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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, 2021
OR
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-12295
GENESIS ENERGY, L.P.
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
919 Milam, Suite 2100,
Houston , TX
(Address of principal executive offices)
76-0513049
(I.R.S. Employer
Identification No.)
77002
(Zip code)
Registrant’s telephone number, including area code: (713) 860-2500
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Common Units
Trading Symbol(s)
GEL
Name of Each Exchange on Which Registered
NYSE
Securities registered pursuant to Section 12(g) of the Act:
NONE
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T(§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files). Yes x No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting
company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,”
and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
Non-accelerated filer
x
☐
Accelerated filer
Smaller reporting company
Emerging growth company
☐
☐
☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying
with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 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
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The aggregate market value of the Class A common units held by non-affiliates of the Registrant on June 30, 2021 (the last business day of
Registrant’s most recently completed second fiscal quarter) was approximately $1,214.6 million based on $11.61 per unit, the closing price of
the common units as reported on the NYSE. For purposes of this computation, all executive officers, directors and 10% owners of the
registrant are deemed to be affiliates. Such a determination should not be deemed an admission that such executive officers, directors and
10% beneficial owners are affiliates. On February 24, 2022, 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.
2021 FORM 10-K ANNUAL REPORT
Table of Contents
Item 1
Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2.
Item 3.
Properties
Legal Proceedings
Item 4. Mine Safety Disclosures
Part I
Part II
Item 5.
Item 6.
Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity
Securities
Selected Financial Data
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8.
Item 9.
Financial Statements and Supplementary Data
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Part III
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14.
Principal Accountant Fees and Services
Part IV
Item 15. Exhibits and Financial Statement Schedules
Item 16.
Form 10-K Summary
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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/day: Thousand Bbls per day.
Mcf: Thousand cubic feet of gas.
MMBtu: One million British thermal units, an energy measurement.
MMcf: Thousand Mcf.
MMcf/day: Thousand Mcf per day.
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:
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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
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activity, capital expenditures by energy producers, weather, alternative energy sources, international events,
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 BXC (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;
compliance with and changes in cybersecurity requirements; and
a cyberattack involving our information systems and related infrastructure, or that of our business associates.
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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
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described in our Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and Form 8-K/A and other documents that we
may file from time to time with the SEC. Except as required by applicable securities laws, we do not intend to update these
forward-looking statements and information.
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Item 1. Business
General
PART I
We are a growth-oriented master limited partnership formed in Delaware in 1996. Our common units are traded on the
New York Stock Exchange, or NYSE, under the ticker symbol “GEL.” We are (i) a provider of an integrated suite of midstream
services (primarily transportation, storage, sulfur removal, blending, terminaling 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, or U.S. 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 crude oil and natural gas pipeline transportation and handling operations in the Gulf of Mexico 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 large-reservoir, long-lived crude oil and natural gas properties. We
provide services to the Gulf of Mexico, which is one of the most active drilling and development regions in the U.S., and a
producing region representing approximately 15% of the crude oil production in the U.S. during 2021. 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 U.S., 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 2021 production) of over 100 years related to the seam
currently being mined, which is disclosed in further detail in Item 2. “Properties.” 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:
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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 2021;
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.
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 over 100 years;
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 in the Gulf of
Mexico 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
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 2021. 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/day, a number of which pipeline systems are substantial and/or strategically located. For example, we own a 64%
interest in the Poseidon oil pipeline system, or Poseidon pipeline, and a 64% interest in the Cameron Highway oil pipeline
system, or CHOPS pipeline, which are two 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 system, or SEKCO pipeline,
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/day. We also own an interest in three offshore
hub platforms, two of which are operational, with an aggregate processing capacity of approximately 495 MMcf/day of natural
gas and 123 MBbls/day of crude oil. Additionally, we own an interest in a number of junction and service platforms in the Gulf
of Mexico, which are used to (i)interconnect the offshore pipeline network; (ii) provide an efficient means to perform pipeline
maintenance; and (iii) contain equipment, such as pumps and measurement equipment, which can increase and direct flow on
our pipelines.
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.
We believe our offshore pipeline transportation segment is well positioned to participate in the energy transition and
lower carbon world as barrels produced from the Gulf of Mexico are the least emission intensive barrels, from reservoir to
refinery, of any barrel refined by Gulf Coast refineries (including shipping).
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 86,000 acres of land, containing an estimated 878 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 U.S., 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 one other U.S. soda ash producer are members currently, whose purpose is to
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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, market supply, customer demand and consistent customer service. In North America, primary
competition is from other U.S.-based natural soda ash operations: Solvay Chemicals, Sisecam Resources LP, and Tata
Chemicals Soda Ash Partners in Wyoming, and Searles Valley Minerals in California.
As part of our sulfur services business, we primarily (i) provide sulfur removal services by processing refineries high
sulfur (or “sour”) gas streams to remove the sulfur at ten refining operations located mostly in Texas, Louisiana, Arkansas,
Oklahoma, Montana and Utah; (ii) operate significant storage and transportation assets in relation to those services; and (iii) sell
NaHS and NaOH (also known as caustic soda) to large industrial and commercial companies. Our sulfur removal services
footprint also includes NaHS and caustic soda terminals, and we utilize railcars, ships, barges and trucks to transport product.
Our sulfur removal services contracts are typically long-term in nature and have an average remaining term of 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 produce 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.
We believe our Alkali Business and sulfur services business are well positioned to participate in the energy transition
and lower carbon world. Natural soda ash has a lower Greenhouse Gas footprint than synthetic soda ash as it is less energy
intensive. In addition, synthetic soda ash creates by-products such as calcium chloride and ammonia chloride which need
further handling, or are disposed of as waste, and ultimately increase synthetic soda ash’s carbon footprint. Our sulfur services
business helps our host refineries lower their emissions by processing their sour gas stream using our proprietary, closed-loop,
non-combustion technology to remove sulfur from the sour gas, whereas the traditional combustion technology releases certain
levels of harmful gases and incremental carbon dioxide emissions into the atmosphere. Additionally, certain of our customers
also utilize the NaHS we sell them to further reduce air emissions from various chemical and industrial activities.
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, 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
infrastructure assets and complexes 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, and trailers, 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 intermediate refined petroleum products, including heavy fuel oil and asphalt, as well as crude oil.
Refiners contracted for approximately 80% of the revenues from our marine inland barges during 2021.
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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 objectives continue 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. We believe that the (i) long-term contracted
commercial opportunities in the Gulf of Mexico, including Argos and the King’s Quay floating production system (which are
scheduled for first production in the first half of 2022) will provide significant incremental volumes on our offshore pipeline
transportation assets with existing connectivity and excess capacity that require minimal to no additional investment from us;
(ii) normalization and recovery of soda ash markets from the declines in 2020, including both price and volume recovery; and
(iii) increased capacity for soda ash production in 2023 with the potential to bring the original Granger facility and its
approximately 500,000 tons of production back online in the first part of 2023 and further increased production capacity from
our Granger Optimization Project (as defined below), which is scheduled to begin first production in the second half of 2023
and ramp to its design capacity of an additional 750,000 tons per year over the subsequent nine to twelve months, will support
the generation and growth of stable cash flows.
To deleverage our balance sheet, we recently completed (i) the sale of a 36% minority equity interest in our Cameron
Highway oil pipeline system (“CHOPS”) for gross proceeds of approximately $418 million (which represents a premium
relative to the proportionate carrying value of CHOPS); and (ii) the repayment of the $300 million outstanding under the Term
Loan under our new credit agreement (as defined below).
To further enhance our financial flexibility to opportunistically pursue accretive organic growth projects and
acquisitions should they present themselves, we completed the renewal and extension of the maturity on our senior secured
credit facility to mature in 2024 with a current maximum revolving borrowing capacity of $650 million under our new credit
agreement (see Note 10 of our Consolidated Financial Statements in Item 8).
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 large-reservoir, long-lived crude oil and natural gas properties. Our
offshore oil pipelines that transport oil produced from integrated and large independent energy companies are ideally suited for
the vast majority of refineries along the Gulf Coast. 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 2021, refiners were the shippers of approximately 98% of the volumes
transported on our onshore crude pipelines, and refiners contracted for approximately 80% of the revenues from our marine
inland barges during 2021, 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;
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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.
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;
•
•
•
Fund capital projects through a combination of the available borrowing capacity under our new credit agreement,
internally generated free cash flows, or externally;
Pursue divestitures of non-core assets that support our deleveraging objective; 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 our 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 2021. 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 over 100 years.
• We are financially flexible and have significant liquidity. As of December 31, 2021, we had $599.7 million available
under our $650 million revolving credit agreement, subject to compliance with our covenants, including up to $190.3
million available under the $200 million petroleum products inventory loan sublimit and $98.7 million available for
letters of credit. Our inventory borrowing base was $9.7 million at December 31, 2021.
•
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
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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 largest
producing regions in the U.S., the Gulf of Mexico.
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, sustainability and safety metrics), our executive management team is
incentivized to create value.
Recent Developments and Status of Certain Growth Initiatives
The following is a brief listing of developments since December 31, 2020. Additional information regarding most of
these items may be found elsewhere in this report.
Credit Facility Amendment
On April 8, 2021, we entered into the Fifth Amended and Restated Credit Agreement (our “new credit agreement”) to
replace our Fourth Amended and Restated Credit Agreement. Our new credit agreement provides for a $950 million senior
secured credit facility (the “senior secured credit facility”), comprised of a revolving loan facility with a borrowing capacity of
$650 million (the “Revolving Loan”) and a term loan facility of $300 million (the “Term Loan”). Our Term Loan was paid off
in full with a portion of the proceeds received from the sale of a 36% interest in CHOPS (discussed further below). The new
credit agreement matures on March 15, 2024, subject to extension at our request for one additional year on up to two occasions
and subject to certain conditions.
Senior Unsecured Note Transactions
On April 22, 2021, we completed our offering of an additional $250 million in aggregate principal amount of our 2027
Notes (as defined in Note 10 to our Consolidated Financial Statements in Item 8). The notes constitute an additional issuance of
our existing 2027 Notes that we issued on December 17, 2020 in an aggregate principal amount of $750 million. The additional
$250 million of notes have identical terms as (other than with respect to the issue price) and constitute part of the same series of
the 2027 Notes. The $250 million of the 2027 Notes were issued at a premium of 103.75% plus accrued interest from December
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17, 2020. We used the net proceeds from the offering for general partnership purposes, including repaying a portion of the
revolving borrowings outstanding under our new credit agreement.
On January 19, 2021, we redeemed the remaining principal balance outstanding on our 2023 Notes of $80.9 million in
accordance with the terms and conditions of the indenture governing the 2023 Notes. We incurred a total loss of approximately
$1.6 million relating to the extinguishment of our remaining 2023 Notes, inclusive of the redemption fee and the write-off of
the related unamortized debt issuance costs, which is recorded in “Other expense, net” in our Unaudited Condensed
Consolidated Statement of Operations for the year ended December 31, 2021.
Sale of a Minority Interest in CHOPS
On November 17, 2021, we closed on the sale of a 36% minority equity interest in CHOPS for gross proceeds of
approximately $418 million. Proceeds from the sale, net of fees and expenses, were used to repay the $300 million outstanding
under our Term Loan in full. We own 64% of CHOPS and remain the operator of the pipeline.
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 during the second half of 2023. We entered into agreements with funds
affiliated with Blackstone Alternative Credit Advisors LP, formerly known as “GSO Capital Partners LP” (collectively,
“BXC”) for the purchase of up to $350 million of preferred units in Genesis Alkali Holdings Company (“Alkali Holdings”)
(refer to Note 11 for further discussion). The proceeds we receive from BXC will assist in the funding of the anticipated cost of
the GOP, subject to compliance with the covenants contained in our agreements with BXC. The preferred unitholders receive
payment-in-kind (“PIK”) in lieu of cash distributions through September 2023, which represents the anticipated construction
period.
On April 14, 2020, we entered into an amendment to our agreements with BXC 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 BXC, which was accounted for as issuance costs. As of December 31, 2021,
there are 246,394 Alkali Holdings preferred units outstanding. During the fourth quarter of 2021, we made the decision to fund
the remaining construction costs required to complete the GOP through a combination of our internally generated free cash flow
and availability under our Revolving Loan.
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.
Due to the economic effects from commodity price volatility and Covid-19, demand and volumes throughout our
businesses were negatively impacted beginning in the second quarter of 2020. Additionally, during 2020, our businesses were
negatively impacted by lower refinery utilization, crude differentials, supply and demand imbalances in our Alkali Business,
and an unprecedented hurricane season. However, we began to see economic recovery across a majority of our asset footprint
as we exited 2020, which has continued during 2021. Specifically, during 2021, oil and natural gas prices have seen a recovery
from the lows experienced in 2020 and our offshore pipeline transportation segment experienced volumes at its normal run rate
as we resumed normal operations on our CHOPS pipeline. Additionally, our Alkali Business has continued to see volume
demand recovery and continued pricing recovery on our ANSAC export volumes.
