gel-20201231
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
☒ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2020
OR
☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-12295
GENESIS ENERGY, L.P.
(Exact name of registrant as specified in its charter)
(Address of principal executive offices) (Zip code)
Registrant’s telephone number, including area code: (713) 860-2500
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Trading Symbol(s) Name of Each Exchange on Which Registered
Common Units GEL 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. Yesx 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 oNox
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. Yesx No o
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T(§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yesx No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer," “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer x Accelerated filer ☐
Non-accelerated filer ☐ Smaller reporting company ☐
Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2) of the Act). Yes ☐ No x
The aggregate market value of the Class A common units held by non-affiliates of the Registrant on June 30, 2020 (the last business day of Registrant’s most recently completed second fiscal quarter) was approximately $755.4 million based on $7.22 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 March 1, 2021, 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.
2020 FORM 10-K ANNUAL REPORT
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Page
Part I
Item 1 Business 6
Item 1A. Risk Factors 35
Item 1B. Unresolved Staff Comments 52
Item 2. Properties 52
Item 3. Legal Proceedings 52
Item 4. Mine Safety Disclosures 52
Part II
Item 6. Selected Financial Data 54
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 81
Item 8. Financial Statements and Supplementary Data 82
Item 9A. Controls and Procedures 82
Item 9B. Other Information 84
Part III
Item 10. Directors, Executive Officers and Corporate Governance 84
Item 11. Executive Compensation 89
Item 14. Principal Accountant Fees and Services 100
Part IV
Item 15. Exhibits and Financial Statement Schedules 102
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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, and caustic soda, all of which may be affected by economic activity, capital expenditures by energy producers, weather, alternative energy sources, international events,
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pandemics (including Covid-19), the actions of OPEC (as defined below) and other oil exporting nations, conservation and technological advances;
•our ability to successfully execute our business and financial strategies;
•our ability to realize cost savings from our recent cost saving measures;
•the realized benefits of the preferred equity investment in Alkali Holdings (as defined below) by GSO (as defined below) or our ability to comply with the GOP (as defined below) agreements and maintain control over and ownership of the Alkali Business;
•throughput levels and rates;
•changes in, or challenges to, our tariff rates;
•our ability to successfully identify and close strategic acquisitions on acceptable terms (including obtaining third-party consents and waivers of preferential rights), develop or construct infrastructure assets, make cost saving changes in operations and integrate acquired assets or businesses into our existing operations;
•service interruptions in our pipeline transportation systems, processing operations or mining facilities;
•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 or otherwise;
•the effects of future laws and regulations;
•planned capital expenditures and availability of capital resources to fund capital expenditures, and our ability to access the credit and capital markets to obtain financing on terms we deem acceptable;
•our inability to borrow or otherwise access funds needed for operations, expansions or capital expenditures as a result of our credit agreement and the indentures governing our notes, which contain various affirmative and negative covenants;
•loss of key personnel;
•cash from operations that we generate could decrease or fail to meet expectations, either of which could reduce our ability to pay quarterly cash distributions at the current level, pay our quarterly distribution on our Class A Convertible Preferred Units (as defined below), 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;
•the impact of natural disasters, pandemics (including Covid-19), epidemics, accidents or terrorism, and actions taken by governmental authorities and other third parties in response thereto, on our business financial condition and results of operations;
•reduction in demand for our services resulting in impairments of our assets;
•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;
•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; and
•a cyberattack involving our information systems and related infrastructure, or that of our business associates.
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
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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 of Mexico and the Gulf Coast region of the crude oil and natural gas industry and (ii) one of the leading producers in the world of natural soda ash.
A core part of our focus is in the midstream sector of the crude oil and natural gas industry in the Gulf of Mexico and the Gulf Coast region of the United States. We provide an integrated suite of services to refiners, crude oil and natural gas producers, and industrial and commercial enterprises and have a diverse portfolio of assets, including pipelines, offshore hub and junction platforms, refinery-related plants, storage tanks and terminals, railcars, rail unloading facilities, barges and other vessels, and trucks.
Our offshore Gulf of Mexico crude oil and natural gas pipeline transportation and handling operations focus on providing a suite of services primarily to integrated and large independent energy companies who make intensive capital investments (often in excess of a billion dollars) to develop numerous large-reservoir, long-lived crude oil and natural gas properties. We provide services to one of the most active drilling and development regions in the U.S.- the Gulf of Mexico- a producing region representing approximately 15% of the crude oil production in the U.S. during 2020. Our onshore-based refinery-centric operations located primarily in the Gulf Coast region of the U.S. focus on providing a suite of services primarily to refiners, which includes our sulfur removal services, transportation, storage, and other handling services. Our onshore-based operations occur upstream of, at, and downstream of refinery complexes. Upstream of refineries, we aggregate, purchase, gather and transport crude oil, which we sell to refiners, as well as perform other handling activities. Within refineries, we provide services to assist in sulfur removal/balancing requirements. Downstream of refineries, we provide transportation services as well as market outlets for finished refined petroleum products and certain refining by-products.
The other core focus of our business is our trona and trona-based exploring, mining, processing, producing, marketing and selling business based in Wyoming (our “Alkali Business”). Our Alkali Business mines and processes trona from which it produces natural soda ash, also known as sodium carbonate (Na2CO3), a basic building block for a number of ubiquitous products, including flat glass, container glass, dry detergent and a variety of chemicals and other industrial products, and has been operating for over 70 years. Our Alkali Business has a diverse customer base in the United States, Canada, the European Community, the European Free Trade Area and the South African Customs Union with many long-term relationships. Our Alkali Business has an estimated remaining reserve life (based on 2020 production) of over 100 years related to the seam currently being mined, which is disclosed in further detail in the Reporting of Ore and Mineral Reserve section of Item 1. Our existing leases have other seams available to us for future mining that would increase our available reserve quantities.
Our operations include, among others, the following diversified businesses, each of which is one of the leaders in its market, has a long commercial life and has significant barriers to entry:
•one of the largest pipeline networks (based on throughput capacity) in the Deepwater area of the Gulf of Mexico, an area that produced approximately 15% of the oil produced in the U.S. during 2020;
•one of the leading providers of crude oil and petroleum transportation, storage, and other handling services for two of the largest refinery complexes in the U.S., one located in Baton Rouge, Louisiana and one in Baytown, Texas, both of which have been operational for approximately 100 years;
•one of the leading producers (based on tons produced) of natural soda ash in the world; and
•one of the largest producers and marketers (based on tons produced) of sodium hydrosulfide (or NaHS, pronounced "nash") in North and South America.
We conduct our operations and own our operating assets through our subsidiaries and joint ventures. Our general partner, Genesis Energy, LLC, a wholly-owned subsidiary that owns a non-economic general partner interest in us, has sole responsibility for conducting our business and managing our operations. Our outstanding common units (including our Class B common units), and our outstanding Class A convertible preferred units (our "Class A Convertible Preferred Units"), representing limited partner interests, constitute all of the economic equity interests in us.
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."
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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 a billion dollars) to develop numerous large-reservoir, long-lived crude oil and natural gas properties in the Gulf of Mexico, primarily offshore Texas, Louisiana, and Mississippi. 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 15% of the crude oil production in the U.S. during 2020. Even though the large-reservoir properties, 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 and gas companies and large independent crude oil and natural gas 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 1,944 MBbls per day, a number of which pipeline systems are substantial and/or strategically located. For example, we own a 64% interest in the Poseidon pipeline system and 100% of the Cameron Highway pipeline system, or CHOPS, which is one of the largest crude oil pipelines (in terms of both length and design capacity) located in the Gulf of Mexico. We also own 100% of the Southeast Keathley Canyon Pipeline Company, LLC ("SEKCO"), which is a deepwater pipeline servicing the Lucius, Buckskin and Hadrian North fields in the southern Keathley Canyon area of the Gulf of Mexico.
Our interests in operating offshore natural gas pipeline systems and related infrastructure include approximately 764 miles of pipe with an aggregate design capacity of approximately 2,308 MMcf per day. We also own an interest in four offshore hub platforms, three of which are operational, with an 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 long-term 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 sodium minerals and sulfur services segment includes our Alkali Business and our sulfur removal business.
Our Alkali Business owns the largest leasehold position of accessible trona ore reserves in the Green River, Wyoming trona patch, a geological formation holding the vast majority of the world’s accessible trona ore reserves, which we mine to ultimately produce, market, and sell soda ash. Soda ash is utilized by our customers as a basic building block for a number of ubiquitous products, including flat glass, container glass, dry detergent and a variety of chemicals and other industrial products.
Our Alkali Business holds leases covering approximately 87,000 acres of land, containing an estimated 890 million short tons of proved and probable reserves of trona ore, representing an estimated remaining reserve life of over 100 years. It also owns and operates soda ash production facilities, underground trona ore mines and solution mining operations and related equipment, logistics and other assets.
Our Alkali Business has been mining trona and producing soda ash in the Green River, Wyoming trona patch for over 70 years. All of our Alkali Business’ mining and processing activities are conducted at its “Westvaco” and “Granger” facilities in Wyoming. Utilizing our two facilities near Green River, our Alkali Business involves the mining of trona ore, the processing of 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 were members during 2020, 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 14 for a further discussion of ANSAC.
