(15,022		)
Net interest expense	$	229,191		$	176,762

Net interest expense increased $52.4 million during 2018 primarily due to an increase in our average outstanding indebtedness from acquired and constructed assets, including the financing of the acquisition of our Alkali Business in 2017, along with an increase in libor rates during 2018 which is a major component in the interest expense derived on our senior secured credit facility. In addition, capitalized interest decreased as result of certain of our large organic growth projects being completed and placed into service throughout 2017.

Other Consolidated Results

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(refer to Note 7 and Note 10).

Net income (loss) included an unrealized gain on the valuation of our embedded derivative associated with our preferred units of $8.4 million in 2018 compared to an unrealized loss of $10.5 million during 2017. Those amounts are included in other income (expense) in the Consolidated Statement of Operations.

Year Ended December 31, 2017 Compared with Year Ended December 31, 2016

Offshore Pipeline Transportation Segment

Operating results and volumetric data for our offshore pipeline transportation segment are presented below:

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	Year Ended December 31,
	2017			2016
	(in thousands)
Offshore crude oil pipeline revenue	$	267,658		$	270,454
Offshore natural gas pipeline revenue	50,582			64,225
Offshore pipeline operating costs, excluding non-cash expenses	(63,231		)	(72,009		)
Distributions from equity investments	80,639			84,321
Other	(18,108		)	(10,371		)
Offshore Pipeline Transportation Segment Margin⁽¹⁾	$	317,540		$	336,620

Volumetric Data 100% basis:
Offshore crude oil pipelines (average barrels/day unless otherwise noted):
CHOPS	213,527			204,533
Poseidon	253,547			262,829
Odyssey	116,408			106,933
GOPL⁽²⁾	8,185			7,468
Total crude oil offshore pipelines	591,667			581,763

Natural gas transportation volumes (MMBtus/d)	496,302			679,862

Volumetric Data net to our ownership interest ⁽³⁾:
Offshore crude oil pipelines (average barrels/day unless otherwise noted):
CHOPS	213,527			204,533
Poseidon	162,270			168,211
Odyssey	33,758			31,011
GOPL⁽²⁾	8,185			7,468
Total crude oil offshore pipelines	417,740			411,223

Natural gas transportation volumes (MMBtus/d)	222,729			398,190


(1)	Offshore Pipeline Transportation Segment Margin includes distributions received from our offshore pipeline joint ventures accounted for under the equity method of accounting in 2017 and 2016, 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 2017 decreased $19.1 million, or 6%, from 2016. The year ended December 31, 2017 was negatively impacted by both anticipated and unanticipated downtime at several major fields, including weather-related downtime, affecting certain of our deepwater Gulf of Mexico customers and thus certain of our key crude oil and natural gas assets, including our Poseidon pipeline and certain associated laterals which we own. The 2017 period also reflects the effects of a contractual adjustment to a lower rate for a lateral we own that will be in place going forward. In addition, we benefited in 2016 from the temporary diversion of certain natural gas volumes from third party gas pipelines to one of our gas pipelines and related facilities due to one-time disruptions at onshore processing facilities where such volumes typically flow.

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Sodium Minerals and Sulfur Services Segment

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



	Year Ended December 31,
	2017	2016
Volumes sold:
NaHS volumes (Dry short tons "DST")	133,404	125,766
Soda Ash volumes (short tons sold) ⁽¹⁾	1,274,421	—