We continue to monitor the market environment and will evaluate whether any triggering events would indicate
possible impairments of long-lived assets, intangible assets and goodwill. Management’s estimates are based on numerous
assumptions about future operations and market conditions, which we believe to be reasonable but are inherently uncertain. The
uncertainties underlying our assumptions and estimates could differ significantly from actual results, including with respect to
the duration and severity of the Covid-19 pandemic. In the current volatile economic environment and to the extent conditions
deteriorate, we may identify triggering events that may require future evaluations of the recoverability of the carrying value of
our long-lived assets, intangible assets and goodwill, which could result in impairment charges that could be material to our
results of operations.
We believe the fundamentals of our core businesses continue to remain strong and, given the current industry
environment and capital market behavior, we have continued our focus on deleveraging our balance sheet, which included the
sale of a 36% minority equity interest in CHOPS for gross proceeds of approximately $418 million and the refinance and
extension of our senior secured credit facility to 2024 under our new credit agreement. Refer to “Liquidity and Capital
Resources” for additional discussion.
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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, 2021.
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 U.S., 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.
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The table below reflects our interests in our operating offshore crude oil pipelines:
Offshore crude oil
pipelines
Operator
System
Miles
Design
Capacity
(Bbls/day) (1)
Interest
Owned
Throughput
(Bbls/day)
100% basis
Throughput
(Bbls/day) net
to ownership
interest
Main Lines
CHOPS Pipeline
Poseidon Pipeline
Odyssey Pipeline
Eugene Island
Pipeline and Other
Total
Lateral Lines (2)
SEKCO Pipeline
Shenzi Crude Oil
Pipeline
Allegheny Crude Oil
Pipeline
Marco Polo Crude
Oil Pipeline
Constitution Crude
Oil Pipeline
Tarantula
Genesis
Genesis
Shell
Pipeline
Genesis/
Shell
Pipeline
380
358
120
500,000
490,000
64 %
64 %
189,904
263,169
180,173 (3)
168,428
200,000
29 %
114,128
33,097
184
39,000
29 %
1,042
1,229,000
7,826
575,027
7,826
389,524
Genesis
149
115,000
100 %
Genesis
Genesis
Genesis
Genesis
Genesis
83
40
37
67
4
230,000
100 %
140,000
100 %
120,000
100 %
80,000
30,000
100 %
100 %
(1) Capacity figures presented represent 100% of the design capacity; except for Eugene Island, which represents our net capacity in
the undivided interest (29%) in that system. Ultimate capacities can vary primarily as a result of pressure requirements, installed
pumps, related facilities and the viscosity of the crude oil actually moved.
(2) Represents 100% owned lateral crude oil pipelines which ultimately flow into our other offshore crude oil pipelines (including
CHOPS pipeline and Poseidon pipeline) and thus are excluded from main lines above.
(3) Represents throughput for our 64% ownership interest from November 17, 2021 to December 31, 2021, and 100% ownership
interest for the period prior to November 17, 2021.
•
•
•
•
•
CHOPS Pipeline. CHOPS pipeline 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 three strategically located multi-
purpose offshore platforms. An affiliate of an undisclosed financial party owns the remaining 36% interest in CHOPS.
Poseidon Pipeline. The Poseidon pipeline 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 Oil Pipeline Company, L.L.C.
(“Poseidon”).
Odyssey Pipeline. The Odyssey pipeline 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 Pipeline, L.L.C (“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 pipeline 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. Southeast
Keathly Canyon Pipeline Company, LLC (“SEKCO”) has crude oil transportation agreements with various Gulf of
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Mexico producers who have dedicated their production from Lucius, Buckskin and Hadrian North to the pipeline for
the life of their reserves.
Shenzi Crude Oil Pipeline. The Shenzi Crude Oil Pipeline gathers crude oil production from the Shenzi production
field located in the Green Canyon area of the Gulf of Mexico offshore Louisiana for delivery to both our CHOPS and
Poseidon pipeline systems.
Allegheny Crude Oil Pipeline. The Allegheny Crude Oil Pipeline connects the Allegheny and South Timbalier 316
platforms in the Green Canyon area of the Gulf of Mexico with the CHOPS and Poseidon pipelines.
•
•
• Marco Polo Crude Oil Pipeline. The Marco Polo Crude Oil Pipeline transports crude oil from our Marco Polo crude
oil platform to an interconnect with the Allegheny Crude Oil Pipeline in Green Canyon Block 164.
•
Constitution Crude Oil Pipeline. The Constitution Crude Oil Pipeline gathers crude oil from the Constitution,
Constellation, Caesar Tonga and Ticonderoga production fields located in the Green Canyon area of the Gulf of
Mexico for delivery to either the CHOPS or Poseidon pipelines.
None of our offshore crude oil pipelines are rate regulated with the exception of Eugene Island, which is regulated by
the FERC.
The table below reflects our interests in our operating offshore natural gas pipelines:
Offshore natural gas pipelines
Operator
System Miles
Design Capacity
(MMcf/day) (1)
Interest
Owned
High Island Offshore System
Anaconda Gathering System
Green Canyon Laterals
Manta Ray Offshore Gathering
System
Nautilus System
Total
Genesis
Genesis
Genesis
Enbridge
Enbridge
238
183
5
237
101
764
500
300
108
800
600
2,308
100 %
100 %
100%
25.7 %
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
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demand-type fees and commodity charges, but demand-type fees generally expire after a contractually fixed period of time and
in some instances may be subject to cancellation by customers.
The table below reflects our interests in our operating offshore hub platforms:
Offshore hub platform
Marco Polo
East Cameron 373
Total
Operator
Occidental
Genesis
Water
Depth (Feet)
Natural Gas
Capacity (MMcf/
day) (1)
Crude Oil
Capacity (Bbls/
day) (1)
4,300
441
300
195
495
120,000
3,000
123,000
Interest
Owned
100 %
100 %
(1) Capacity figures presented represent 100% of the design capacity.
• 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.
•
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
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.
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Our Alkali Business includes the following:
Dry mining of trona ore underground at our Westvaco facility;
Secondary recovery of trona from previously dry mined areas underground at our Westvaco and Granger facilities
through solution mining;
Processing of raw trona ore into soda ash and specialty sodium alkali products; and
•
•
•
• Marketing, sale and distribution of alkali products.
Our Alkali Business currently 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 plant
process, the ore is calcined with heat, prior to dissolution, to convert the trona to soda ash by the removal of water and carbon
dioxide. A final drying step using steam produces a dense soda ash product from the Mono process. In our Sesqui plant, the
calcination is performed at the end of the process, producing a light density soda ash that is preferred in applications desiring
increased absorptivity. The Sesqui process also has the ability to produce refined sodium sesquicarbonate (which we sell under
the names S-Carb® and Sesqui®) for use as a buffer in animal feed formulations and in cleaning and personal care applications.
Solution mined trona is converted into dense soda ash in our ELDM operation at the Westvaco site and at our Granger
facility. The steps to produce soda ash are similar to the dry mined processes, except the crushing and dissolving steps are
eliminated because the trona is already in a water solution as it leaves the mine.
Intermediate, semi-processed products are extracted from our soda ash processes at Westvaco at strategic locations for
use as feedstocks for production of sodium bicarbonate and 50% caustic soda (NaOH).
Marketing, Sale and Distribution of Alkali Products
We sell our alkali products to customers directly in the U.S., 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 one other U.S. soda ash producer are members currently, 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 3,400 covered hopper cars which we use to deliver over 90% of the sales of alkali products from the Green
River facilities, all of which are shipped via a single rail line owned and operated by Union Pacific Railroad. We lease these
railcars from banks and leasing companies and from FMC Corporation under agreements with varying term-lengths. We
recover costs of leasing through mileage credits paid under agreements with customers and carriers in accordance with
established industry practices and government requirements.
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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 U.S. 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 in 2021). 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 U.S., 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 one other U.S. soda ash producer are members currently. One previous ANSAC member exited ANSAC in 2021.
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.
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
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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, Sisecam Resources LP, 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 U.S., 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, 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 U.S. 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 in 2021). 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 29% 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 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 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 24,000 Bbls/
day (as of December 31, 2021) 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 incurring other 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
Crude Oil,
Intermediates,
and
Refined
Products
100%
Product
Interest Owned
Design Capacity (Bbls/day)
2021 Throughput (Bbls/day)
System Miles
Crude Oil
100%
Existing 8" -
60,000
Looped 18" -
275,000
65,918
47
Crude Oil
100%
Crude Oil
100%
150,000
7,941
143
45,000
5,206
207
350,000
44,564
51
Approximate owned tankage storage
capacity (Bbls)
1,100,000
230,000
247,500
330,000
Hastings
Junction, TX
to Webster,
TX
Texas City,
TX to
Webster, TX
FERC/
TXRRC
Port Hudson,
LA to Baton
Rouge, LA
Baton Rouge,
LA to Port
Allen, LA
Southern AL/
FL to Mobile,
AL
Soso, MS to
Liberty, MS
FERC
FERC
FERC
Location
Rate Regulated
•
•
Texas System. Our Texas System 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. Our Texas System also transports crude oil from Hastings Junction (south of
Houston) to several delivery points near Houston, Texas (including our Webster, Texas facility). 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 connects the Anchorage Tank Farm to our Port of Baton Rouge Terminal
(which was built to service Exxon Mobil Corporation’s Baton Rouge refinery, which is one of the largest refinery
complexes in North America, with more than 500,000 Bbls/day of refining capacity), allowing bidirectional flow of
crude oil, intermediates and refined products between the Anchorage Tank Farm and this terminal via a dedicated
crude oil pipeline and a dedicated intermediates pipeline. Total daily volume for the year ended December 31, 2021
includes 32,526 Bbls/day of intermediate refined products associated with our Port of Baton Rouge Terminal pipelines.
Our Louisiana system also transports crude oil from Port Hudson to our Baton Rouge Scenic Station rail unloading
facility and continues downstream to the Anchorage Tank Farm. 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, 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 intermediate 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:
Aggregate Fleet Design Capacity (MBbls)
Individual Vessel Capacity Range (MBbls)(1)
Number of:
Push/Tug Boats
Barges
Product Tankers
Inland
2,285
23-39
33
82
—
Offshore
884
65-135
9
9
—
American Phoenix
330
330
—
—
1
(1) Represents capacity per barge ranges on our inland and offshore barge, as well as the capacity of our M/T American Phoenix.
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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
2021 and 2020. 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. During 2021, we continued to enter into more short term spot contracts because we believe
the day rates for term contracts being offered by the market have yet to fully recover from their cyclical lows. During 2021 and
2020, approximately 49% and 63%, respectively, of our marine transportation revenues were from term contracts and 51% and
37%, 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,
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 Corporation (“Occidental”) and ANSAC.
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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 1,903 employees at December 31, 2021.
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.
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.
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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
The operation of towboats, tugboats, barges, vessels and marine equipment create maritime obligations involving
property, personnel and cargo and are subject to regulation by the U.S. Coast Guard, or USCG, the Environmental Protection
Agency, or EPA, the Department of Homeland Security, or DHS, federal laws, state laws and certain international conventions
under General Maritime Law. These obligations can create risks which are varied and include, among other things, the risk of
collision and allision, which may precipitate claims for personal injury, cargo, contract, pollution, third-party claims and
property damages to vessels and facilities. Routine towage operations can also create risk of personal injury under the Jones Act
and General Maritime Law, cargo claims involving the quality of a product and delivery, terminal claims, contractual claims
and regulatory issues. Federal regulations also require that all tank barges engaged in the transportation of oil and petroleum in
the U.S. be double hulled. All of our barges are double-hulled.
All of our barges are inspected by the USCG and carry certificates of inspection. All of our towboats and tugboats are
certificated by the USCG. Most of our vessels are built to American Bureau of Shipping, or ABS, classification standards and
in some instances are inspected periodically by ABS to maintain the vessels in class standards. The crews we employ aboard
vessels, including captains, pilots, engineers, tankermen and ordinary seamen, are documented by the USCG.
We are required by various governmental agencies to obtain licenses, certificates and permits for our vessels
depending upon such factors as the cargo transported, the waters in which the vessels operate and other factors. We are of the
opinion that our vessels have obtained and can maintain all required licenses, certificates and permits required by such
governmental agencies for the foreseeable future.
Jones Act: The Jones Act is a federal law that restricts maritime transportation between locations in the U.S. to vessels
built and registered in the U.S. and owned and manned by U.S. citizens. We are responsible for monitoring the ownership of
our subsidiary that engages in maritime transportation and for taking any remedial action necessary to insure that no violation
of the Jones Act ownership restrictions occurs. Jones Act requirements significantly increase operating costs of U.S.-flag vessel
operations compared to foreign-flag vessel operations. Further, the USCG and ABS maintain the most stringent regime of
vessel inspection in the world, which tends to result in higher regulatory compliance costs for U.S.-flag operators than for
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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
Sweetwater Trona OpCo LLC (“Sweetwater”). 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. Sweetwater acquired the leases
and interests from Anadarko Land Corporation, a subsidiary of Occidental following Occidental’s August 2019 acquisition of
Anadarko Petroleum Corporation, who was 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 Overview of Mining Property and Operations in Item 2 below.
We pay royalties to the BLM, the State of Wyoming and Sweetwater Royalties, LLC (“Sweetwater Royalties”) who
acquired the mineral rights through a conveyance from Sweetwater. 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 Sweetwater Royalties to pay royalties in advance based on a
formula based on the amount of trona produced and sold in the previous year which is then credited against production royalties
owed. The royalty rates we pay to our lessors may change upon our renewal of such leases; however, we anticipate being able
to renew all material leases at the appropriate time. In the past, the U.S. Congress has passed legislation to cap royalties
collected by BLM at a rate lower than the rate stated in our federal leases.