The global market in which our Alkali Business operates is competitive. Competition is based on a number of factors such as price, favorable logistics and consistent customer service. In North America, primary competition is from other U.S.-based natural soda ash operations: Solvay Chemicals, Ciner Resources, L.P., and Tata Chemicals Soda Ash Partners in Wyoming, and Searles Valley Minerals in California.
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As part of our sulfur services business, we primarily (i) provide sulfur removal services by processing refineries high sulfur (or "sour") gas streams to remove the sulfur at ten refining operations located mostly in Texas, Louisiana, Arkansas, Oklahoma, Montana and Utah; (ii) operate significant storage and transportation assets in relation to those services; and (iii) sell NaHS and NaOH (also known as caustic soda) to large industrial and commercial companies. Our sulfur removal services footprint also includes NaHS and caustic soda terminals, and we utilize railcars, ships, barges and trucks to transport product. Our sulfur removal services contracts are typically long-term in nature and have an average remaining term of approximately three 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 the mining of base metals, primarily copper and molybdenum, and the production of pulp and paper. We believe we are one of the largest producers and marketers of NaHS in North and South America.
Onshore Facilities and Transportation Segment
Our onshore facilities and transportation segment owns and/or leases our increasingly integrated suite of onshore crude oil and refined products infrastructure, including pipelines, trucks, terminals, railcars, and rail unloading facilities. It uses those assets, together with other modes of transportation owned by third parties and us, to service its customers and for its own account. The increasingly integrated nature of our onshore facilities and transportation assets is particularly evident in certain of our more recently completed infrastructure projects in areas such as Louisiana and Texas.
We own four onshore crude oil pipeline systems, with approximately 450 miles of pipe located primarily in Alabama, Florida, Louisiana, Mississippi and Texas that are rate regulated by the Federal Energy Regulatory Commission, or FERC. The rates for certain segments of our Texas onshore pipeline are regulated by the Railroad Commission of Texas. Our onshore pipelines generate cash flows from fees charged to customers. Each of our onshore pipelines has significant available capacity to accommodate potential future growth in volumes.
We own four operational crude oil rail unloading facilities located in Baton Rouge, Louisiana; Raceland, Louisiana; Walnut Hill, Florida; and Natchez, Mississippi, which provide synergies to our existing asset footprint. We generally earn a fee for unloading railcars at these facilities. Three of these facilities, our Baton Rouge, Louisiana, Raceland, Louisiana, and Walnut Hill, Florida facilities are directly connected to our existing integrated crude oil pipeline and terminal infrastructure.
In addition to the above, we have access to a suite of trucks, trailers, and railcars, as well as terminals and tankage with approximately 4.2 million barrels of storage capacity (excluding capacity associated with our common carrier crude oil pipelines) in multiple locations along the Gulf Coast, which we use to service customers and for our own account. Usually, our onshore facilities and transportation segment experiences limited direct commodity price risk because it utilizes back-to-back purchases and sales, matching sale and purchase volumes on a monthly basis. Unsold volumes are hedged with NYMEX derivatives to offset the remaining price risk.
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 approximately 80% of our marine transportation volumes for 2020.
We also own the M/T American Phoenix, an ocean going tanker with 330,000 barrels of cargo capacity. The M/T American Phoenix is currently transporting crude oil.
We are a provider of transportation services for our customers and, in almost all cases, do not assume ownership of the products that we transport. Our marine transportation services are conducted under term contracts, some of which have renewal options for customers with whom we have traditionally had long-standing relationships, and spot contracts. For more information regarding our charter arrangements, please refer to the marine transportation segment discussion below. All of our vessels operate under the U.S. flag and are qualified for domestic trade under the Jones Act.
Our Objectives and Strategies
Our primary objective continues to be to generate and grow stable cash flows and deleverage our balance sheet, while never wavering from our commitment to safe and responsible operations. In addition to this, we believe that (i) the new long-term contracted commercial opportunities that will provide significant incremental volumes on our already constructed offshore pipeline transportation assets that require minimal to no additional investment from us; (ii) the normalization of soda ash markets, including both price and volume recovery; (iii) our minimal expected growth capital expenditures for the foreseeable future with the exception of the Granger Optimization Project (as defined below), which can be fully funded externally, subject to compliance with the covenants contained in our agreements with GSO; (iv) the continued realization of our cost saving
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initiatives implemented in mid-2020; (v) the disposition and early monetization of our non-core legacy CO2 business; and (vi) our recent debt transactions, including our at the market repurchases of certain of our senior unsecured notes of approximately $153.6 million, the tender and redemption of our 2023 Notes (as defined below), and the issuance of our $750 million 2027 Notes (Note 10), allow us the financial flexibility to naturally deleverage our balance sheet. We are also currently working with our banks to renew and extend the maturity on our senior secured credit facility that is currently set to mature in 2022. These allow us to further enhance our financial flexibility to opportunistically pursue accretive organic projects and acquisitions should they present themselves.
Business Strategy
Our primary business strategy is to provide an integrated suite of services to crude oil and natural gas producers, refiners, and industrial and commercial enterprises that use natural soda ash, NaHS and caustic soda. Successfully executing this strategy should enable us to generate and grow stable cash flows.
Our offshore Gulf of Mexico crude oil and natural gas pipeline transportation and handling operations focus on providing a suite of services primarily to integrated and large independent energy companies who make intensive capital investments (often in excess of a billion dollars) to develop numerous large-reservoir, long-lived crude oil and natural gas properties. The integrated and large independent energy companies that use our offshore oil pipelines produce oil that is ideally suited for the vast majority of refineries along the Gulf Coast, unlike the lighter crude oil and condensates produced from numerous onshore shale plays. Our onshore-based refinery-centric operations located primarily in the Gulf Coast region of the U.S. focus on providing a suite of services primarily to refiners, which include our sulfur removal services, transportation, storage, and other handling services. In 2020, refiners were the shippers of approximately 97% of the volumes transported on our onshore crude pipelines, and refiners contracted for approximately 80% of the use of our inland barges during 2020, which are used primarily to transport intermediate refined products (not crude oil) between refining complexes.
Our Alkali Business is one of the world's leading producers of natural soda ash. Natural soda ash accounts for approximately 30% of the world’s production of soda ash. We believe the significant cost advantage in the production of natural soda ash over synthetically produced soda ash will remain for the foreseeable future, somewhat mitigating the effects of market specific factors in the soda ash market in which we operate.
We intend to develop our business by:
•Identifying and exploiting incremental profit opportunities, including cost synergies, across an increasingly integrated footprint;
•Economically expanding our pipeline and terminal operations by utilizing capacity currently available on our existing assets that requires minimal to no additional investment;
•Optimizing our existing assets and creating synergies through additional commercial and operating advancement;
•Leveraging customer relationships across business segments;
•Attracting new customers and expanding our scope of services offered to existing customers;
•Expanding the geographic reach of our businesses;
•Evaluating internal and third party growth opportunities (including asset and business acquisitions) that leverage our core competencies and strengths and further integrate our businesses; and
•Focusing on health, safety and environmental stewardship.
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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 current and forward path to deleveraging (including minimal growth capital requirements in the foreseeable future outside of our Granger Optimization Project, which can be fully funded externally, subject to compliance with the covenants contained in our agreements with GSO), as well as being cash flow positive in 2021 and the foreseeable future; and
•Create strategic arrangements and share capital costs and risks through joint ventures and strategic alliances.
Competitive Strengths
We believe we are well positioned to execute our strategies and ultimately achieve our objectives due primarily to the following competitive strengths:
•Our businesses encompass a balanced, diversified portfolio of customers, operations and assets. We operate four business segments and own and operate assets that enable us to provide a number of services primarily to refiners, crude oil and natural gas producers, and industrial and commercial enterprises that use natural soda ash, NaHS and caustic soda. Our business lines complement each other by allowing us to offer an integrated suite of services to common customers across segments. Our businesses are primarily focused on (i) providing offshore crude oil and natural gas pipeline transportation and related handling services in the Gulf of Mexico to mostly integrated and large independent energy companies, (ii) producing sodium minerals and performing sulfur removal services 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 15% of the oil produced in the U.S. during 2020. We are one of the leading producers (based on tons produced) of natural soda ash in the world. We believe we are one of the largest producers and marketers (based on tons produced) of NaHS in North and South America. We are one of the leading providers of crude oil and petroleum product transportation, storage and other handling services for large, complex refineries in Baton Rouge, Louisiana and Baytown, Texas, both of which have been operational for approximately 100 years.
•We are financially flexible and have significant liquidity. As of December 31, 2020, we had $1,055.2 million available under our $1.7 billion revolving credit agreement, subject to compliance with our covenants, including up to $165.6 million available under the $200 million petroleum products inventory loan sublimit and $198.9 million available for letters of credit. Our inventory borrowing base was $34.4 million at December 31, 2020.
•Our businesses provide relatively consistent consolidated financial performance. Our historically consistent financial performance, combined with our goal of a conservative capital structure over the long term, has allowed us to generate relatively stable and increasing cash flows.