Our mining operations in Wyoming are subject to mine permits issued by the Land Quality Division of the Wyoming
Department of Environmental Quality (“WDEQ”). WDEQ imposes detailed reclamation obligations on us as a holder of mine
permits. As of December 31, 2021, 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.
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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
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 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
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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.
The scope of waters regulated under the CWA has fluctuated in recent years. 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, and then, 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. On August 30, 2021, a federal court struck down the replacement rule and, on December 7, 2021, the EPA
and the Corps published a proposed rule that would put back into place the pre-2015 definition of “waters of the United States,”
updated to reflect Supreme Court decisions, while the agencies continue to consult with stakeholders on future regulatory
actions. As a result of such recent developments, substantial uncertainty exists regarding the scope of waters protected under the
Clean Water Act. To the extent the rules expand the range of properties subject to the Clean Water Act's jurisdiction, we could
face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.
Also, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore
unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. In addition, the Clean
Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water
runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from certain
of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations
that may impact groundwater conditions.
The Oil Pollution Act is the primary federal law for oil spill liability. The Oil Pollution Act contains numerous
requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the
requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and
maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential
environmental cleanup and restoration costs. The Oil Pollution Act subjects owners of facilities to strict liability that, in some
circumstances, may be joint and several for all containment and cleanup costs and certain other damages arising from a release,
including, but not limited to, the costs of responding to a release of oil to surface waters.
Noncompliance with the Clean Water Act or the Oil Pollution Act may result in substantial administrative, civil and
criminal penalties, as well as injunctive obligations. We believe we are in material compliance with each of these requirements.
Air Emissions - The Federal Clean Air Act, or CAA, as amended, and analogous state and local laws and regulations
restrict the emission of air pollutants, and impose permit requirements and other obligations. Regulated emissions occur as a
result of our operations, including the handling or storage of crude oil and other petroleum products. Both federal and state laws
impose substantial penalties for violation of these applicable requirements. Accordingly, our failure to comply with these
requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, revocation or
suspension of necessary permits and, potentially, criminal enforcement actions.
On August 16, 2012, the EPA published final regulations under the CAA 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
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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, on August 13,
2020, in response to an executive order by former President Trump to review and revise unduly burdensome regulations, the
EPA amended 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. On June 30, 2021,
President Biden signed into law a joint resolution of Congress disapproving the 2020 amendments (with the exception of some
technical changes) thereby reinstating the 2012 and 2016 New Source Performance standards. The EPA expects owners and
operators of regulated sources to take “immediate steps” to comply with these standards. Additionally, on November 15, 2021,
the EPA published a proposed rule that would expand and strengthen emission reduction requirements for both new and
existing sources in the oil and natural gas industry by requiring increased monitoring of fugitive emissions, imposing new
requirements for pneumatic controllers and tank batteries, and prohibiting venting of natural gas in certain situations. These new
standards, to the extent implemented, 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.
National Environmental Policy Act - 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. Our compliance with any future legislation or regulation of GHGs, if adopted, 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. On April 21, 2021, the United States announced that it was setting an economy-wide
target of reducing its greenhouse gas emissions by 50-52 percent below 2005 levels in 2030. In November 2021, in connection
with the 26th Conference of the Parties (COP-26) in Glasgow, Scotland, the United States and other world leaders made further
commitments to reduce greenhouse gas emissions, including reducing global methane emissions by at least 30% by 2030.
Furthermore, many state and local leaders have stated their intent to intensify efforts to support the international climate
commitments.
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
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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
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. Also, on November 15, 2021, the PHMSA published a final rule
extending reporting requirements to all onshore gas gathering operators and establishing a set of minimum safety requirements
for certain gas gathering pipelines with large diameters and high operating pressures. Also, on June 7, 2021, the PHMSA issued
an advisory bulletin reminding pipeline owners and operators that, pursuant to legislation signed into law in December 2020,
they must take several steps to eliminate hazardous leaks and minimize releases of natural gas by December 27, 2021.
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 strengthen integrity management assessment requirements.
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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 consistent with PHMSA requirements, effective September 13, 2021. 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.
On May 27, 2021, the Department of Homeland Security’s Transportation Security Administration (“TSA”)
announced Security Directive Pipeline-2021-01 that requires us, as a critical pipeline owner, to report confirmed and potential
cybersecurity incidents to the DHS Cybersecurity and Infrastructure Security Agency (“CISA”) and to designate a
Cybersecurity Coordinator. It also requires us and the third-party operators of our assets to review current practices as well as to
identify any gaps and related remediation measures to address cyber-related risks and report the results to TSA and CISA
within 30 days. We designated a Cybersecurity Coordinator, developed a plan to comply with mandatory reporting timeframes
and completed the vulnerability assessment required under this directive in 2021. On July 20, 2021, the TSA issued a second
Security Directive. We have evaluated the impacts of this second directive to our pipeline business and have made significant
progress in compliance. See “Compliance with and changes in cybersecurity requirements has a cost impact on our business,
and failure to comply with such laws and regulations could have an impact on our assets, costs, revenue generation and growth
opportunities.”
Available Information
We make available free of charge on our internet website (www.genesisenergy.com) our annual report on Form 10-K,
quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to
Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file the
material with, or furnish it to, the SEC. These documents are also available at the SEC’s website (www.sec.gov). Additionally,
on our internet website we make available our Corporate Governance Guidelines, Code of Business Conduct and Ethics, Audit
Committee Charter and Governance, Compensation and Business Development Committee Charter. Information on our website
is not incorporated into this Form 10-K or our other securities filings and is not a part of this Form 10-K or our other securities
filings.
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Item 1A. Risk Factors
The following risk factors and other information included in this Annual Report on Form 10-K should be carefully
considered. The occurrence of any of the following risks or of unknown risks and uncertainties may adversely affect our
business, operating results and financial condition.
Risk Factors Summary
Risks Related to the Operations of Our Business
• We may not be able to fully execute our growth strategy due to various factors, such as unreceptive capital markets
and/or excessive competition for acquisitions.
• We may not have sufficient cash from operations to pay the current level of quarterly distributions following the
establishment of cash reserves and payment of fees and expenses.
• Our profitability and cash flow are dependent on our ability to increase or, at a minimum, maintain our current
commodity (crude oil, natural gas, refined products, soda ash, NaHS and caustic soda) volumes, which often depend
on actions and commitments by parties beyond our control.
• Many of our crude oil and natural gas transportation customers are producers whose drilling activity levels and
spending for transportation have historically been, and may continue to be, impacted by volatility in the commodity
markets.
Fluctuations in prices for crude oil, refined petroleum products, NaHS, soda ash and caustic soda could adversely
affect our business.
•
Risks Related to Liquidity and Financing
• Our indebtedness could adversely restrict our ability to operate, affect our financial condition, prevent us from
complying with requirements under our debt instruments and prevent us from paying cash distributions to our
unitholders.
• We may not be able to access adequate capital (debt and/or equity) on economically viable terms, or any terms.
Risks Related to Legal and Regulatory Compliance
•
•
• Our operations are subject to federal, state and local environmental protection and safety laws and regulations.
•
Climate change legislation and regulatory initiatives may decrease demand for the products we store, transport and sell
and increase our operating costs.
Changes in environmental laws could increase costs and harm our business, financial condition and results of
operations.
Risks Related to Our Partnership Structure
Individual members of the Davison family can exert significant influence over us and may have conflicts of interest
with us and may be permitted to favor their interests to the detriment of our other unitholders.
• Our Class B Common Units may be transferred to a third party without unitholder consent, which could affect our
•
strategic direction.
The interruption of distributions to us from our subsidiaries and joint ventures could affect our ability to make
payments on indebtedness or cash distributions to our unitholders.
• We do not have the same flexibility as other types of organizations to accumulate cash and equity to protect against
illiquidity in the future.
Tax Risks to Our Unitholders
• Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as us not being
subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service, or IRS, were
to treat us as a corporation (for U.S. federal income tax purposes) or if we were to become subject to a material amount
of entity-level taxation for state tax purposes, then our cash available for distribution to our unitholders could be
substantially reduced.
• Our unitholders will be required to pay taxes on income (as well as deemed distributions, if any) from us even if they
do not receive any cash distributions from us.
• Our unitholders will likely be subject to state and local taxes in states where they do not live as a result of an
investment in our units.
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General Risks
• We are exposed to the credit risk of our customers in the ordinary course of our business activities.
• A natural disaster, pandemic, epidemic, accident, terrorist attack or other interruption event could result in an
economic slowdown, severe personal injury, property damage and/or environmental damage, which could curtail our
operations or otherwise adversely affect our assets and cash flow.
• Our business could be negatively impacted by security threats, including cybersecurity threats, and related disruptions.
Compliance with and changes in cyber security requirements have a cost impact on our business.
• Our significant unitholders may sell units or other limited partner interests in the trading market, which could reduce
the market price of our common units.
• We may issue additional common units without unitholders’ approval, which would dilute their ownership interests.
Risks Related to the Operations of Our Business
We may not be able to fully execute our growth strategy due to various factors, such as unreceptive capital markets and/or
excessive competition for acquisitions.
Our strategy contemplates substantial growth through the development and acquisition of a wide range of midstream
and other infrastructure and mining assets while maintaining a strong balance sheet. This strategy includes constructing and
acquiring additional assets and businesses to enhance our ability to compete effectively, diversify our asset portfolio and,
thereby, provide more stable cash flow. We regularly consider and enter into discussions regarding, and are currently
contemplating, additional potential joint ventures, stand-alone projects and other transactions that we believe will present
opportunities to realize synergies, expand our role in the infrastructure and mining businesses, and increase our market position
and, ultimately, increase distributions to unitholders. A number of factors could adversely affect our ability to execute our
growth strategy, including an inability to raise adequate capital on acceptable terms, competition from competitors and/or an
inability to successfully integrate one or more acquired businesses into our operations.
We will need new capital to finance the future development and acquisition of assets and businesses. Limitations on
our access to capital will impair our ability to execute this strategy. Expensive capital will limit our ability to develop or acquire
accretive assets. Although we intend to continue to expand our business, this strategy may require substantial capital, and we
may not be able to raise the necessary funds on satisfactory terms, if at all.
In addition, we experience competition for the assets we purchase or contemplate purchasing. Increased competition
for a limited pool of assets could result in our not being the successful bidder more often or our acquiring assets at a higher
relative price than that which we have paid historically. Either occurrence would limit our ability to fully execute our growth
strategy. Our ability to execute our growth strategy may impact the market price of our securities.
We may be unable to integrate successfully businesses we acquire. We may incur substantial expenses, delays or other
problems in connection with our growth strategy that could negatively impact our results of operations. Moreover, acquisitions
and business expansions involve numerous risks, including: difficulties in the assimilation of the operations, technologies,
services and products of the acquired companies or business segments; inefficiencies and complexities that can arise because of
unfamiliarity with new assets and the businesses associated with them, including unfamiliarity with their markets; and diversion
of the attention of management and other personnel from day-to-day business to the development or acquisition of new
businesses and other business opportunities.
We may not have sufficient cash from operations to pay the current level of quarterly distributions following the
establishment of cash reserves and payment of fees and expenses.
The amount of cash we distribute on our common and Class A Convertible Preferred Units principally depends upon
margins we generate from our businesses, which fluctuate from quarter to quarter based on, among other things: the volumes
and prices at which we purchase and sell crude oil, natural gas, refined products and caustic soda; the volumes of sodium
hydrosulfide, or NaHS, and soda ash that we receive for our sodium minerals and sulfur services and the prices at which we sell
NaHS and soda ash; the demand for our services; the level of competition; the level of our operating costs; the effect of
worldwide energy conservation measures; governmental regulations and taxes; the level of our general and administrative costs;
and prevailing economic conditions.
In addition, the actual amount of cash we will have available for distribution will depend on other factors that include:
the level of capital expenditures we make, including the cost of acquisitions (if any); our debt service requirements; fluctuations
in our working capital; restrictions on distributions contained in our debt instruments or organizational documents governing
our joint ventures and unrestricted subsidiaries; our ability to borrow under our working capital facility to pay distributions; and
the amount of cash reserves required in the conduct of our business.
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Our ability to pay distributions each quarter depends primarily on our cash flow, including cash flow from financial
reserves and working capital borrowings, and our cash requirements, so it is not solely a function of profitability, which will be
affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and we may not
make distributions during periods when we record net income.
Our profitability and cash flow are dependent on our ability to increase or, at a minimum, maintain our current commodity
(crude oil, natural gas, refined products, soda ash, NaHS and caustic soda) volumes, which often depend on actions and
commitments by parties beyond our control.
Our profitability and cash flow are dependent on our ability to increase or, at a minimum, maintain our current
commodity (crude oil, natural gas, refined products, soda ash, NaHS, and caustic soda) volumes. We access commodity
volumes through various sources, such as our mines, producers, service providers (including gatherers, shippers, marketers and
other aggregators) and refiners. Depending on the needs of each customer and the market in which it operates, we can provide a
service for a fee (as in the case of our pipeline, marine vessel and railcar transportation operations), we can acquire the
commodity from our customer and resell it to another party, or, in the case of soda ash, we can produce the commodity
ourselves.
Our source of volumes depends on successful exploration and development of additional crude oil and natural gas
reserves by others; our successful development of our trona reserves, continued demand for refining and our related sulfur
removal and other services, for which we are paid in NaHS; the breadth and depth of our logistics operations; the extent that
third parties provide NaHS for resale; and other matters beyond our control.
The crude oil, natural gas and refined products available to us and our refinery customers are derived from reserves
produced from existing wells, and these reserves naturally decline over time. In order to offset this natural decline, our energy
infrastructure assets must access additional reserves. Additionally, some of the projects we have planned or recently completed
are dependent on reserves that we expect to be produced from newly discovered properties that producers are currently
developing.
Finding and developing new reserves is very expensive, requiring large capital expenditures by producers for
exploration and development drilling, installing production facilities and constructing pipeline extensions to reach new wells.
Many economic and business factors out of our control can adversely affect the decision by any producer to explore for and
develop new reserves. These factors include the prevailing market price of the commodity, the capital budgets of producers, the
depletion rate of existing reservoirs, the success of new wells drilled, environmental concerns, regulatory initiatives, cost and
availability of equipment, capital budget limitations or the lack of available capital and other matters beyond our control.
Additional reserves, if discovered, may not be developed in the near future or at all. The volatility in crude oil and natural gas
prices has forced some producers to significantly defer or curtail their planned capital expenditures. Thus, crude oil and natural
gas production in our market areas could decline, which could have a material negative impact on our revenues and prospects.
Demand for our services is dependent on the demand for crude oil and natural gas. Any decrease in demand for crude
oil or natural gas, including by those refineries or connecting carriers to which we deliver could adversely affect our cash flows.
The demand for crude oil also is dependent on the competition from refineries, the impact of future economic conditions, fuel
conservation measures, alternative fuel requirements or alternative fuel sources such as electricity, coal, fuel oils or nuclear
energy, government regulation or technological advances in fuel economy and energy generation devices, all of which could
reduce demand for our services. A reduction in demand for our services in the markets we serve could result in impairments of
our assets and have a material adverse effect on our business, financial condition and results of operations.
Our ability to access NaHS depends primarily on the demand for our proprietary sulfur removal process. Demand for
our services could be adversely affected by many factors, including lower refinery utilization rates, U.S. refineries accessing
more “sweet” (instead of “sour”) crude and the development of alternative sulfur removal processes that might be more
economically beneficial to refiners.
We are dependent on third parties for NaOH for use in our sulfur removal process as well as volume to market to third
parties. Should regulatory requirements or operational difficulties disrupt the manufacture of caustic soda by these producers,
we could be affected.
Our sulfur removal operations are dependent upon the supply of caustic soda, the demand for NaHS and the continuing
operations of the refiners for whom we process sour natural gas.
Caustic soda is a major component of the proprietary sulfur removal process we provide to our refinery customers.
Because we are a large consumer of caustic soda, we can leverage our economies of scale and logistics capabilities to
effectively market caustic soda to third parties. NaHS, the resulting by-product from our sulfur removal operations, is a vital
ingredient in a number of industrial and consumer products and processes. Any decrease in the supply of caustic soda could
affect our ability to provide sulfur removal services to refiners and any decrease in the demand for NaHS by the parties to
whom we sell the NaHS could adversely affect our business. Refineries’ need for our sulfur removal services is also dependent
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on refining competition from other refineries by refiners to process more “sweet” (instead of “sour”) crude, the impact of
future economic conditions, fuel conservation measures, alternative fuel requirements, government regulation or technological
advances in fuel economy and energy generation devices, all of which could reduce demand for our services.
Our crude oil and natural gas transportation operations are dependent upon demand for crude oil by refiners, primarily in
the Midwest and Gulf Coast, and the demand for natural gas.
Any decrease in this demand for crude oil by those refineries or connecting carriers to which, or for the natural gas, we
deliver could adversely affect our cash flows. Those refineries’ demand for crude oil also is dependent on the competition from
other refineries, the impact of future economic conditions, fuel conservation measures, alternative fuel requirements,
government regulation or technological advances in fuel economy and energy generation devices, all of which could reduce
demand for our services. The demand for natural gas is dependent on the impact of future economic conditions, fuel
conservation measures, alternative fuel requirements and alternative fuel sources such as electricity, coal, fuel oils or nuclear
energy, government regulation or technological advances in fuel economy and energy generation devices, all of which could
reduce demand for our services.
We face intense competition to obtain crude oil, natural gas and refined products volumes.
Our competitors-gatherers, transporters, marketers, brokers and other aggregators-include integrated, large and small
independent energy companies, as well as their marketing affiliates, who vary widely in size, financial resources and
experience. Some of these competitors have capital resources many times greater than ours and control substantially greater
supplies of crude oil, natural gas and refined products.
Even if reserves exist or refined products are produced in the areas accessed by our facilities, we may not be chosen by
the refiners or producers to gather, refine, market, transport, store or otherwise handle any of these crude oil and natural gas
reserves, NaHS, caustic soda, soda ash or other refined products. We compete with others for any such volumes on the basis of
many factors, including: geographic proximity to the production and/or refineries; costs of connection; available capacity; rates;
logistical efficiency in all of our operations; operational efficiency in our sulfur removal business; customer relationships; and
access to markets.
Additionally, on our onshore pipelines most of our third-party shippers do not have long-term contractual
commitments to ship crude oil on our pipelines. A decision by a shipper to substantially reduce or cease to ship volumes of
crude oil on our pipelines could cause a significant decline in our revenues. In Mississippi, we are dependent on
interconnections with other pipelines to provide shippers with a market for their crude oil, and in Texas, we are dependent on
interconnections with other pipelines to provide shippers with transportation to our pipeline. Any reduction of throughput
available to our shippers on these interconnecting pipelines as a result of testing, pipeline repair, reduced operating pressures or
other causes could result in reduced throughput on our pipelines that would adversely affect our cash flows and results of
operations.
Fluctuations in demand for crude oil or natural gas or availability of refined products or NaHS, such as those caused
by refinery downtime or shutdowns, can negatively affect our operating results. Reduced demand in areas we service with our
pipelines, marine vessels, rail facilities and trucks can result in less demand for our transportation services.
Many of our crude oil and natural gas transportation customers are producers whose drilling activity levels and spending
for transportation have historically been, and may continue to be, impacted by volatility in the commodity markets.
Many of our customers finance their drilling activities through cash flow from operations, the incurrence of debt or the
issuance of equity. Extreme volatility in commodity prices has caused many of our customers’ equity value to substantially
decline. New credit facilities and other debt financing from institutional sources have generally become more difficult and
expensive to obtain, and there may be a general reduction in the amount of credit available in the markets in which we conduct
business. For example, prices for crude oil declined precipitously starting in the second half of 2014 from over $100 per barrel
in June 2014 to approximately $30 per barrel in early 2016. Over the last two years, average monthly prices for crude oil ranged
from a high of over $80 per barrel to a low of less than $20 per barrel, and such extreme volatility may continue going forward.
Adverse price changes put downward pressure on drilling budgets for crude oil and natural gas producers, which have resulted,
and could continue to result, in lower volumes than we otherwise would have seen being transported on our pipeline and
transportation systems, which could have a material negative impact on our revenues and prospects.
Fluctuations in prices for crude oil, refined petroleum products, NaHS, soda ash and caustic soda could adversely affect our
business.
Because we purchase (or otherwise acquire) and sell crude oil, refined petroleum products, NaHS soda ash and caustic
soda we are exposed to some direct commodity price risks. Prices for those commodities can fluctuate in response to changes
in supply, market uncertainty and a variety of additional factors that are beyond our control, which could have an adverse effect
on our cash flows, profit and/or Segment Margin. We attempt to limit those commodity price risks through back-to-back
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purchases and sales, hedges and other contractual arrangements; however, we cannot completely eliminate our commodity price
risk exposure.
Our use of derivative financial instruments could result in financial losses.
We use derivative financial instruments and other hedging mechanisms from time to time to limit a portion of the
effects resulting from changes in commodity prices. To the extent we hedge our commodity price exposure, we forego the
benefits we would otherwise experience if commodity prices were to increase. In addition, we could experience losses resulting
from our hedging and other derivative positions. Such losses could occur under various circumstances, including if our
counterparty does not perform its obligations under the hedge arrangement, our hedge is imperfect or our hedging policies and
procedures are not followed.
Non-utilization of certain assets could significantly reduce our profitability due to the fixed costs incurred with respect to
such assets.
From time to time in connection with our business, we may lease or otherwise secure the right to use certain third party
assets (such as railcars, trucks, barges, pipeline capacity, storage capacity and other similar assets) with the expectation that the
revenues we generate through the use of such assets will be greater than the fixed costs we incur pursuant to the applicable
leases or other arrangements. However, when such assets are not utilized or are under-utilized, our profitability is negatively
affected because the revenues we earn are either non-existent or reduced (in the event of under-utilization), but we remain
obligated to continue paying any applicable fixed charges, in addition to incurring any other costs attributable to the non-
utilization of such assets. For example, in connection with our operations, we lease all of our railcars that obligate us to pay the
applicable lease rate without regard to utilization. If business conditions are such that we do not utilize a portion of our leased
assets for any period of time, we will still be obligated to pay the applicable fixed lease rate. In addition, during the period of
time that we are not utilizing such assets, we will incur incremental costs associated with the cost of storing such assets, and we
will continue to incur costs for maintenance and upkeep. Our failure to utilize a significant portion of our leased assets and
other similar assets could have a significant negative impact on our profitability and cash flows.
In addition, certain of our field and pipeline operating costs and expenses are fixed and do not vary with the volumes
we gather and transport. These costs and expenses may not decrease ratably or at all should we experience a reduction in our
volumes transported by truck, marine vessel or rail or transported by our pipelines. As a result, we may experience declines in
our margin and profitability if our volumes decrease.
We cannot cause our joint ventures and certain of our unrestricted subsidiaries to take or not to take certain actions unless
some or all of the joint venture or third party participants agree.
Due to the nature of joint ventures, each participant (including us) in our material joint ventures has made substantial
investments (including contributions and other commitments) in that joint venture and, accordingly, has required that the
relevant charter documents contain certain features designed to provide each participant with the opportunity to participate in
the management of the joint venture and to protect its investment in that joint venture, as well as any other assets which may be
substantially dependent on or otherwise affected by the activities of that joint venture. These participation and protective
features include a governance structure that consists of a management committee composed of members, only some of which
are appointed by us. In addition, many of our joint ventures are operated by our “partners” and have “stand-alone” credit
agreements that limit their freedom to take certain actions. Thus, without the concurrence of the other joint venture participants
and/or the lenders of our joint venture participants, we cannot cause our joint ventures to take or not to take certain actions,
even though those actions may be in the best interest of the joint ventures or us. Similarly, third parties that invested in Alkali
Holdings’ equity have required that Alkali Holdings' governing documents contain certain features designed to protect their
investment. These features include a governance structure that consists of a board of managers composed of members, only a
majority of which are appointed solely by us. Certain fundamental decisions of Alkali Holdings may require consent of the full
board of managers and, thus, without the concurrence of one of more third parties, we cannot cause Alkali Holdings to take or
not to take certain fundamental actions, even though those actions may be in the best interest of Alkali Holdings or us.
The insolvency of an operator of our joint ventures, the failure of an operator of our joint ventures to adequately
perform operations or an operator’s breach of applicable agreements could reduce our revenue and result in our liability to
governmental authorities for compliance with environmental, safety and other regulatory requirements and to the operator’s
suppliers and vendors. As a result, the success and timing of development activities of our joint ventures operated by others and
the economic results derived therefrom depends upon a number of factors outside our control, including the operator’s timing
and amount of capital expenditures, expertise and financial resources, and the inclusion of other participants.
In addition, joint venture participants may have obligations that are important to the success of the joint venture, such
as the obligation to pay their share of capital and other costs of the joint venture. The third party equity investors in Alkali
Holdings have obligations to invest additional capital in Alkali Holdings, subject to certain conditions. The performance and
ability of third parties to satisfy their obligations under joint venture arrangements and Alkali Holdings’ governing documents
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is outside our control. If these third parties do not satisfy their obligations under these arrangements, our business may be
adversely affected.
We may not be able to renew our marine transportation time charters and contracts when they expire at favorable rates, for
extended periods, or at all, which may increase our exposure to the spot market and lead to lower revenues and increased
expenses.
During the year ended December 31, 2021, our marine transportation segment received approximately 49% of its
revenue from time charters and other fixed contracts, which help to insulate us from revenue fluctuations caused by weather,
navigational delays and short-term market declines. We earned approximately 51% of our marine transportation revenues from
spot contracts, where competition is high and rates are typically volatile and subject to short-term market fluctuations, and
where we bear the risk of vessel downtime due to weather and navigational delays. If we deploy a greater percentage of our
vessels in the spot market, we may experience a lower overall utilization of our fleet through waiting time or ballast voyages,
leading to a decline in our operating revenue and gross profit. There can be no assurance that we will be able to enter into future
time charters or other fixed contracts on terms favorable to us. For further discussion of our marine transportation contracts, see
“Marine Transportation - Customers”.