•We have limited direct commodity price risk exposure in our oil and gas and NaHS businesses. The volumes of crude oil, refined products or intermediate feedstocks we purchase are either subject to back-to-back sales contracts or are hedged with NYMEX derivatives to limit our direct exposure to movements in the price of the commodity, although we cannot completely eliminate commodity price exposure. Our risk management policy requires us to monitor the effectiveness of the hedges to maintain a value at risk of such hedged inventory not in excess of $2.5 million. In addition, our service contracts with refiners allow us to adjust the rates we charge for processing to maintain a balance between NaHS supply and demand.
•Our offshore Gulf of Mexico crude oil and natural gas pipeline transportation and handling operations are located in a significant producing region with large-reservoir, long-lived crude oil and natural gas properties. We provide a suite of services, primarily to integrated and large independent energy companies who make intensive capital investments to develop numerous large-reservoir, long-lived crude oil and natural gas properties, in one of the most
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active drilling and development regions in the U.S.-the Gulf of Mexico, a producing region representing approximately 15% of the crude oil production in the U.S. during 2020.
•Our Alkali Business has significant cost advantages over synthetic production methods. Our Alkali Business has significant cost advantages over synthetic production methods, including lower raw material and energy requirements. According to IHS, on average, the cash cost to produce material soda ash has been about half of the cost to produce synthetic soda ash.
•Our expertise and reputation for high performance standards and quality enable us to provide refiners with economic and proven services. Our extensive understanding of the sulfur removal process and crude oil refining can provide us with an advantage when evaluating new opportunities and/or markets.
•Some of our pipeline transportation and related assets are strategically located. Our pipelines are critical to the ongoing operations of our refiner and producer customers. In addition, a majority of our terminals are located in areas that can be accessed by pipeline, truck, rail or barge.
•Some of our onshore facilities and transportation assets are operationally flexible. Our portfolio of trucks, railcars, barges and terminals affords us flexibility within our existing regional footprint and provides us the capability to enter new markets and expand our customer relationships.
•Our marine transportation assets provide waterborne transportation throughout North America. Our fleet of barges and boats provide service to both inland and offshore customers within a large North American geographic footprint. All of our vessels operate under the U.S. flag and are qualified for U.S. coastwise trade under the Jones Act.
•We have an experienced, knowledgeable and motivated executive management team with a proven track record. Our executive management team has an average of more than 25 years of experience in the midstream sector. Its members have worked in leadership roles at a number of large, successful public companies, including other publicly-traded partnerships. Through their equity interest in us and compensation package (including long term incentive awards based on available cash before reserves, leverage, and safety metrics), our executive management team is incentivized to create value by increasing cash flows.
Recent Developments and Status of Certain Growth Initiatives
The following is a brief listing of developments since December 31, 2019. Additional information regarding most of these items may be found elsewhere in this report.
Granger Production Facility Expansion
On September 23, 2019, we announced the expansion of our existing Granger facility (the "Granger Optimization Project" or "GOP") currently expected to be completed near the end of 2023. We entered into agreements with funds affiliated with GSO Capital Partners LP (collectively, "GSO") for the purchase of up to $350 million of preferred units in Genesis Alkali Holdings Company ("Alkali Holdings"). The proceeds we receive from GSO will fund up to 100% of the anticipated cost of the GOP, subject to compliance with the covenants contained in our agreements with GSO. The preferred unitholders receive payment-in-kind in lieu of cash distributions during the anticipated construction period.
On April 14, 2020, we entered into an amendment to our agreements with GSO to, among other things, extend the construction timeline of the Granger Optimization Project by one year, to late 2023. In consideration for the amendment, we issued 1,750 Alkali Holdings preferred units to GSO, which was accounted for as issuance costs. As of December 31, 2020, there are 141,249 Alkali Holdings preferred units outstanding.
Covid-19 and Market Update
In March 2020, the World Health Organization categorized Covid-19 as a pandemic, and the President of the United States declared the Covid-19 outbreak a national emergency. Our operations, which fall within the energy, mining and transportation sectors, are considered critical and essential by the Department of Homeland Security's Cybersecurity and Infrastructure Security Agency ("CISA") and we have continued to operate our assets during this pandemic.
Covid-19 has caused commodity prices to decline due to, among other things, reduced industrial activity and travel demand that are expected to continue in the near future. Beginning in the second quarter of 2020, our results were negatively impacted, primarily through lower volumes and demand for our assets, by the macroeconomic conditions and current operating environment. Additionally, as a result of lower current demand and the outlook for our crude-by-rail logistics assets, and rail becoming an uneconomic means of transportation for producers to get crude oil to their refineries, we recognized a non-cash
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impairment charge associated with these assets in our onshore facilities and transportation segment during the second quarter of 2020 (refer to Note 7 for additional discussion). In response to the pandemic and as part of our overall cost savings strategy, during the second quarter of 2020 we recorded a one-time charge of approximately $13 million associated with restructuring and severance expenses incurred during the period.
In addition to Covid-19, we experienced several major weather disruptions, including Tropical Storm Cristobal and Hurricanes Laura, Marco, Delta and Zeta, which caused significant downtime and damage to certain of our assets in the Gulf of Mexico causing an increase to our operating costs in our offshore pipeline transportation segment. As a result of these named storms, we sustained damage to our Garden Banks 72 (GB 72) junction platform and had to take our CHOPS pipeline, which goes up and over GB72, out of service beginning on August 26, 2020. From this time through the end of 2020, we were able to successfully divert all volumes from CHOPS onto our 64% owned Poseidon oil pipeline. On February 4, 2021, we completed the construction of a bypass around the GB72 platform that allowed CHOPS to resume service.
During the end of the third quarter and throughout the remainder of 2020, our businesses began to see a slight recovery in volumes and demand as certain regions of the United States and the world begin to re-open their economies.
CO2 Assets Disposition
On October 30, 2020, we reached an agreement with a subsidiary of Denbury Inc. to transfer to them the ownership of our remaining CO2 assets, including the North East Jackson Dome ("NEJD") and Free State pipelines. As a part of the agreement, we will receive total consideration of $92.5 million, of which $22.5 million was paid in the fourth quarter of 2020 upon execution of the agreements, and the remaining $70 million will be paid in equal installments during each quarter of 2021. We recorded a loss of approximately $22 million during 2020 associated with the sale of our Free State pipeline, which represents the difference between the proceeds and the net book value of the assets transferred. Refer to Note 4 and Note 7 for additional discussion.
Credit Facility Amendments
On March 25, 2020, we amended our credit agreement. This amendment, among other things, (i) sets the maximum Consolidated Senior Secured Leverage Ratio (as defined in the credit agreement) at 3.25 to 1.00 throughout the remaining term of the facility, and (ii) allows us to purchase certain of our outstanding senior unsecured notes, subject to certain customary conditions.
On July 24, 2020, we further amended our credit agreement. The amendment increases our Consolidated Leverage Ratio from 5.50X to 5.75X from September 30, 2020 through March 31, 2021, after which time it reverts back to 5.50X for the remaining term of the agreement. Additionally, it decreases our Consolidated Interest Coverage Ratio from 3.0X to 2.75X from September 30, 2020 through March 31, 2021, after which time it reverts back to 3.0X for the remaining term of the agreement.
Senior Unsecured Note Transactions
On January 16, 2020, we issued $750.0 million in aggregate principal amount of our 7.75% senior unsecured notes due February 1, 2028 (the “2028 Notes”). Interest payments are due February 1 and August 1 of each year with the initial interest payment due on August 1, 2020. That issuance generated net proceeds of approximately $736.7 million, net of issuance costs incurred. The net proceeds were used to purchase $554.8 million of our existing 6.75% senior unsecured notes due August 1, 2022 (the “2022 Notes”), including the related accrued interest and tender premium on those notes, and the remaining proceeds at the time were used to repay a portion of the borrowings outstanding under our revolving credit facility. On January 17, 2020 we called for redemption the remaining $222.1 million of our 2022 Notes, and they were redeemed on February 16, 2020. We incurred a total loss of approximately $23.5 million relating to the extinguishment of our 2022 Notes, inclusive of our transaction costs and the write-off of the related unamortized debt issuance costs and discount, which is recorded as "Other income (expense)" in our Consolidated Statements of Operations for the year ended December 31, 2020.
On December 17, 2020, we issued $750.0 million in aggregate principal amount of our 8.00% senior unsecured notes due January 15, 2027 (the “2027 Notes”). Interest payments are due January 15 and July 15 of each year with the initial interest payment due on July 15, 2021. That issuance generated net proceeds of approximately $737 million, net of issuance costs incurred. The net proceeds were used to purchase $316.5 million of our existing 6.00% senior unsecured notes due May 15, 2023 (the “2023 Notes”), including the related accrued interest and tender premium and fees on those notes, and the remaining proceeds at the time were used to repay a portion of the borrowings outstanding under our revolving credit facility. We incurred a loss of approximately $8 million relating to the tender of our 2023 Notes, inclusive of our transaction costs and the write-off of the related unamortized debt issuance costs, which is recorded as "Other income (expense)" in our Consolidated Statements of Operations for the year ended December 31, 2020. On January 19, 2021 we redeemed the remaining principal of $80.9 million of our 2023 Notes in accordance with the terms and conditions of the indenture governing the 2023 Notes.