A decrease in the cost of importing refined petroleum products could cause demand for U.S. flag product carrier and barge
capacity and charter rates to decline, which would decrease our revenues and our ability to pay cash distributions on our
units.
The demand for U.S. flag product carriers and barges is influenced by the cost of importing refined petroleum
products. Historically, charter rates for vessels qualified to participate in the U.S. coastwise trade under the Jones Act have been
higher than charter rates for foreign flag vessels. This is due to the higher construction and operating costs of U.S. flag vessels
under the Jones Act requirements that such vessels be built in the U.S. and manned by U.S. crews. This has made it less
expensive for certain areas of the U.S. that are underserved by pipelines or which lack local refining capacity, such as in the
Northeast, to import refined petroleum products carried aboard foreign flag vessels than to obtain them from U.S. refineries. If
the cost of importing refined petroleum products decreases to the extent that it becomes less expensive to import refined
petroleum products to other regions of the East Coast and the West Coast than producing such products in the U.S. and
transporting them on U.S. flag vessels, demand for our vessels and the charter rates for them could decrease.
We face periodic dry-docking costs for our vessels, which can be substantial.
Vessels must be dry-docked periodically for regulatory compliance and for maintenance and repair. Our dry-docking
requirements are subject to associated risks, including delay, cost overruns, lack of necessary equipment, unforeseen
engineering problems, employee strikes or other work stoppages, unanticipated cost increases, inability to obtain necessary
certifications and approvals and shortages of materials or skilled labor. A significant delay in dry-dockings could have an
adverse effect on our marine transportation contract commitments. The cost of repairs and renewals required at each dry-dock
are difficult to predict with certainty and can be substantial.
The U.S. inland waterway infrastructure is aging and may result in increased costs and disruptions to our marine
transportation segment.
Maintenance of the U.S. inland waterway system is vital to our marine transportation operations. The system is
composed of over 12,000 miles of commercially navigable waterway, supported by over 240 locks and dams designed to
provide flood control, maintain pool levels of water in certain areas of the country and facilitate navigation on the inland river
system. The U.S. inland waterway infrastructure is aging, with more than half of the locks over 50 years old. As a result, due to
the age of the locks, scheduled and unscheduled maintenance outages may be more frequent in nature, resulting in delays and
additional operating expenses. Failure of the federal government to adequately fund infrastructure maintenance and
improvements in the future would have a negative impact on our ability to deliver products for our marine transportation
customers on a timely basis.
Failure to obtain or renew surety bonds on acceptable terms could affect our ability to secure reclamation obligations and,
therefore, our ability to conduct our mining operations.
We are required to obtain surety bonds or post other financial security to secure performance or payment of certain
long-term obligations, such as mine closure or reclamation costs. The amount of security required to be obtained can change as
the result of new laws, as well as changes to the factors used to calculate the bonding or security amounts. We may have
difficulty procuring or maintaining our surety bonds. Our bond issuers may demand higher fees or additional collateral,
including letters of credit or other terms less favorable to us upon those renewals. Because we are required to have these bonds
or other acceptable security in place before mining can commence or continue, our failure to maintain surety bonds, letters of
credit or other guarantees or security arrangements would materially and adversely affect our ability to mine trona. That failure
could result from a variety of factors, including lack of availability, higher expense or unfavorable market terms, the exercise by
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third-party surety bond issuers of their right to refuse to renew the surety and restrictions on availability of collateral for current
and future third-party surety bond issuers under the terms of our financing arrangements.
Risks Related to Liquidity and Financing
Our indebtedness could adversely restrict our ability to operate, affect our financial condition, prevent us from complying
with requirements under our debt instruments and prevent us from paying cash distributions to our unitholders.
We have outstanding debt and the ability to incur more debt. As of December 31, 2021, we had approximately $49.0
million outstanding of senior secured indebtedness and an additional $2.9 billion of senior unsecured indebtedness. We must
comply with various affirmative and negative covenants contained in our credit agreement and the indentures governing our
notes, some of which may restrict the way in which we would like to conduct our business. Among other things, these
covenants limit or will limit our ability to incur additional indebtedness or liens, make payments in respect of or redeem or
acquire any debt or equity issued by us, sell assets, make loans or investments, make guarantees, enter into any hedging
agreement for speculative purposes, acquire or be acquired by other companies, and amend some of our contracts.
The restrictions under our indebtedness may prevent us from engaging in certain transactions which might otherwise
be considered beneficial to us and could have other important consequences to unitholders. For example, they could increase
our vulnerability to general adverse economic and industry conditions, limit our ability to make distributions; to fund future
working capital, capital expenditures and other general partnership requirements; to engage in future acquisitions, construction
or development activities; to access capital markets (debt and equity); or to otherwise fully realize the value of our assets and
opportunities because of the need to dedicate a substantial portion of our cash flows from operations to payments on our
indebtedness or to comply with any restrictive terms of our indebtedness; limit our flexibility in planning for, or reacting to,
changes in our businesses and the industries in which we operate; and place us at a competitive disadvantage as compared to
our competitors that have less debt.
We may incur additional indebtedness (public or private) in the future under our existing credit agreement, by issuing
debt instruments, under new credit agreements, under joint venture credit agreements, under new credit agreements of our
unrestricted subsidiaries, under capital leases or synthetic leases, on a project-finance or other basis or a combination of any of
these. If we incur additional indebtedness in the future, it likely would be under our existing or replacement credit agreement or
under arrangements that may have terms and conditions at least as or even more restrictive as those contained in our existing
credit agreement and the indentures governing our existing notes. Failure to comply with the terms and conditions of any
existing or future indebtedness would constitute an event of default. If an event of default occurs, the lenders or noteholders will
have the right to accelerate the maturity of such indebtedness and foreclose upon the collateral, if any, securing that
indebtedness. In addition, if there is a change of control as described in our senior secured credit facility, that would be an event
of default, unless our creditors agreed otherwise, and, under our senior secured credit facility, any such event could limit our
ability to fulfill our obligations under our debt instruments and to make cash distributions to unitholders which could adversely
affect the market price of our securities.
In addition, from time to time, some of our joint ventures or unrestricted subsidiaries may have substantial
indebtedness, which will include affirmative and negative covenants and other provisions that limit their freedom to conduct
certain operations, events of default, prepayment and other customary terms.
We may not be able to access adequate capital (debt and/or equity) on economically viable terms or any terms.
The capital markets (debt and equity) have previously been from time to time disrupted and volatile as a result of
adverse conditions, including recessionary pressures, bubble-effects and precipitous commodity price declines. These
circumstances and events, which can last for extended periods of time, have led to reduced capital availability, tighter lending
standards and higher interest rates on loans for companies in the energy industry, especially non-investment grade companies.
Although we cannot predict the future condition of the capital markets, future turmoil in capital markets and the related higher
cost of capital could have a material adverse effect on our business, liquidity, financial condition and cash flows, particularly if
our ability to borrow money from lenders or access the capital markets to finance our operations were to be limited.
If we are unable to access the amounts and types of capital we seek at a cost and/or on terms that have been available
to us historically, we could be materially and adversely affected. Such an inability to access capital could limit or prohibit our
ability to execute significant portions of our business plan, such as executing our growth strategy, refinancing our debt and/or
optimizing our capital structure.
Our actual construction, development and acquisition costs could exceed our forecast, and our cash flow from construction
and development projects may not be immediate.
Our forecast contemplates significant expenditures for the development, construction or other acquisition of
infrastructure and mining assets, including some construction and development projects with technological challenges. We (or
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our joint ventures) may not be able to complete our projects at the costs or within the timeframes currently estimated. If we (or
our joint ventures) experience material cost overruns, we will have to finance these overruns using one or more of the following
methods: using cash from operations; delaying other planned projects; incurring additional indebtedness; or issuing additional
debt or equity.
Any or all of these methods may not be available when needed, may be prohibited or restricted by our or our joint
venture’s debt or other contractual arrangements or may adversely affect our future results of operations.
In addition, some construction projects require substantial investments over a long period of time before they begin
generating any meaningful cash flow.
Fluctuations in interest rates could adversely affect our business.
We have exposure to movements in interest rates. The interest rates on our senior secured credit facility ($49.0 million
outstanding at December 31, 2021) are variable. Our results of operations and our cash flow, as well as our access to future
capital and our ability to fund our growth strategy, could be adversely affected by significant increases in interest rates.
An increase in interest rates may also cause a corresponding decline in demand for equity investments, in general, and
in particular, for yield-based equity investments such as our common units. Any such reduction in demand for our common
units resulting from other more attractive investment opportunities may cause the trading price of our common units to decline.
Changes in the method pursuant to which the London Interbank Offered Rate (“LIBOR”), or the replacement of LIBOR
with an alternative reference rate, may adversely impact our business and results of operations.
We are exposed to market risks due to the floating interest rates on our senior secured credit facility. Obligations under
our senior secured credit facility bear interest at LIBOR rate or alternate base rate (which approximates the prime rate), at our
option, plus the applicable margin. We have not historically hedged our interest rates.
The U.K. Financial Conduct Authority, which regulates LIBOR, has announced that it will no longer persuade or
compel banks to submit rates for the calculation of LIBOR after 2021. In March 2021, the ICE Benchmark Administration
Limited, the administrator of LIBOR, extended the transition dates of certain LIBOR tenors to June 30, 2023, after which
LIBOR reference rates will cease to be provided. Despite this deferral, the LIBOR administrator has advised that no new
contracts using U.S. Dollar LIBOR should be entered into after December 31, 2021. It is unknown whether any banks will
continue to voluntarily submit rates for the calculation of LIBOR, or whether LIBOR will continue to be published by its
administrator based on these submissions, or on any other basis, after such dates.
In March 2020, the Financial Accounting Standards Board (“FASB”) issued ASU 2020-04, Reference Rate Reform
(Topic 848), which provides expedients and exceptions for accounting treatment of contracts which are affected by the
anticipated discontinuation of LIBOR and other rates resulting from rate reform. The Alternative Reference Rates Committee, a
group of market participants convened under the auspices of the U.S. Federal Reserve Board and other U.S. regulators, has
recommended the Secured Overnight Financing Rate (“SOFR”), calculated based on repurchase agreements backed by treasury
securities, as its recommended alternative benchmark rate to replace LIBOR. The consequences of these developments cannot
be entirely predicted but may include an increase in the interest rate on our senior secured credit facility when transitioning
from LIBOR to SOFR, which may have an adverse effect on our financial condition, operating results or cash flows.
Risks Related to Legal and Regulatory Compliance
Our operations are subject to federal, state and local environmental protection and safety laws and regulations.
Our operations are subject to stringent federal, state and local environmental protection and safety laws and
regulations. See “Regulation-Environmental Regulations.” 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. While we believe that we are in substantial compliance with current environmental laws
and regulations and that continued compliance with existing requirements would not materially affect us, there is no assurance
that this trend will continue in the future. Revised or new additional regulations that result in increased compliance costs or
additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material
adverse effect on our business, financial position, results of operations and cash flows. Moreover, our operations, including the
transportation and storage of crude oil, natural gas and other commodities, involves a risk that crude oil, natural gas and related
hydrocarbons or other substances may be released into the environment, which may result in substantial expenditures for a
response action, significant government penalties, liability to government agencies for natural resources damages, liability to
private parties for personal injury or property damages and significant business interruption. These costs and liabilities could
rise under increasingly strict environmental and safety laws, including regulations and enforcement policies, or claims for
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damages to property or persons resulting from our operations. If we are unable to recover such resulting costs through increased
rates or insurance reimbursements, our cash flows and distributions to our unitholders could be materially affected.
Climate change legislation and regulatory initiatives may decrease demand for the products we store, transport and sell and
increase our operating costs.
In recent years, federal, state, and local governments have taken steps to reduce emissions of GHGs. The EPA has
finalized a series of GHG monitoring, reporting and emission control rules for the oil and natural gas industry, and the U.S.
Congress has, from time to time, considered various proposals to reduce GHG emissions. Almost half of the states, either
individually or through multi-state regional initiatives, have already taken legal measures to reduce GHG emissions, primarily
through the planned development of GHG emission inventories and/or GHG cap-and-trade programs. In addition, states have
imposed increasingly stringent requirements related to the venting or flaring of gas during oil and gas operations. While we are
subject to certain federal GHG monitoring, reporting and emission control rules, our operations are not adversely and materially
impacted by existing federal, state and local climate change initiatives. However, our compliance with any future legislation or
regulation of GHGs, if it occurs, may result in materially increased compliance and operating costs.
In addition, in December 2015, the United States participated in the 21st Conference of the Parties (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. On April 21, 2021, the United States announced that it was setting an economy-wide
target of reducing its greenhouse gas emissions by 50-52 percent below 2005 levels in 2030. In November 2021, in connection
with the 26th Conference of the Parties (COP-26) in Glasgow, Scotland, the United States and other world leaders made further
commitments to reduce greenhouse gas emissions, including reducing global methane emissions by at least 30% by 2030.
Furthermore, many state and local leaders have stated their intent to intensify efforts to support the international climate
commitments.