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During the year ended December 31, 2020, we repurchased $153.6 million of certain of our senior unsecured notes on the open market and recorded cancellation of debt income of $27.3 million. This is recorded within "Other income (expense)" in our Consolidated Statements of Operations for the year ended December 31, 2020.
Ownership Structure
We conduct our operations and own our operating assets through subsidiaries and joint ventures. As is customary with publicly traded limited partnerships, Genesis Energy, LLC, our general partner, is responsible for operating our business, including providing all necessary personnel and other resources.
The following chart depicts our organizational structure at December 31, 2020.
Description of Segments and Related Assets
We conduct our businesses through four operating segments: offshore pipeline transportation, sodium minerals and sulfur services, onshore facilities and transportation and marine transportation. These segments are strategic business units that provide a variety of midstream energy-related services as well as soda ash production and sales. Financial information with respect to each of our segments can be found in Note 13 to our Consolidated Financial Statements in Item 8.
We have a diverse portfolio of customers, operations and assets, including pipelines, refinery-related plants, soda ash production facilities and related equipment, trona reserves, storage tanks and terminals, railcars, rail unloading facilities, barges and other vessels, and trucks. Substantially all of our revenues are derived from providing services to refiners, integrated and large independent crude oil and natural gas companies, and large industrial and commercial enterprises, including those that use natural soda ash, NaHS and caustic soda. Our onshore-based operations, excluding those associated with our Alkali Business, occur upstream of, at, and downstream of refinery complexes. Upstream of refineries, we aggregate, purchase, gather and transport crude oil, which we sell to refiners. Within refineries, we provide services to assist in sulfur removal/balancing requirements. Downstream of refineries, we provide transportation services as well as market outlets for finished refined petroleum products and certain refining by-products. Within our Alkali Business, we sell our soda ash and specialty products to a diverse customer base directly in the United States, Canada, the European Community, the European Free Trade Area and the South African Customs Union. We sell through ANSAC exclusively in all other markets.
Offshore Pipeline Transportation
Offshore Crude Oil and Natural Gas Pipelines
We own interests in several crude oil and natural gas pipelines and related infrastructure located offshore in the Gulf of Mexico, a producing region representing approximately 15% of the crude oil production in the U.S. during 2020.
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The table below reflects our interests in our operating offshore crude oil pipelines:
Main Lines
Lateral Lines (2)
Constitution Crude Oil Pipeline Genesis 67 80,000 100 %
(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 and terminals located in Port Arthur and Texas City, Texas. CHOPS also includes two strategically located multi-purpose offshore platforms.
•Poseidon. The Poseidon system is comprised of 16- to 24-inch diameter pipelines to deliver crude oil from developments in the central and western offshore Gulf of Mexico to other pipelines and terminals onshore and offshore Louisiana. An affiliate of Shell owns the remaining 36% interest in Poseidon.
•Odyssey. The Odyssey system is comprised of 12- to 20-inch diameter pipelines to deliver crude oil from developments in the eastern Gulf of Mexico to other pipelines and terminals onshore Louisiana. An affiliate of Shell owns the remaining 71% interest in Odyssey.
•Eugene Island. The Eugene Island system is comprised of a network of crude oil pipelines, the main pipeline of which is 20 inches in diameter, to deliver crude oil from developments in the central Gulf of Mexico to other pipelines and terminals onshore Louisiana. Other owners in Eugene Island include affiliates of Exxon Mobil, ConocoPhillips and Shell Oil Company.
•SEKCO Pipeline. SEKCO is a deepwater pipeline serving the Lucius crude oil and natural gas field, Buckskin oil field and Hadrian North oil field located in the southern Keathley Canyon area of the Gulf of Mexico. SEKCO has crude oil transportation agreements with various Gulf of Mexico producers who have dedicated their production from Lucius, Buckskin and Hadrian North to the pipeline for the life of their reserves.
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•Shenzi Crude Oil Pipeline. The Shenzi Crude Oil Pipeline gathers crude oil production from the Shenzi production field located in the Green Canyon area of the Gulf of Mexico offshore Louisiana for delivery to both our CHOPS and Poseidon pipeline systems.
•Allegheny Crude Oil Pipeline. The Allegheny Crude Oil Pipeline connects the Allegheny and South Timbalier 316 platforms in the Green Canyon area of the Gulf of Mexico with the CHOPS and Poseidon pipelines.
•Marco Polo Crude Oil Pipeline. The Marco Polo Crude Oil Pipeline transports crude oil from our Marco Polo crude oil platform to an interconnect with the Allegheny Crude Oil Pipeline in Green Canyon Block 164.
•Constitution Crude Oil Pipeline. The Constitution Crude Oil Pipeline gathers crude oil from the Constitution, Constellation, Caesar Tonga and Ticonderoga production fields located in the Green Canyon area of the Gulf of Mexico for delivery to either the CHOPS or Poseidon pipelines.
None of our offshore crude oil pipelines are rate regulated with the exception of Eugene Island, which is regulated by the FERC.
The table below reflects our interests in our operating offshore natural gas pipelines:
High Island Offshore System Genesis 238 500 100 %
Anaconda Gathering System Genesis 183 300 100 %
Green Canyon Laterals Genesis 5 108 100%
Manta Ray Offshore Gathering System Enbridge 237 800 25.7 %
(1)Capacity figures presented represent 100% of the design capacity.
•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 152 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: (i) interconnect the offshore pipeline network; (ii) provide an efficient means to perform pipeline maintenance; (iii) locate compression, separation and production handling equipment and similar assets; and (iv) conduct drilling operations during the initial development phase of a crude oil and natural gas property. The results of operations from offshore platform services are primarily dependent upon the level of commodity charges and/or demand-type fees billable to customers. Revenue from commodity charges is based on a fee per unit of volume delivered to the platform (typically per MMcf of natural gas or per barrel of crude oil) multiplied by the total volume of each product delivered. Demand-type fees are similar to firm capacity reservation agreements for a pipeline in that they are charged to a customer regardless of the volume the customer actually delivers to the platform. Contracts for platform services often include both 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.
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The table below reflects our interests in our operating offshore hub platforms:
(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.
Competition
The principal competition for our offshore pipelines includes other crude oil and natural gas pipeline systems as well as producers who may elect to build or utilize their own production handling facilities. Our offshore pipelines compete for new production on the basis of geographic proximity to the production, cost of connection, available capacity, transportation rates and access to onshore markets. In addition, the ability of our offshore pipelines to access future reserves will be subject to our ability, or the producers’ ability, to fund the significant capital expenditures required to connect to the new production. In general, most of our offshore pipelines are not subject to regulatory rate-making authority, and the rates our offshore pipelines charge for services are dependent on the quality of the service required by the customer and the amount and term of the reserve commitment by that customer.
Sodium Minerals and Sulfur Services
Our Sodium Minerals and Sulfur Services segment consists of our Alkali Business and our sulfur removal business as discussed in further detail below.
Alkali Business
Our Alkali Business is one of the leading producers of natural soda ash worldwide. We provide our soda ash to a variety of industries such as flat glass, container glass, detergent and chemical manufacturing. Soda ash, also known by its chemical name sodium carbonate (Na2CO3), is a highly valued raw material in the manufacture of glass due to its properties of lowering the melting point of silica in the batch. Soda ash is also valued by detergent manufacturers for its absorptive and water softening properties. We produce our products from trona, which we mine at two sites in the Green River Basin in Wyoming. The vast majority of the world’s accessible trona reserves are located in the Green River Basin. According to historical production statistics, approximately 30% of global soda ash is produced from trona or similar sodium carbonate containing materials, with the remainder being produced synthetically, which requires chemical transformation of limestone and salt using a significantly higher amount of energy. Production of soda ash from trona is significantly less expensive than producing it
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synthetically. In addition, life-cycle analyses reveal that production from trona consumes less energy and produces less carbon dioxide and fewer undesirable by-products than synthetic production.
Our Alkali Business includes the following:
•Dry mining of trona ore underground at our Westvaco facility;
•Secondary recovery of trona from previously dry mined areas underground at our Westvaco and Granger facilities through solution mining;
•Processing of raw trona ore into soda ash and specialty sodium alkali products; and
•Marketing, sale and distribution of alkali products.
Our Alkali Business has the ability to produce approximately 4 million tons of soda ash and downstream specialty products annually. All mining and processing activities related to our products take place in our facilities located in the Green River Basin.
Dry Mining of Trona Ore
Trona is dry mined underground at our Westvaco facility primarily through the operation of our single longwall mining machine. Longwall mining provides higher recovery rates leading to extended mine life compared to other dry mining techniques. Development of the “tunnels” necessary to access and ventilate our longwall is through room and pillar mining completed primarily by our fleet of borer miners. The ore is conveyed underground to two hoisting operations where it travels about 1,600 feet vertically to the surface and is either taken directly into the processing facilities or stored on outdoor stockpiles for future consumption.
Secondary Recovery Solution Mining
We solution mine trona at both our Westvaco and Granger sites using secondary recovery techniques. Our secondary recovery mining starts with the recovery of water streams from our operations and non-trona solids (“insolubles”) remaining from the processing of dry mined trona. The water and some insolubles are injected through a number of wells into the old dry mine workings at both our Westvaco and Granger sites. The insolubles settle out while the water travels through the old workings, dissolving trona that remained during previous dry mining. Multiple pumping systems are used to pump the enriched solution to the surface for processing.
Processing of Trona into Finished Alkali Products
Our Sesqui and Mono plants, located at our Westvaco site, convert dry-mined trona into soda ash. Crushing, dissolution in water, filtration, and crystallization techniques are used to produce the desired final products. In the Mono process, the ore is calcined with heat, prior to dissolution, to convert the trona to soda ash by the removal of water and carbon dioxide. A final drying step using steam produces a dense soda ash product from the Mono process. In our Sesqui plant, the calcination is performed at the end of the process, producing a light density soda ash that is preferred in applications desiring increased absorptivity. The Sesqui process also has the ability to produce refined sodium sesquicarbonate (which we sell under the names S-Carb ® and SesquiTM) for use as a buffer in animal feed formulations and in cleaning and personal care applications.
Solution mined trona is converted into dense soda ash in our ELDM operation at the Westvaco site and at our Granger facility. The steps to produce soda ash are similar to the dry mined processes, except the crushing and dissolving steps are eliminated because the trona is already in a water solution as it leaves the mine.
Intermediate, semi-processed products are extracted from our soda ash processes at Westvaco at strategic locations for use as feedstocks for production of sodium bicarbonate and 50% caustic soda (NaOH).
Marketing, Sale and Distribution of Alkali Products
We sell our alkali products to customers directly in the United States, Canada, the European Community, the European Free Trade Area and the South African Customs Union. We sell through ANSAC exclusively in all other markets. ANSAC is a nonprofit foreign sales association in which we and two other U.S. soda ash producers were members during 2020, whose purpose is to promote export sales of U.S. produced soda ash in conformity with the Webb-Pomerene Act.
All of our alkali products are shipped by rail and truck from our facilities in the Green River Basin. We operate a fleet of approximately 3,600 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
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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, with the exception of a slight decline in mid-2020 due to economic shutdowns related to Covid-19 (which began to recover during the end of the third quarter and throughout the remainder of 2020). Sales of soda ash in rapidly developing economies have grown more rapidly as a growing middle class demands more products that use soda ash, such as glass for housing and autos and detergents for cleaning.
In addition, we also market sodium bicarbonate to private label manufacturers who package it for sale to retail grocery customers as baking soda. We also sell sodium bicarbonate to manufacturers of packaged baked goods and similar products. Animal feed is an important market for sodium bicarbonate, which is mixed with feed to increase the yield of dairy cows and improve the health of poultry and other livestock. Sodium bicarbonate is also sold to customers who use it in hemodialysis applications and as an active ingredient in pharmaceutical products.
Sulfur Removal Business
Our sulfur services business primarily (i) provides sulfur-extraction services to ten refining operations located mostly in Texas, Louisiana, Arkansas, Oklahoma, Montana and Utah, (ii) operates significant storage and transportation assets in relation to those services and (iii) sells NaHS and caustic soda to large industrial and commercial companies. Our sulfur removal services primarily involve processing refiners' high sulfur (or “sour”) gas streams that the refineries have generated from crude oil processing operations. Our process applies our proprietary technology, which uses large quantities of caustic soda (the primary raw material used in our process) to act as a scrubbing agent under prescribed temperature and pressure to remove sulfur. Sulfur removal in a refinery is a key factor in optimizing production of refined products such as gasoline, diesel and aviation fuel. Our sulfur removal technology returns a clean (sulfur-free) hydrocarbon stream to the refinery for further processing into refined products, and simultaneously produces NaHS. The resultant NaHS constitutes the sole consideration we receive for our sulfur removal services. A majority of the NaHS we receive is sourced from refineries owned and operated by large companies, including Phillips 66, CITGO, HollyFrontier, Calumet and Ergon. Our ten sulfur removal services contracts have an average remaining term of approximately three years. This includes the extended term of our renegotiated sulfur removal services contract with Phillips 66 at our Westlake, Louisiana facility, which 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 130 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 the pulp and paper business, and in connection with mining operations (nickel, gold and separating copper from molybdenum) as well as bauxite refining (aluminum). NaHS has also gained acceptance in environmental applications, including waste treatment programs requiring stabilization and reduction of heavy and toxic metals and flue gas scrubbing. Additionally, NaHS can be used for removing hair from hides at the beginning of the tannery process.
Caustic soda is used in many of the same industries as NaHS. Many applications require both chemicals for use in the same process. For example, caustic soda can increase the yields in bauxite refining, pulp manufacturing and in the recovery of copper, gold and nickel. Caustic soda is also used as a cleaning agent (when combined with water and heated) for process equipment and storage tanks at refineries.
Customers
Our natural soda ash is sold to a diverse customer base in the United States, Canada, the European Community, the European Free Trade Area and the South African Customs Union. Our Alkali Business sells exclusively through the American Natural Soda Ash Corporation, or ANSAC, in all other markets. ANSAC is a nonprofit foreign sales association in which our Alkali Business and two other U.S. soda ash producers were members during 2020. The other ANSAC members have given notice that they will exit ANSAC in 2021 and 2022, respectively. 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.
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.
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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 NaHS to South America for sale to customers for mining in Peru and Chile. No sulfur removal customer or NaHS sales customer is responsible for more than ten percent of our consolidated revenues. Many of the industries that our NaHS customers are in (such as copper mining and the pulp and paper industry) participate in global markets for their products. As a result, this creates an indirect exposure for NaHS to global demand for the end products of our customers. Provisions in our service contracts with refiners allow us to adjust our sour gas processing rates (sulfur removal) to maintain a balance between NaHS supply and demand.
We sell caustic soda to many of the same customers who purchase NaHS from us, including pulp and paper manufacturers and customers in the copper mining industry. We also supply caustic soda to some of the refineries in which we operate for use in cleaning processing equipment.
Competition- Alkali Business
The global soda ash market which our Alkali Business operates in is competitive. Competition is based on a number of factors such as price, favorable logistics and consistent customer service. In North America, primary competition is from other U.S.-based natural soda ash operations: Solvay Chemicals, Ciner Resources, L.P., and Tata Chemicals Soda Ash Partners in Wyoming, and Searles Valley Minerals in California. Because of the structural cost advantages of natural soda ash production in the United States, including lower raw material and energy requirements, imports have not been an important source of competition in North America. According to IHS, on average, the cash cost to produce material soda ash has been about half 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, and beginning in 2021, other U.S.-based natural soda ash operations. 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, with the exception of a slight decline in mid-2020 due to economic shutdowns related to Covid-19 (which began to recover during the end of the third quarter and throughout the remainder of 2020). 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 27% of total sales in the sodium minerals and sulfur services segment. Apart from ANSAC, our sodium minerals and sulfur services segment is not dependent on any single or small group of customers, the loss of one of which would not have a material adverse effect on us.
Competition- Sulfur Services
Our competitors for the supply of NaHS consist primarily of parties who produce NaHS as a by-product of or an alternative to other sulfur derivative products, including fertilizers, pesticides, other agricultural products, plastic additives and lubricants. Typically our competitors for the supply of NaHS have only one location and they do not have the logistical infrastructure that we have to supply customers. These competitors often reduce NaHS production when demand for their alternative sulfur derivatives is high and increase NaHS production when demand for these alternatives is low. Also, they tend to supply less when prices and demand for elemental sulfur are higher and supply more NaHS when the price of elemental sulfur falls.
Demand for NaHS faces competition from alternative sulfidity management mediums such as sulfidic caustic, emulsified sulfur, salt cake and flake NaHS. Changes in the value, supply and/or demand of these alternative products can impact the volume and/or value of our NaHS sold.
Typically, our competitors for sulfur removal services include refineries themselves through the use of their sulfur removal processes.
Our competitors for sales of caustic soda include manufacturers of caustic soda. These competitors supply caustic soda to our sodium minerals and sulfur services operations and support us in our third-party caustic soda sales. By utilizing our storage capabilities and having access to transportation assets, we sell caustic soda to third parties who gain efficiencies from acquiring both NaHS and caustic soda from one source.
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Onshore Facilities and Transportation
We provide onshore facilities and transportation services to Gulf Coast crude oil refineries and producers through a combination of purchasing, transporting, storing, blending and marketing of crude oil and refined products (primarily fuel oil, asphalt, and other heavy refined products). In connection with these services, we utilize our increasingly integrated portfolio of logistical assets consisting of pipelines, trucks, terminals, railcars and barges. The increasingly integrated nature of our onshore facilities and transportation assets is particularly evident in areas such as Louisiana and Texas. Our crude oil related services include gathering crude oil from producers at the wellhead, transporting crude oil by gathering line, truck, railcar and barge to pipeline injection points, transporting crude oil for our gathering and marketing operations and for other shippers on our pipelines and marketing crude oil to refiners. Not unlike our crude oil operations, we also gather refined products from refineries, transport refined products via pipeline, truck, railcar and barge, and sell refined products to customers in wholesale markets. For certain of these services, we generate fee-based income related to the transportation services provided. In some cases, we also profit from the difference between the price at which we re-sell the crude oil and petroleum products less the price at which we purchase the crude oil and products, minus the associated costs of aggregation and transportation.