Efforts to regulate or restrict emissions of GHGs in areas that we conduct business could adversely affect the demand
for the products that we transport, store and distribute and, depending on the particular program adopted, could increase our
costs to operate and maintain our facilities by requiring that we, among other things, measure and report our emissions, install
new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay any taxes related to our GHG
emissions and administer and manage a GHG emissions program. We may be unable to include some or all of such increased
costs in the rates charged by our pipelines or other facilities, and any such recovery may depend on events beyond our control,
including the outcome of future rate proceedings before the FERC or state regulatory agencies and the provisions of any final
legislation or implementing regulations. Any GHG emissions legislation or regulatory programs applicable to power plants or
refineries could also increase the cost of consuming, and thereby adversely affect demand for the crude oil and natural gas that
we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our
business, financial condition and results of operations. It is not possible at this time to predict with any accuracy the structure or
outcome of any future legislative or regulatory efforts to address such emissions or the eventual costs to us of compliance.
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.
President Biden’s regulatory agenda, and a closely divided Congress, creates some regulatory uncertainty for the oil and
natural gas industry. Changes in environmental laws could increase costs and harm our business, financial condition and
results of operations.
President Biden’s regulatory agenda, as well as a closely divided Congress, creates some regulatory uncertainty in the
oil and natural gas industry. President Biden has indicated that he is supportive of, and has issued several executive orders
promoting various programs and initiatives designed to, among other things, curtail climate change, control the release of
methane from new and existing oil and gas operations, and decarbonize electric generation and the transportation sector. It
remains unclear what additional actions the current administration will take and what support they will have for any potential
legislative changes from Congress. Further, it is uncertain to what extent any new environmental laws or regulations, or any
repeal of existing environmental laws or regulations, may affect our operations. However, such actions could materially
increase our costs or impair our ability to explore and develop other projects, which could materially harm our business,
financial condition and results of operations.
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We have reclamation and mine closing obligations. If the assumptions underlying our accruals are inaccurate, we could be
required to expend greater amounts than anticipated.
Our mining operations in Wyoming are subject to mine permits issued by the Land Quality Division of the Wyoming
Department of Environmental Quality (“WDEQ”). WDEQ imposes detailed reclamation obligations on us as a holder of mine
permits. We accrue for the costs of current mine disturbance and of final mine closure. The amounts recorded are dependent
upon a number of variables, including the estimated future closure costs, estimated proven reserves, assumptions involving
profit margins, inflation rates and the assumed credit-adjusted risk-free interest rates. If these accruals are insufficient or our
liability in a particular year is greater than currently anticipated, our future operating results could be materially adversely
affected.
Regulation of the rates, terms and conditions of services and a changing regulatory environment could affect our financial
position, results of operations or cash flow.
FERC regulates certain of our energy infrastructure assets engaged in interstate operations. Our intrastate pipeline
operations are regulated by state agencies. Our railcar operations are subject to the regulatory jurisdiction of the Federal
Railroad Administration of the DOT, the Occupational Safety and Health Administration, as well as other federal and state
regulatory agencies. This regulation extends to such matters as: rate structures; rates of return on equity; recovery of costs; the
services that our regulated assets are permitted to perform; the acquisition, construction and disposition of assets; and to an
extent, the level of competition in that regulated industry.
In addition, some of our pipelines and other infrastructure are subject to laws providing for open and/or non-
discriminatory access.
Given the extent of this regulation, the evolving nature of federal and state regulation and the possibility for additional
changes, the current regulatory regime may change and affect our financial position, results of operations or cash flow.
Our business would be adversely affected if we failed to comply with the Jones Act foreign ownership provisions.
We are subject to the Jones Act and other federal laws that restrict maritime cargo transportation between points in the
U.S. only to vessels operating under the U.S. flag, built in the U.S., at least 75% owned and operated by U.S. citizens (or owned
and operated by other entities meeting U.S. citizenship requirements to own vessels operating in the U.S. coastwise trade and,
in the case of limited partnerships, where the general partner meets U.S. citizenship requirements) and manned by U.S. crews.
To maintain our privilege of operating vessels in the Jones Act trade, we must maintain U.S. citizen status for Jones Act
purposes. To ensure compliance with the Jones Act, we must be U.S. citizens qualified to document vessels for coastwise trade.
We could cease being a U.S. citizen if certain events were to occur, including if non-U.S. citizens were to own 25% or more of
our equity interest or were otherwise deemed to control us or our general partner. We are responsible for monitoring ownership
to ensure compliance with the Jones Act. The consequences of our failure to comply with the Jones Act provisions on coastwise
trade, including failing to qualify as a U.S. citizen, would have an adverse effect on us as we may be prohibited from operating
our vessels in the U.S. coastwise trade or, under certain circumstances, permanently lose U.S. coastwise trading rights or be
subject to fines or forfeiture of our vessels.
Our business would be adversely affected if the Jones Act provisions on coastwise trade or international trade agreements
were modified or repealed or as a result of modifications to existing legislation or regulations governing the crude oil and
natural gas industry in response to the recent lifting of the crude oil export ban and the Deepwater Horizon drilling rig
incident in the U.S. Gulf of Mexico and subsequent crude oil spill.
If the restrictions contained in the Jones Act were repealed or altered or certain international trade agreements were
changed, the maritime transportation of cargo between U.S. ports could be opened to foreign flag or foreign-built vessels. The
Secretary of the Department of Homeland Security, or the Secretary, is vested with the authority and discretion to waive the
coastwise laws if the Secretary deems that such action is necessary in the interest of national defense. Any waiver of the
coastwise laws, whether in response to natural disasters or otherwise, could result in increased competition from foreign
product carrier and barge operators, which could reduce our revenues and cash available for distribution.
Foreign-flag vessels generally have lower construction costs and generally operate at significantly lower costs than we
do in U.S. markets, which would likely result in reduced charter rates. We believe that continued efforts will be made to modify
or repeal the Jones Act. If these efforts are successful, foreign-flag vessels could be permitted to trade in the U.S. coastwise
trade and significantly increase competition with our fleet, which could have an adverse effect on our business.
Events within the crude oil and natural gas industry may adversely affect our customers’ operations and, consequently,
our operations and may also subject companies operating in the crude oil and natural gas industry, including us, to additional
regulatory scrutiny and result in additional regulations and restrictions adversely affecting the U.S. crude oil and natural gas
industry.
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OSHA’s emergency temporary standard (“ETS”) mandating either fully vaccination or weekly testing of employees could
have a material adverse impact on our business and results of operations.
On November 5, 2021, OSHA announced an ETS requiring that employers with 100 or more employees to implement
and enforce a mandatory Covid-19 vaccination policy, unless they adopt a policy requiring employees to choose to either be
vaccinated or undergo weekly Covid-19 testing and wear a face covering in the workplace. On November 6, 2021, the ETS was
stayed by the U.S. Fifth Circuit Court of Appeals pending additional court review. The Biden administration requested that the
U.S. Fifth Circuit Court of Appeals reinstate the mandate. Multiple other lawsuits were filed regarding the ETS in various
jurisdictions. The pending lawsuits were consolidated before the U.S. Sixth Circuit Court of Appeals. On December 17, 2021,
the U.S. Sixth Circuit Court of Appeals lifted the injunction imposed by the U.S. Fifth Circuit Court of Appeals. Shortly after
the ruling, a number of petitions were filed with the U.S. Supreme Court, asking it to immediately block the mandate. On
January 13, 2022, the U.S. Supreme Court blocked the mandate. Subsequent to the U.S. Supreme Court’s decision, OSHA
withdrew the ETS effective January 26, 2022, although OSHA did not withdraw the proposed rule and indicated it is
prioritizing its resources to focus on finalizing a permanent COVID-19 Healthcare Standard. Additional vaccine mandates may
be announced in jurisdictions in which our businesses operate. Our implementation of any such requirements if and when they
are deemed to be enforceable may result in attrition, including attrition of critically skilled labor, and difficulty securing future
labor needs, which could have a material adverse effect on our business and financial condition, and may result in costs of
compliance that are difficult to quantify at this time.
Risks Related to Our Partnership Structure
Individual members of the Davison family can exert significant influence over us and may have conflicts of interest with us
and may be permitted to favor their interests to the detriment of our other unitholders.
James E. Davison and James E. Davison, Jr., each of whom is a director of our general partner, each own a significant
portion of our common units, including our Class B Common Units, the holders of which elect our directors. Other members of
the Davison family also own a significant portion of our common units. Collectively, members of the Davison family and their
affiliates own approximately 11.0% of our Class A Common Units and 77.0% of our Class B Common Units and are able to
exert significant influence over us, including the ability to elect at least a majority of the members of our board of directors and
the ability to control most matters requiring board approval, such as material business strategies, mergers, business
combinations, acquisitions or dispositions of assets, issuances of additional partnership securities, incurrences of debt or other
financings and payments of distributions. In addition, the existence of a controlling group (if one were to form) may have the
effect of making it difficult for, or may discourage or delay, a third party from seeking to acquire us, which may adversely
affect the market price of our common units. Further, conflicts of interest may arise between us and other entities for which
members of the Davison family serve as officers or directors. In resolving any conflicts that may arise, such members of the
Davison family may favor the interests of another entity over our interests.
Members of the Davison family own, control and have interests in diverse companies, some of which may (or could in
the future) compete directly or indirectly with us. As a result, the interests of the members of the Davison family may not
always be consistent with our interests or the interests of our other unitholders. Members of the Davison family could also
pursue acquisitions or business opportunities that may be complementary to our business. Our organizational documents allow
the holders of our units (including affiliates, like the Davisons) to take advantage of such corporate opportunities without first
presenting such opportunities to us. As a result, corporate opportunities that may benefit us may not be available to us in a
timely manner, or at all. To the extent that conflicts of interest may arise among us and any member of the Davison family,
those conflicts may be resolved in a manner adverse to us or you. Other potential conflicts may involve, among others, the
following situations: our general partner is allowed to take into account the interest of parties other than us, such as one or more
of its affiliates, in resolving conflicts of interest; our general partner may limit its liability and reduce its fiduciary duties, while
also restricting the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of
fiduciary duty; our general partner determines the amount and timing of asset purchases and sales, capital expenditures,
borrowings, issuance of additional partnership securities, reimbursements and enforcement of obligations to the general partner
and its affiliates, retention of counsel, accountants and service providers and cash reserves, each of which can also affect the
amount of cash that is distributed to our unitholders; and our general partner determines which costs incurred by it and its
affiliates are reimbursable by us and the reimbursement of these costs and of any services provided by our general partner could
adversely affect our ability to pay cash distributions to our unitholders.
Our Class B Common Units may be transferred to a third party without unitholder consent, which could affect our strategic
direction.
Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters
affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Only holders
of our Class B Common Units have the right to elect our board of directors. Holders of our Class B Common Units may transfer
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such units to a third party without the consent of the unitholders. The new holders of our Class B Common Units may then be in
a position to replace our board of directors and officers of our general partner with its own choices and to control the strategic
decisions made by our board of directors and officers.
Our general partner has a limited call right that may require unitholders to sell their units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80% of any class of our units, our general partner
will have the right, but not the obligation, which it may assign to any of its affiliates, including any controlling unitholder, or to
us, to acquire all, but not less than all, of the units held by unaffiliated persons at a price not less than their then-current market
price. As a result, unitholders may be required to sell their units at an undesirable time or price and may not receive any return
on their investment. Unitholders may also incur a tax liability upon a sale of their units.
The interruption of distributions to us from our subsidiaries and joint ventures could affect our ability to make payments on
indebtedness or cash distributions to our unitholders.
We are a holding company. As such, our primary assets are the equity interests in our subsidiaries and joint ventures.
Consequently, our ability to fund our commitments (including payments on our indebtedness) and to make cash distributions
depends upon the earnings and cash flow of our subsidiaries and joint ventures and the distribution of that cash to us. While
some of our joint ventures and our Alkali Business may generally be required to make cash distributions to us on a quarterly or
other periodic basis, distributions from our joint ventures and our unrestricted subsidiaries holding the Alkali Business are
subject to the discretion of their respective management committee or similar governing body in one or more respects even if
such distributions are generally required, such as with respect to the establishment of cash reserves. Further, the charter
documents of certain of our joint ventures and the unrestricted subsidiaries holding the Alkali Business may vest in the
management committees or similar governing body’s certain discretion or contain certain limitations regarding cash
distributions even if such distributions are generally required. Accordingly, our joint ventures and our unrestricted subsidiaries
holding the Alkali Business may not continue to make distributions to us at current levels or at all.
We do not have the same flexibility as other types of organizations to accumulate cash and equity to protect against
illiquidity in the future.
Unlike a corporation, our partnership agreement requires us to make quarterly distributions to our unitholders of all
available cash reduced by any amounts reserved for commitments and contingencies, including capital and operating costs and
debt service requirements. The value of our units and other limited partner interests may decrease in direct correlation with
decreases in the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the future, we may not be
able to issue more equity to recapitalize.
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them.
Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the
distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three
years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of
the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted
limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to
the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the
liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their
partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a
distribution is permitted.
Unitholder liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for
those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership
is organized under Delaware law, and we conduct business in other states. The limitations on the liability of holders of limited
partner interests for the obligations of a limited partnership have not been clearly established in some states in which we do
business or may do business in from time to time in the future. Unitholders could be liable for any and all of our obligations as
if unitholders were a general partner if a court or government agency were to determine that: we were conducting business in a
state but had not complied with that particular state’s partnership statute; or unitholders right to act with other unitholders to
remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under
our partnership agreement constitutes “control” of our business.