Our crude oil onshore facilities and transportation operations are concentrated in Texas, Louisiana, Alabama, Florida and Mississippi. These operations help to ensure (among other things) a base supply source for our crude oil pipeline systems, refinery customers and other shippers while providing our producer customers with a market outlet for their production. By utilizing our network of pipelines, trucks, railcars, barges, and terminals, we are able to provide transportation related services to, and in many cases back-to-back gathering and marketing arrangements with, crude oil refiners and producers. Additionally, our crude oil and petroleum product 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 27,000 barrels per day (as of December 31, 2020) of crude oil and petroleum products, 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 as 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
Rate Regulated FERC/TXRRC FERC FERC FERC
•Texas System. Our Texas System transports crude oil from Hastings Junction (south of Houston) to several delivery points near Houston, Texas (including our Webster, Texas facility). This system also takes delivery of crude oil volumes at Texas City (which includes the capability of receiving various Gulf of Mexico pipeline volumes) for delivery to our Webster, Texas facility, which ultimately connects to other crude oil pipelines. We earn a tariff for our transportation services, with the tariff rate per barrel of crude oil varying with the distance from injection point to delivery point.
•Jay System. Our Jay System provides crude oil shippers access to refineries, pipelines and storage near Mobile, Alabama. That system also includes gathering connections to approximately 38 wells, additional crude oil storage capacity of approximately 20,000 barrels in the field, an interconnect with our Walnut Hill rail facility, a delivery connection to a refinery in Alabama and an interconnection to another common carrier pipeline that delivers crude oil into Mississippi.
•Mississippi System. Our Mississippi System provides shippers of crude oil in Mississippi indirect access to refineries, pipelines, storage, terminals and other crude oil infrastructure located in the Midwest. That system is adjacent to several crude oil fields that are in various phases of being produced through tertiary recovery strategy, including CO2 injection and flooding. We provide transportation services on our Mississippi pipeline through an “incentive” tariff which provides that the average rate per barrel that we charge during any month decreases as our aggregate throughput for that month increases above specified thresholds.
•Louisiana System. Our Louisiana System transports crude oil from Port Hudson to our Baton Rouge Scenic Station rail unloading facility and continues downstream to the Anchorage Tank Farm servicing Exxon Mobil Corporation's Baton Rouge refinery. This refinery is one of the largest refinery complexes in North America, with more than 500,000 barrels per day of refining capacity. Our Louisiana system also connects the Anchorage Tank Farm to our Port of Baton Rouge Terminal (which was also built to service Exxon's Baton Rouge refinery), allowing bidirectional flow of crude oil, intermediates and refined products between the Anchorage Tank Farm and this terminal via a dedicated crude pipeline and a dedicated intermediates pipeline. Total daily volume for the year ended December 31, 2020 includes 26,708 barrels per day of intermediate refined products associated with our Port of Baton Rouge Terminal pipelines. 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 unloading railcars at these facilities. Three of these facilities, our Baton Rouge, Louisiana, Raceland, Louisiana, and Walnut Hill, Florida facilities are directly connected to our existing integrated crude oil pipeline and terminal infrastructure.
Within our onshore facilities and transportation business segment, we employ many types of logistically flexible assets. These assets include a suite of trucks, trailers, crude oil railcars, as well as terminals and other tankage with approximately 4.2 million barrels of leased and owned storage capacity in multiple locations along the Gulf Coast, accessible by pipeline, truck, rail or barge, in addition to tankage related to our crude oil pipelines, previously mentioned.
Our refined products onshore facilities and transportation operations are concentrated in the Gulf Coast region, principally Texas and Louisiana. Through our footprint of owned and leased pipelines, trucks, leased railcars, terminals and barges, we are able to provide Gulf Coast area refineries with transportation services as well as market outlets for certain heavy refined products. We primarily engage in the transportation and supply of fuel oil, asphalt, and other heavy refined products to our customers in wholesale markets. We have the ability from time to time to obtain various grades of refined products from our refinery customers and blend them to meet the requirements of our other market customers. However, because our refinery customers may choose to manufacture such refined products based on a number of economic and operating factors, we cannot predict the timing of contribution margins related to our blending services.
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.
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 production.
In our refined products onshore facilities and transportation operations, we compete primarily with regional companies. See "Marine Transportation - Competition" for additional discussion of our competitors. Competitive factors in our onshore facilities and transportation business include price, relationships with customers, range and quality of services, knowledge of products and markets, availability of trade credit and capabilities of risk management systems.
Marine Transportation
Our marine transportation segment consists of (i) our inland marine fleet which transports heavy refined petroleum products, including asphalt, principally serving refineries and storage terminals along the Gulf Coast, Intracoastal Canal and western river systems of the U.S., principally along the Mississippi River and its tributaries, (ii) our offshore marine fleet which transports crude oil and refined petroleum products, principally serving refineries and storage terminals along the Gulf Coast, Eastern Seaboard, Great Lakes and Caribbean, and (iii) our modern double-hulled, Jones Act qualified tanker M/T American Phoenix which is currently under charter serving a customer along the Gulf Coast and Eastern Seaboard. The below table includes operational information relating to our marine transportation fleet:
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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 —
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 large energy companies. Our M/T American Phoenix is currently operating under a charter with a 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 2020 and 2019. 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 2020 and 2019, approximately 63% and 65%, respectively, of our marine transportation revenues were from term contracts and 37% and 35%, respectively, were from spot contracts.
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.
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,
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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, and 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, Occidental Petroleum and ANSAC.
Human Capital
We believe our employees are our most important asset and the cornerstone of our organization. We take steps to attract and retain talented people to safely operate our assets, foster customer relationships, and achieve our long-term goals. We are committed to employee retention and we encourage our employees to maintain long-term careers with us. Human capital measures and objectives which we focus on in managing our business include safety, employee compensation and benefits, diversity and inclusion, and employee development.
Employees and Collective Bargaining Agreements
To carry out our business activities, we employed approximately 1,914 employees at December 31, 2020. Approximately 600 of those employees were covered under collective bargaining agreements. These collective bargaining agreements cover wage increases and other benefits, including the defined benefit pension plan, the post-employment benefit plan and the enhanced 401(k) retirement savings plan. We consider our relationship with the union strong, and our relationship with our employees, including those covered by collective bargaining agreements, to be in good standing.
Safety
Safety is one of our guiding principles and it is our intention to create and sustain a workplace free from recognized safety and health hazards. We have implemented safety programs and management practices to promote a culture of safety, which include policies, training, procedures, audits, inspections, incident evaluations, data analysis, reporting, and communications. We also established annual safety and health targets for total recordable injury and illness rates, and tied a portion of our management compensation to safety related goals to emphasize the importance of safety at the Company.
Our emphasis on safety extends to our approach to managing the risk of operational disruptions related to Covid-19. We have a designated internal management team to provide resources, updates, and support to our entire workforce during this pandemic, while maintaining a focus to ensure the safety and well-being of our employees, the families of our employees, and the communities in which our businesses operate.
Employee Compensation and Benefits
Our compensation programs are integrated with our overall business strategies and management processes to incentivize performance, maximize returns, and build shareholder value. We participate in market surveys as well as work with consultants to benchmark our compensation and benefits programs to help us offer competitive remuneration packages to attract and retain high-performing employees.
Further, to attract and meet the needs of our workforce, we offer a comprehensive and affordable benefits program that includes medical, dental, vision, life insurance, and disability protection, along with a generous retirement savings plan, including up to six percent matching. Our benefits package options may vary depending on the type of employee and date of hire. Additionally, we continuously look for ways to improve employee work-life balance and the well-being of our employees and their families.
Diversity and Inclusion
We are an equal opportunity employer. We believe that eliminating barriers to employment results in a more plentiful recruiting pool, diverse perspectives to problem solving, and stronger teams. We maintain a positive work environment by striving to create a strong culture of diversity and inclusion, supported by both our Code of Business Conduct and our employment practices.
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We have policies in place that reinforce our commitment to diversity and inclusion within the workplace. Our employee handbook includes equal employment opportunity commitments and nondiscrimination and anti-harassment disclosures, which communicate our expectations with respect to maintaining a professional workplace free of harassment. We prohibit discrimination or harassment against any employee or applicant on the basis of sex, race, ethnicity, or any other protected categories. We are committed to a harassment free workplace, which is further supported through prevention training we provide for employees.
Employee Development
Our success as a company is measured by the successful performance of our employees in their respective roles. Thus, it is our policy to properly train and equip each employee to perform his or her job functions safely and in compliance with all laws, regulations, and internal procedures.
We develop our employees through performance management processes, regular coaching and supervisory and leadership training while also offering a tuition reimbursement program. Our annual performance management cycle enables managers and employees to collaborate to set performance goals and development objectives that align to business objectives. We also provide in-house health and safety training and emergency response training. Employee attendance at external workshops, conferences and other training events is also encouraged.