Tax Risks to Our Unitholders
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Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as us not being subject to
a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation (for U.S. federal
income tax purposes) or if we were to become subject to a material amount of entity-level taxation for state tax purposes,
then our cash available for distribution to our unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our units depends largely on our being treated as a
partnership for federal income tax purposes. Section 7704 of the Internal Revenue Code provides that publicly traded
partnerships will, as a general rule, be taxed as corporations. However, an exception exists with respect to publicly traded
partnerships, 90% or more of the gross income of which for each taxable year consists of “qualifying income.”
If less than 90% of our gross income for any taxable year is “qualifying income” from transportation, processing or
marketing of natural resources (including minerals, crude oil, natural gas or products thereof), interest or dividends income, we
will be taxable as a corporation under Section 7704 of the Internal Revenue Code for federal income tax purposes for that
taxable year and all subsequent years. We have not requested a ruling from the IRS with respect to our treatment as a
partnership for federal income tax purposes.
The decision of the U.S. Court of Appeals for the Fifth Circuit in Tidewater Inc. v. U.S., 565 F.3d 299 (5th Cir. April
13, 2009) held that the marine time charter being analyzed in that case was a “lease” that generated rental income rather than
income from transportation services for purposes of a foreign sales corporation provision of the Internal Revenue Code. Even
though (i) the Tidewater case did not involve a publicly traded partnership and it was not decided under Section 7704 of the
Internal Revenue Code relating to “qualifying income,” (ii) some experienced practitioners believe the decision was not well
reasoned, (iii) the IRS stated in an Action on Decision (AOD 2010-01) that it disagrees with and will not acquiesce to the Fifth
Circuit’s marine time charter analysis contained in the Tidewater case and (iv) the IRS has issued several favorable private
letter rulings (which can be relied upon and cited as precedent by only the taxpayers that obtained them) relating to time
charters since the Tidewater decision was issued, the Tidewater decision creates some uncertainty regarding the status of
income from certain of our marine time charters as “qualifying income” under Section 7704 of the Internal Revenue Code.
Notwithstanding the foregoing, the Tidewater case is relevant authority because it is the only case of which we and our outside
tax counsel are aware directly analyzing whether a particular time charter would constitute a lease or service agreement for
certain U.S. federal tax purposes. Due to the uncertainty created by the Tidewater decision, our outside tax counsel, Akin Gump
Strauss Hauer & Feld, LLP, was required to change the standard in its opinion relating to our status as a partnership for federal
income tax purposes to “should” from “will.”
Although we do not believe based upon our current operations that we are treated as a corporation for federal income
tax purposes, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal
income tax purposes or otherwise subject us to taxation as an entity. If we were treated as a corporation for federal income tax
purposes, we would pay federal income tax on our taxable income at the corporate tax rate and would pay state income tax at
varying rates. Distributions to our unitholders would generally be taxable to them again as corporate distributions and no
income, gains, losses, or deductions would flow through to them. Because a tax would be imposed upon us as a corporation, our
cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation
would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a
substantial reduction in the value of our units.
At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to
subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For
example, we are required to pay Texas franchise tax on our gross income apportioned to Texas. Imposition of any such taxes on
us by any other state would reduce our cash available for distribution to our unitholders.
The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative,
judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our
units may be modified by administrative, legislative or judicial interpretation at any time. From time to time, members of
Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded
partnerships, including the elimination of partnership tax treatment for certain publicly traded partnerships.
Any modifications to the U.S. federal income tax laws may be applied retroactively and could make it more difficult
or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal
income tax purposes. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted.
Any such changes could cause a material reduction in our anticipated cash flows and could cause us to be treated as an
association taxable as a corporation for U.S. federal income tax purposes subjecting us to the entity-level tax and adversely
affecting the value of our units.
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A successful IRS contest of the federal income tax positions we take may adversely affect the market for our units, and the
costs of any IRS contest would reduce our cash available for distribution to our unitholders and our general partner.
The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or
court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we
take. Any contest with the IRS may materially and adversely impact the market for our units and the price at which they trade.
In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because
these costs will reduce our cash available for distribution.
Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes
adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties
and interest) resulting from such audit adjustments directly from us. To the extent possible under the new rules, our general
partner may elect to either cause us to pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we
are eligible, issue a revised information statement to each unitholder and former unitholder with respect to an audited and
adjusted return. Although our general partner may elect to have it, our unitholders and former unitholders take such audit
adjustments into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their
interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or
effective in all circumstances. If we make payments of taxes and any penalties and interest directly to the IRS in the year in
which the audit is completed, our cash available for distribution to our unitholders might be substantially reduced, in which case
our current unitholders may bear some or all of the tax liability resulting from such audit adjustments, even if such unitholders
did not own units in us during the tax year under audit.
Our unitholders will be required to pay taxes on income (as well as deemed distributions, if any) from us even if they do not
receive any cash distributions from us.
Our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on
their share of our taxable income (as well as deemed distributions, if any) even if unitholders receive no cash distributions from
us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income (or deemed
distributions, if any) or even the tax liability that results from that income (or deemed distribution).
Tax gain or loss on the disposition of our units could be more or less than expected.
If our unitholders sell their units, they will recognize a gain or loss equal to the difference between the amount realized
and their tax basis in those units. Because distributions in excess of their allocable share of our net taxable income decrease
their tax basis in their units, the amount, if any, of such prior excess distributions with respect to the units a unitholder sells will,
in effect, become taxable income to the unitholder if it sells such units at a price greater than its tax basis in those units, even if
the price received is less than its original cost. A substantial portion of the amount realized, whether or not representing gain,
may be ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount
realized includes a unitholder’s share of our non-recourse liabilities, if our unitholders sell their units, they may incur a tax
liability in excess of the amount of cash they receive from the sale.
Unitholders may be subject to limitations on their ability to deduct interest expense by us.
Our ability to deduct interest paid or accrued on indebtedness properly allocable to our trade or business during our
taxable year may be limited in certain circumstances. If this limitation were to apply with respect to a taxable year, it could
result in an increase in the taxable income allocable to a unitholder for such taxable year without any corresponding increase in
the cash available for distribution to such unitholder. However, in certain circumstances, a unitholder may be able to utilize a
portion of a business interest deduction subject to this limitation in future taxable years. Unitholders should consult their tax
advisors regarding the impact of this business interest deduction limitation on an investment in our units.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our units that may result in adverse tax
consequences to them.
Investment in our units by tax-exempt entities, such as individual retirement accounts (known as IRAs), other
retirement plans and non-U.S. persons, raises issues unique to them. For example, virtually all of our income allocated to
organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business
taxable income and will be taxable to them. With respect to taxable years beginning after December 31, 2017, subject to the
proposed aggregation rules for certain similarly situated businesses or activities issued by the Treasury Department, a tax-
exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as
ours) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each
trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning
after December 31, 2017, it may not be possible for tax exempt entities to utilize losses from an investment in our partnership to
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offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should
consult a tax advisor before investing in our units.
Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income
effectively connected with a U.S. trade or business (“effectively connected income”). Income allocated to our unitholders and
any gain from the sale of our units will generally be considered to be “effectively connected” with a U.S. trade or business. As
a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a
non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized
from the sale or disposition of that unit. Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade
or business is generally required to withhold 10% of the “amount realized” by the transferor unless the transferor certifies that it
is not a foreign person. While the determination of a partner's “amount realized” generally includes any decrease of a partner’s
share of the partnership’s liabilities, recently issued Treasury regulations provide that the “amount realized” on a transfer of an
interest in a publicly traded partnership, such as our common units, will generally be the amount of gross proceeds paid to the
broker effecting the applicable transfer on behalf of the transferor, and thus will be determined without regard to any decrease
in that partner’s share of a publicly traded partnership’s liabilities. The Treasury regulations further provide that withholding on
a transfer of an interest in a publicly traded partnership will not be imposed on a transfer that occurs prior to January 1, 2023,
and after that date, if effected through a broker, the obligation to withhold is imposed on the transfer’s broker. Non-U.S.
unitholders should consult a tax advisor before investing in our units.
We will treat each purchaser of our common units as having the same tax benefits without regard to the common units
actually purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.
Because we cannot match transferors and transferees of our common units, we adopt depreciation and amortization
conventions that may not conform to all aspects of existing Treasury Regulations and may result in audit adjustments to our
unitholders’ tax returns without the benefit of additional deductions. A successful IRS challenge to those conventions could
adversely affect the amount of tax benefits available to a common unitholder. It also could affect the timing of these tax benefits
or the amount of gain from a sale of common units and could have a negative impact on the value of our common units or result
in audit adjustments to the common unitholder’s tax returns.
Our unitholders will likely be subject to state and local taxes in states where they do not live as a result of an investment in
our units.
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including foreign, state and
local taxes, unincorporated business taxes and estate inheritance or intangible taxes that are imposed by the various jurisdictions
in which we do business or own property, even if our unitholders do not live in any of those jurisdictions. Our unitholders will
likely be required to file foreign, state, and local income tax returns and pay state and local income taxes in some or all of these
jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently
own assets and do business in more than 20 states including Texas, Louisiana, Mississippi, Alabama, Florida, Arkansas and
Oklahoma. Many of the states we currently do business in impose a personal income tax. It is our unitholders’ responsibility to
file all applicable U.S. federal, foreign, state and local tax returns. Unitholders should consult with their own tax advisors
regarding the filing of such tax returns, the payment of such taxes, and the deductibility of any taxes paid.
We have subsidiaries that are treated as corporations for federal income tax purposes and subject to corporate-level income
taxes.
We conduct a portion of our operations through subsidiaries that are, or are treated as, corporations for federal income
tax purposes. We may elect to conduct additional operations in corporate form in the future. These corporate subsidiaries will
be subject to corporate-level tax, which, effective for taxable years beginning after December 31, 2017, is 21%, and will likely
pay state (and possibly local) income tax at varying rates, on their taxable income. Any such entity level taxes will reduce the
cash available for distribution to us and, in turn, to our unitholders. If the IRS were to successfully assert that these corporate
subsidiaries have more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, our cash
available for distribution to our unitholders would be further reduced.
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We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each
month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular
unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss
and deduction among our unitholders.
We generally prorate our items of income, gain, loss, and deduction between transferors and transferees of our units
each month based upon the ownership of our units on the first day of each month (the “Allocation Date”), instead of on the
basis of the date a particular unit is transferred. Similarly, we generally allocate (i) certain deductions for depreciation of capital
additions, (ii) gain or loss realized on a sale or other disposition of our assets and (iii) in the discretion of the general partner,
any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury
Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our
proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of
income, gain, loss and deduction among our unitholders.
A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed
of those units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those units
during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as
having disposed of the loaned units, such unitholder may no longer be treated for tax purposes as a partner with respect to those
units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition.
Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units
may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully
taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a
loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing
their units.
The IRS could challenge our treatment of the holders of Class A Convertible Preferred Units as partners for tax purposes,
and if such challenge were sustained, certain holders of Class A Convertible Preferred Units could be adversely impacted.
The IRS may disagree with our treatment of the Class A Convertible Preferred Units as equity for U.S. federal income
tax purposes, and no assurance can be given that our treatment will be sustained. If the IRS were to successfully characterize
the Class A Convertible Preferred Units as indebtedness for tax purposes, certain holders of Class A Convertible Preferred
Units may be subject to additional withholding and reporting requirements. Further, if the Class A Convertible Preferred Units
were treated as indebtedness for U.S. federal tax purposes, rather than equity, distributions likely would be treated as payments
of interest by us to the holders of Class A Convertible Preferred Units. Holders of Class A Convertible Preferred Units are
encouraged to consult their tax advisors regarding the tax consequences applicable to the re-characterization of the Class A
Convertible Preferred Units as indebtedness for tax purposes.
The amount that a Class A Convertible Preferred unitholder would receive upon liquidation may be less than the liquidation
value of the Class A Convertible Preferred Units.
In general, we intend to specially allocate to the Class A Convertible Preferred Units items of our gross income in an
amount equal to the distributions paid in respect of the Class A Convertible Preferred Units during the taxable year. If the
distributions paid in respect of the Class A Convertible Preferred Units during a taxable year exceed the amount of our gross
income allocated to the Class A Convertible Preferred Units for such taxable year (as in the case of prior distributions during
the PIK period), the per unit capital account balance of the Class A Convertible Preferred unitholders would be reduced by the
amount of such excess. If we were to dissolve or liquidate, after satisfying all of our liabilities, our unitholders (including the
Class A Convertible Preferred unitholders) would be entitled to receive liquidating distributions in accordance with their capital
account balances. In such event, Class A Convertible Preferred unitholders would be specially allocated items of gross income
and gain in a manner designed to cause the capital account balance of a preferred unit to equal the liquidation value of a
preferred unit. If we were to have insufficient gross income and gain to cause the capital account balance to equal the
liquidation value of a preferred unit, then the amount that a Class A Convertible Preferred unitholder would receive upon
liquidation would be less than the liquidation value of the Class A Convertible Preferred Units, even though there may be cash
available for distribution to the holders of common units or any other junior securities with respect to their capital accounts.