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.
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.
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.
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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 unloading facilities and lease a significant number of railcars. Our railcar operations are subject to the regulatory jurisdiction of the Federal Railroad Administration of the DOT, the Occupational Safety and Health Administration, or OSHA, as well as other federal and state regulatory agencies. We believe that our railcar operations are in substantial compliance with all existing federal, state and local regulations.
DOT and OSHA have jurisdiction under several federal statutes over a number of safety and health aspects of rail operations, including the transportation of hazardous materials. State agencies regulate some aspects of rail operations with respect to health and safety in areas not otherwise preempted by federal law.
Regulation of the Mining Industry in the United States
We have the right to mine trona through leases we hold from the U.S. Federal government, the State of Wyoming and Occidental. Our leases with the U.S. government are issued under the provisions of the Mineral Leasing Act of 1920 (30 U.S.C. 18 et. Seq.) and are administered by the U.S. Bureau of Land Management (“BLM”) and our leases with the state of Wyoming are issued under Wyoming Statutes 36-6-101 et. seq. Occidental is the successor to rights originally granted to the Union Pacific Railroad in connection with the construction of the first transcontinental railroad in North America. For more information please see discussion of Mining and Mineral Tenure in Item 1 below.
We pay royalties to the BLM, the State of Wyoming and Occidental. These royalties are calculated based upon the gross value of soda ash and related products at a certain stage in the mining process. We are obligated to pay minimum royalties or annual rentals to our lessors regardless of actual sales and in the case of Occidental to pay royalties in advance based on a formula based on the amount of trona produced and sold in the previous year which is then credited against production royalties owed. The royalty rates we pay to our lessors may change upon our renewal of such leases; however, we anticipate being able to renew all material leases at the appropriate time. In the past, the U.S. Congress has passed legislation to cap royalties collected by BLM at a rate lower than the rate stated in our federal leases.
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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, 2020, the amount of our reclamation bonds totaled to approximately $80 million. The amount of the bonds are 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 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
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or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.
We also may incur liability under the Resource Conservation and Recovery Act, as amended, or RCRA, and analogous state laws which impose requirements and also liability relating to the management and disposal of solid and hazardous wastes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. Certain petroleum production wastes are excluded from RCRA’s hazardous waste regulations. However, it is possible that these wastes, which could include wastes currently generated during our operations, will in the future be designated as “hazardous wastes” and, therefore, be subject to more rigorous and costly disposal requirements. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain crude oil and natural gas exploration and production wastes as “hazardous wastes.” Also, in December 2016, the EPA agreed in a consent decree to review its regulation of oil and gas waste. However, in April 2019, the EPA concluded that revisions to the federal regulations for the management of oil and gas waste are not necessary at this time. Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.
We believe that we are in substantial compliance with the requirements of CERCLA, RCRA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations required under such laws and regulations. Although we believe that the current costs of managing our wastes as they are presently classified are reflected in our budget, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.
Water Discharges
The Federal Water Pollution Control Act, as amended, also known as the “Clean Water Act,” and analogous state laws impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including crude oil, into navigable waters of the U.S., as well as state waters. Permits must be obtained to discharge pollutants into these waters. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. On June 29, 2015, the EPA and the U.S. Army Corps of Engineers, or Corps, jointly promulgated final rules redefining the scope of waters protected under the Clean Water Act. However, on October 22, 2019, the agencies repealed the 2015 rules. Both the 2015 rules and the 2019 repeal are subject to ongoing legal challenges. Also, on April 21, 2020, the EPA and the Corps published a final rule replacing the 2015 rules, and significantly reducing the waters subject to federal regulation under the Clean Water Act. Several states and environmental groups have challenged the replacement rule. As a result of such recent developments, substantial uncertainty exists regarding the scope of waters protected under the Clean Water Act. To the extent the rules expand the range of properties subject to the Clean Water Act's jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.
Also, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.
The Oil Pollution Act is the primary federal law for oil spill liability. The Oil Pollution Act contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The Oil Pollution Act subjects owners of facilities to strict liability that, in some circumstances, may be joint and several for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters.
Noncompliance with the Clean Water Act or the Oil Pollution Act may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with each of these requirements.
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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, the Trump Administration 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 August 13, 2020, the EPA issued amendments to the 2012 and 2016 New Source Performance standards to ease regulatory burdens, including rescinding standards applicable to transmission or storage segments and eliminating methane requirements altogether. Various state, municipal, and environmental groups have challenged the amendments, and, on January 20, 2021, President Biden issued an executive order directing the EPA to review the amendments consistent with several policy objectives, including reducing greenhouse gas emissions. Thus substantial uncertainty exists regarding the scope of New Source Performance standards for oil and natural gas operations. These standards, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions.
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. The designation of previously unidentified endangered or threatened species in areas where we operate could cause us to incur additional costs or become subject to operating delays, restrictions or bans.
Climate Change
In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases ("GHGs") present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Accordingly, in recent years, federal, state, and local governments have taken steps to reduce emissions of GHGs. The EPA has finalized a series of GHG monitoring, reporting and emission control rules for the oil and natural gas industry and the U.S. Congress has from time to time considered various proposals to reduce GHG emissions. Almost half of the states, either individually or through multi-state regional initiatives, have already taken legal measures to reduce GHG emissions, primarily through the planned development of GHG emission inventories and/or GHG cap-and-trade programs. In addition, states have imposed increasingly stringent requirements related to the venting or flaring of gas during oil and gas operations. The net effect of this regulatory regime is to impose increasing costs on the combustion of carbon-based fuels such as crude oil, refined petroleum products and natural gas.
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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. Although the United States withdrew from the Paris Agreement, effective November 4, 2020, President Biden issued an Executive Order on January 20, 2021 to rejoin the Paris Agreement, which took effect on February 19, 2021. The United States has indicated its plan to announce in advance of an April 22, 2021 climate summit, its nationally determined contribution, or its commitment to reduce its national GHG emissions to meet this objective. Furthermore, many state and local leaders have stated their intent to intensify efforts to support the commitments set forth in the international accord.
Legislative efforts or related implementation regulations that regulate or restrict emissions of GHGs in areas that we conduct business could adversely affect the demand for the products that we transport, store and distribute and, depending on the particular program adopted, could increase our costs to operate and maintain our facilities by requiring that we, among other things, measure and report our emissions, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay any taxes related to our GHG emissions and administer and manage a GHG emissions program. We may be unable to include some or all of such increased costs in the rates charged by our pipelines or other facilities, and any such recovery may depend on events beyond our control, including the outcome of future rate proceedings before the FERC or state regulatory agencies and the provisions of any final legislation or implementing regulations. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby adversely affect demand for the crude oil and natural gas that we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations. It is not possible at this time to predict with any accuracy the structure or outcome of any future legislative or regulatory efforts to address such emissions or the eventual costs to us of compliance.
Furthermore, there have been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and 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, 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 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
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intervals and periodically evaluate the integrity of each pipeline segment that could affect a HCA. The integrity of these pipelines must be assessed by internal inspection, pressure test, or equivalent alternative new technology.
The IM regulations required us to prepare an Integrity Management Plan, or IMP, that details the risk assessment factors, the overall risk rating for each segment of pipe, a schedule for completing the integrity assessment, the methods to assess pipeline integrity, and an explanation of the assessment methods selected. The regulations also require periodic review of HCA pipeline segments to ensure that adequate preventative and mitigative measures exist and that companies take prompt action to address pipeline integrity issues. No assurance can be given that the cost of testing and the required rehabilitation identified will not be material costs to us that may not be fully recoverable by tariff increases.
Recently, the PHMSA adopted additional regulations for natural gas and hazardous liquid pipeline safety. In particular, on October 1, 2019, the PHMSA published final rules to expand its IM requirements and impose new pressure testing requirements on regulated pipelines, including certain segments outside HCAs. Many of the requirements will be phased in over an extended compliance schedule. Once effective, the rules also extend reporting requirements to certain previously unregulated hazardous liquid gravity and rural gathering lines. Additional rulemakings are anticipated, including rulemakings to adjust repair criteria for gas transmission lines, to require inspection of gas pipelines following extreme events, and to extend regulatory safety requirements to certain gas gathering lines.
We have developed a Risk Management Plan required by the EPA as part of our IMP. This plan is intended to minimize the offsite consequences of catastrophic spills. As part of this program, we have developed a mapping program. This mapping program identified HCAs and unusually sensitive areas along the pipeline right-of-ways in addition to mapping of shorelines to characterize the potential impact of a spill of crude oil on waterways.
Our crude oil, refined products and sodium minerals and sulfur services operations are also subject to the requirements of OSHA and comparable state statutes. Various other federal and state regulations require that we train all operations employees in Hazardous Communication ("HAZCOM") and disclose information about the hazardous materials used in our operations. Certain information must be reported to employees, government agencies and local citizens upon request.
In most cases, states are responsible for enforcing the federal regulations and more stringent state pipeline regulations and inspection with respect to intrastate hazardous liquids pipelines, including crude oil and natural gas pipelines. In practice, states vary considerably in their authority and capacity to address pipeline safety. The Railroad Commission recently updated its pipeline safety regulations, including regulations pertaining to certain natural gas gathering lines, and hazardous liquids pipelines located in a rural area, effective January 6, 2020. We do not anticipate any significant problems in complying with applicable state laws and regulations in those states in which we operate.
Our trucking operations are licensed to perform both intrastate and interstate motor carrier services. As a motor carrier, we are subject to certain safety regulations issued by the DOT. The trucking regulations cover, among other things, driver operations, log book maintenance, truck manifest preparations, safety placard placement on the trucks and trailer vehicles, drug and alcohol testing, operation and equipment safety and many other aspects of truck operations. We are also subject to OSHA with respect to our trucking operations.
The USCG regulates occupational health standards related to our marine operations. Shore-side operations are subject to the regulations of OSHA and comparable state statutes. The Maritime Transportation Security Act requires, among other things, submission to and approval of the USCG of vessel security plans.
Since the terrorist attacks of September 11, 2001, the U.S. Government has issued numerous warnings that energy assets could be the subject of future terrorist attacks. We have instituted security measures and procedures in conformity with federal guidance. We will institute, as appropriate, additional security measures or procedures indicated by the federal government. None of these measures or procedures should be construed as a guarantee that our assets are protected in the event of a terrorist attack.
Reporting of Ore Reserve and Mineral Resources
As of December 31, 2020, we had estimated mineral ore reserves in our Alkali Business. Our Alkali Business extracts trona, a natural hydrous sodium carbonate mineral used in the production of soda ash in the Green River Basin of southwestern Wyoming, USA. Soda ash, the commercial term for sodium carbonate (Na2CO3), is a basic ingredient in many consumer goods and a raw material used in a diversity of manufacturing processes.
U.S. registrants are required to report ore reserves under SEC Industry Guide 7, “Description of Property by Issuers Engaged or To Be Engaged in Significant Mining Operations.” Industry Guide 7 requires that sufficient technical and economic studies have been completed to reasonably assure economic extraction of the declared reserves, based on the parameters and assumptions current to the end of the reporting period.
We base our mineral reserve estimates on detailed geological, geotechnical, mine engineering and mineral processing inputs, and financial models developed and reviewed by employees/management of our Alkali Business, who possess years of
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experience directly related to the resources, mining and processing characteristics or financial performance of our operations. Additionally, our management and technical staff includes senior personnel who have remained closely involved with each of our active mining and mineral processing operations.
In preparing our reserve estimates for our Alkali operations at Green River, Wyoming, we follow accepted mining industry practice and are guided by our long-term experience in extraction of trona ore from underground mining and sodium carbonate from solution mining in the district. Estimates of recoverable reserves for both techniques are routinely reconciled with actual production, and our Alkali ore reserves disclosures comply with SEC Industry Guide 7.
Under SEC Industry Guide 7, Proven reserves are the highest category of ore reserve estimates, whereby the quantity and quality have been computed from detailed sampling and modeling, while Probable reserves provide slightly lower geologic assurance.
Mineral Tenure - Wyoming
SEC Industry Guide 7 requires us to describe our rights to access and mine the minerals we report as ore reserves and to disclose any change in mineral tenure of material significance. Our trona mining operations in Wyoming USA are secured through private and federal government leases, regulated by the BLM and WDEQ. All of our exploration and mining operations are subject to multiple levels of environmental regulatory review, that include approvals of environmental programs and public comment periods as pre-conditions to granting of mineral tenure. General descriptions of the rights and regulatory framework for minerals of relevance to Alkali follow here.
Ownership of land and minerals relative to trona beds in the Green River Basin of southwestern Wyoming is divided between the Federal Government (56%), Occidental (38%) and the State of Wyoming (6%). Occidental recently acquired Anadarko Petroleum Corporation ("Anadarko"), which was inclusive of the ownership Anadarko acquired in 2000 of the Union Pacific Resources Group (“UPRG”) and included the land and mineral ownership originally granted to UPRG’s parent company, the Union Pacific Railroad in connection with the construction of the first transcontinental railroad in North America.
Leasing of Federal minerals under 41 Stat. 437, 30 U.S. Code § 124 (Section 23), “Agricultural entry or purchase of lands withdrawn or classified as containing sodium or sulphur,” is authorized by the Mineral Leasing Act of February 25, 1920, and subsequent amendments. The U.S. Government’s interests are administered by the BLM which has designated an area of 700,000 acres (283,280 hectares) as the Known Sodium Leasing Area (“KSLA”). In 1993, the BLM established a Mechanical Mining Trona Area (“MMTA”) within the KSLA and suspended oil and gas leasing within the boundary. Our mineral tenure and assets at Green River are strengthened by the KSLA and MMTA.
Mineral leasing authority by the State of Wyoming is granted in W.S. 36-6-101(b). The primary environmental regulatory authority with respect to trona extraction is the WDEQ. The WDEQ is the primary issuer of the environmental permits relevant to our operations, including air quality permits, mining and reclamation permits, as well as class III and class V underground injection control permits.
Alkali Business - Green River, Wyoming
Our Alkali Business is one of the world’s leading producers of natural soda ash. Natural soda ash is refined from trona, a sodium carbonate mineral composed of soda ash (Na2CO3), sodium bicarbonate (NaHCO3) and water with the chemical formula Na2CO3NaHCO32H2O. Approximately 60% of the world’s natural soda ash is produced from trona extracted from underground mines and solution mining in the Green River Basin of southwestern Wyoming.
The Green River trona beds are collectively the largest deposit of trona and the undisputed largest source of raw material feed for the production of natural soda ash in the world. The origin of the trona deposits is the result of very unusual, geological circumstances. Sodium-rich springs are believed to have fed ancient Lake Gosiute, a large, shallow inland lake that reached a maximum extent of over 15,000 square miles (about 40,000 sq km) around 50 million years ago. In response to repetitive cycles of lake expansion, contraction and evaporation, and changes in temperature and salinity, trona was precipitated in beds of remarkable purity and extent. In addition to trona, the evaporite sodium mineral assemblage includes variable levels of other sodium carbonate minerals as well as halite (NaCl). At least 25 beds of natural trona in the Wilkins Peak Member of the Eocene Green River Formation exceed at least locally three feet (1 m) in thickness and are estimated by the USGS to contain a cumulative resource of over 100 billion tons of trona. Individual trona beds are numbered in ascending order and trona beds of significance lie at modern depths between about 400 to 2,000 feet (120-600 m). Our current dry mining and solution mining operations exploit three trona beds, and our reserves are contained in four beds.
Our trona resources and mining operations are held under leases covering 86,997 acres (equivalent to 136 sq miles or 351 sq kilometers) over portions of 23 townships, primarily in two contiguous units informally known as the “Westvaco” and “Granger” blocks. Mineral and mining rights are secured by leases from the Federal government, the State of Wyoming, and Occidental Petroleum. We lease approximately 25,215 acres from the U.S. Government under the Mineral Leasing Act of 1920 (Title 30 §181) which includes trona under its definition of a “solid leasable mineral.” Federal minerals are administered by the
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U.S. Bureau of Land Management (BLM). We lease 40,819 acres from Occidental, formerly Anadarko Land Corporation. Anadarko’s acquisition of the UPRG in 2000 included alternate sections of land for 20 miles on either side of the trans-continental railroad, originally granted to UPRG under the Pacific Railroad Act of 1862 and subsequent railroad land grants. We also lease 20,963 acres from the State of Wyoming. Royalty payments range from 6% to 8% of the sales value of soda ash products.
Our Westvaco site is located approximately 25 miles (40-65 km) north-northwest of Green River. We extract trona ore from our Westvaco underground mine by mechanized, continuous mining methods. Our current underground dry mine production is from a single, near-horizontal bed approximately 10 feet (3.05 meters) thick at a depth from surface of 1500-1600 feet (450-490 meters). Ore is extracted from an extensive network of parallel drifts and connecting cross-cuts, known as room-and-pillar mining, and from longwall mining. Longwall miners shear off successive panels of ore which drops onto a conveyor belt for delivery to vertical shafts to be hoisted to the surface. The Westvaco mine has been in uninterrupted, continuous operation since its start in 1947 by Westvaco Chemical Company. The Westvaco interests were acquired by FMC in 1948.
We also extract trona by secondary recovery solution mining operations in previously dry mined portions of the Westvaco mine and in trona beds impacted by former dry mining of the Granger mine. The Granger mine and processing facility, about 10 miles (15 km) northeast of the eponymous town, operated as an underground mine from 1976 to 2002. FMC acquired the properties in 1999 by acquiring Tg Soda Ash, originally developed as a unit of Texasgulf and then owned by Elf Atochem. FMC converted the mine and mill to solution mining in 2005. In our secondary recovery solution mining operations, we pump process waters from our surface facilities, along with insoluble remnant from the processing of dry mined ore, into former underground mine workings where the insoluble constituents settle out and sodium carbonate and bicarbonate are leached from trona left behind from previous dry mining. The return mine water is pumped back to the Westvaco and Granger surface processing facilities for recovery of sodium solids.
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-mining Total Reserves 448.1 89.4
Solution mining Proven — —
Solution mining Total Reserves 442.0 86.3