General Risks
We are exposed to the credit risk of our customers in the ordinary course of our business activities.
When we (or our joint ventures) market our products or services, we (or our joint ventures) must determine the
amount, if any, of the line of credit. Since certain transactions can involve very large payments, the risk of nonpayment and
nonperformance by customers, industry participants and others is an important consideration in our business.
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For example, in those cases where we provide division order services for crude oil and natural gas purchased at the
wellhead, we may be responsible for distribution of proceeds to all of the interest owners. In other cases, we pay all of or a
portion of the production proceeds to an operator who distributes these proceeds to the various interest owners. These
arrangements expose us to operator credit risk. As a result, we must determine that operators have sufficient financial resources
to make such payments and distributions and to indemnify and defend us in case of a protest, action or complaint.
Additionally, we sell NaHS, soda ash and caustic soda to customers in a variety of industries. Some of these customers
are in industries that have been impacted by a decline in demand for their products and services. Even if our credit review and
analytical procedures work properly, we have experienced, and we could continue to experience losses in dealings with other
parties.
We, along with one other U.S. trona-based soda producer, utilize ANSAC as our exclusive export vehicle for sales to
customers in all countries excluding Canada, South Africa and members of the European Community and European Free Trade
Area. Because ANSAC makes sales to its end customers directly and then allocates a portion of such sales to each member, we
do not have direct access to ANSAC’s customers and we have no direct control over the credit or other terms ANSAC extends
to its customers. As a result, we are indirectly exposed to ANSAC’s customer relationship and the credit and other terms
ANSAC extends to its customers. In addition, if ANSAC ceased to exist, we could face costs and risks of securing those
customers and related logistics arrangements on favorable terms.
Further, many of our customers could be impacted by weakened economic conditions, and volatility in commodity
prices, such as crude oil, natural gas, copper, molybdenum, and aluminum in a manner that could influence the need for our
products and services and their ability to pay us for those products and services. It is uncertain to what extent commodity prices
will experience increased volatility in the future.
A natural disaster, pandemic, epidemic, accident, terrorist attack or other interruption event could result in an economic
slowdown, severe personal injury, property damage and/or environmental damage, which could curtail our operations or
otherwise adversely affect our assets and cash flow.
Some of our operations involve significant risks of severe personal injury, property damage and environmental
damage, any of which could curtail our operations or otherwise expose us to liability and adversely affect our cash flow.
Virtually all of our operations are exposed to the elements, including hurricanes, tornadoes, storms, floods, earthquakes and
extended periods of below freezing weather. A significant portion of our operations are located along the U.S. Gulf Coast, and
our offshore pipelines are located in the Gulf of Mexico. These areas can be subject to hurricanes.
If one or more facilities that are owned by us or that connect to us or our customers is damaged or otherwise affected
by severe weather or any other disaster, pandemic, epidemic, accident, catastrophe or event, our operations could be
significantly interrupted. Similar interruptions could result from damage to production or other facilities that supply our
facilities or other stoppages arising from factors beyond our control. These interruptions might involve significant damage to
people, property or the environment, and repairs or recovery might take from a week or less for a minor incident to six months
or more for a major interruption. Any event that interrupts the fees generated by our energy infrastructure assets, or which
causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying our interest
obligations as well as unitholder distributions and, accordingly, adversely impact the market price of our securities.
Additionally, the proceeds of any property insurance maintained by us may not be paid in a timely manner or be in an amount
sufficient to meet our needs if such an event were to occur, and we may not be able to renew it or obtain other desirable
insurance on commercially reasonable terms, if at all.
Any terrorist attack at our facilities, those of our customers and, in some cases, those of other pipelines, could have a
material adverse effect on our business.
In addition, a natural disaster, pandemic, epidemic, accident, terrorist attack or other interruption event may cause
significant volatility in global financial markets, disruptions to commerce and reduced economic activity. The resulting
macroeconomic conditions could adversely affect our cash flows, as well as the market price of our securities.
The widespread outbreak of an illness, pandemic (like Covid-19) or any other public health crisis may have material adverse
effects on our business, financial position, results of operations and/or cash flows.
In December 2019, a novel strain of coronavirus (SARS-Cov-2), which causes Covid-19, was reported to have
surfaced in China. The spread of this virus has caused business disruption, including disruption to the oil and natural gas and
industrial industries. In March 2020, the World Health Organization declared the outbreak of Covid-19 to be a pandemic, and
the U.S. economy began to experience pronounced effects. The Covid-19 pandemic has negatively impacted the global
economy, disrupted global supply chains, reduced global demand for oil and gas, petroleum products and industrial products,
and created significant volatility and disruption of financial and commodity markets. The extent of the impact of the Covid-19
pandemic on our operational and financial performance, including our ability to execute our business strategies and initiatives
in the expected time frame, is uncertain and depends on various factors, including the demand for oil and natural gas, petroleum
products and industrial products (including the impact that reductions in travel, manufacturing and consumer product demand
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have had and will have on the demand for commodities), the availability of personnel, equipment and services critical to our
ability to operate our assets and the impact of potential governmental restrictions on travel, transportation and operations. There
is uncertainty around the extent and duration of the disruption. The degree to which the Covid-19 pandemic or any other public
health crisis adversely impacts our results will depend on future developments, which are highly uncertain and cannot be
predicted. These developments include, but are not limited to, the duration and spread of the outbreak, its severity, the actions to
contain the virus or treat its impact, its impact on the economy and market conditions and how quickly and to what extent
normal economic and operating conditions can resume. These potential impacts, while uncertain, could adversely affect our
operating results.
Compliance with and changes in cybersecurity requirements have a cost impact on our business, and failure to comply with
such laws and regulations could have an impact on our assets, costs, revenue generation and growth opportunities.
In the second quarter of 2021, the Department of Homeland Security’s Transportation Security Administration
(“TSA”) announced two new security directives. These directives require critical pipeline owners to comply with mandatory
reporting measures and provide vulnerability assessments. We may be required to expend significant additional resources to
respond to cyberattacks, to continue to modify or enhance our protective measures, or to assess, investigate and remediate any
critical infrastructure security vulnerabilities. Any failure to remain in compliance with these government regulations may
results in enforcement actions which may have a material adverse effect on our business and operations.
Our business could be negatively impacted by security threats, including cybersecurity threats, and related disruptions.
We rely on our information technology infrastructure to process, transmit and store electronic information, including
information we use to safely operate our assets. While we believe that we maintain appropriate information security policies
and protocols, we face cybersecurity and other security threats to our information technology infrastructure, which could
include threats to our operational and safety systems that operate our pipelines, facilities and other assets. We could face
unlawful attempts to gain access to our information technology infrastructure, including coordinated attacks from hackers,
whether state-sponsored groups, “hacktivists” or private individuals. The age, operating systems or condition of our current
information technology infrastructure and software assets and our ability to maintain and upgrade such assets could affect our
ability to resist cybersecurity threats.
Our information technology infrastructure is critical to the efficient operation of our business and essential to our
ability to perform day-to-day operations. Breaches in our information technology infrastructure or physical facilities, or other
disruptions, could result in damage to our assets, loss of intellectual property, impairment of our ability to conduct our
operations, disruption of our customers’ operations, loss or damage to our customer data delivery systems, safety incidents,
damage to the environment and could have a material adverse effect on our operations, financial position and results of
operations. It is also possible that breaches to our systems could go unnoticed for some period of time.
We and our third-party service providers may therefore be vulnerable to security events that are beyond our control,
and we may be the target of cyber-attacks, as well as physical attacks, which could result in information security breaches and
significant disruption to our business. Such data breaches and cyberattacks could compromise our operational or other
capabilities and cause significant damage to our business and our reputation. Our information systems have experienced threats
to the security of our digital infrastructure, but none of these have had a significant impact on our business, operations or
reputation relating to such attacks. We maintain a 24/7 dedicated security operations center to anticipate, detect and prevent
cyberattacks; however, there is no assurance that we will not suffer such losses or breaches in the future. As cyberattacks
continue to evolve, we may be required to expend significant additional resources to respond to cyberattacks, to continue to
modify or enhance our protective measures or to investigate and remediate any information systems and related infrastructure
security vulnerabilities. We may also be subject to regulatory investigations or litigation relating from cybersecurity issues.
Our significant unitholders may sell units or other limited partner interests in the trading market, which could reduce the
market price of our common units.
As of December 31, 2021, we have a number of significant unitholders. For example, certain members of the Davison
family (including their affiliates) and management owned approximately 18 million, or approximately 14%, of our common
units. From time to time, we also may have other unitholders that have large positions in our common units. In the future, any
such parties may acquire additional interest or dispose of some or all of their interest. If they dispose of a substantial portion of
their interest in the trading markets, such sales could reduce the market price of common units. In connection with certain
transactions, we have put in place resale shelf registration statements, which allow unit holders thereunder to sell their common
units at any time (subject to certain restrictions) and to include those securities in any equity offering we consummate for our
own account.
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We may issue additional common units without unitholders’ approval, which would dilute their ownership interests.
We may issue an unlimited number of limited partner interests of any type without the approval of our unitholders.
The issuance of additional common units or other equity securities of equal or senior rank will have the following effects: our
unitholders’ proportionate ownership interest in us will decrease; the amount of cash available for distribution on each unit may
decrease; the relative voting strength of each previously outstanding unit may be diminished; and the market price of our
common units may decline.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
See Item 1. “Business,” in addition to the Summary Overview of Mining Operations disclosure below. We also have
various operating leases for rental of office space, facilities and field equipment and transportation equipment. See
“Commitments and Off-Balance Sheet Arrangements” in Management’s Discussion and Analysis of Financial Condition and
Results of Operations, and Note 4 to our Consolidated Financial Statements in Item 8 for details on our right of use assets and
related lease liabilities. Such information is incorporated herein by reference.
Summary Overview of Mining Operations
Information concerning our mining properties in this Annual Report on Form 10-K has been prepared in accordance
with the requirements of subpart 1300 of Regulation S-K, which first became applicable to us for the fiscal year ended
December 31, 2021. These requirements differ significantly from the previously applicable disclosure requirements of SEC
Industry Guide 7. Among other differences, subpart 1300 of Regulation S-K requires us to disclose our mineral resources, in
addition to our mineral reserves, as of the end of our most recently completed fiscal year for our material mining property.
As used in this Annual Report on Form 10-K, the terms “mineral resource,” “measured mineral resource,” “indicated
mineral resource,” “inferred mineral resource,” “mineral reserve,” “proven mineral reserve” and “probable mineral reserve” are
defined and used in accordance with subpart 1300 of Regulation S-K. Under subpart 1300 of Regulation S-K, mineral resources
may not be classified as “mineral reserves” unless the determination has been made by a qualified person that the mineral
resources can be the basis of an economically viable project. You are specifically cautioned not to assume that any part or all of
the mineral deposits (including any mineral resources) in these categories will ever be converted into mineral reserves, as
defined by the SEC.
You are further cautioned that, except for that portion of mineral resources classified as mineral reserves, mineral
resources do not have demonstrated economic value. Inferred mineral resources are estimates based on limited geological
evidence and sampling and have too high of a degree of uncertainty as to their existence to apply relevant technical and
economic factors likely to influence the prospects of economic extraction in a manner useful for evaluation of economic
viability. Estimates of inferred mineral resources may not be converted to mineral reserves. A significant amount of exploration
must be completed in order to determine whether an inferred mineral resource may be upgraded to a higher category of
mineralization and it cannot be assumed that this will occur. Therefore, you are cautioned not to assume that all or any part of
an inferred mineral resource exists, that it can be the basis of an economically viable project, or that it will ever be upgraded to
a higher category of mineralization. Likewise, you are cautioned not to assume that all or any part of measured or indicated
mineral resources will ever be converted to mineral reserves.
The information that follows is derived, in part, from the technical report summary (“TRS”) prepared by Stantec
Consulting Services Inc., an external qualified person (“QP”) in compliance with Item 601(b)(96) and subpart 1300 of
Regulation S-K. Portions of the following information are based on assumptions, qualifications and procedures that are not
fully described herein. Reference should be made to the full text of the TRS, filed as Exhibit 96.1 hereto, incorporated herein by
reference and made a part of this Annual Report on Form 10-K.
Overview of Mining Property and Operations
Our Alkali Business is one of the world’s leading producers of natural soda ash. Natural soda ash is processed from
trona, a sodium carbonate mineral composed of soda ash (Na2CO3), sodium bicarbonate (NaHCO3) and water with the chemical
formula Na2CO3NaHCO3H2O. 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. Our trona mining and processing
facilities are located in southwestern Wyoming approximately 18 miles west of the city of Green River, Wyoming. The
following maps show the location of our mining property, as of December 31, 2021:
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Figure 2.1. General Location Map
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Figure 2.2. Map of Mining Areas
The Green River trona beds are collectively the largest known deposit of trona and the undisputed largest source of
raw material feed for the production of natural soda ash in the world. The trona deposits are 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 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
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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 three feet in thickness and are estimated by the U.S. Geological Survey (“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 depths between approximately 400 to 2,000 feet. Our current dry mining and solution mining operations
exploit three trona beds, and our reserves are contained in four trona beds.
Genesis has one trona mineral property, located in the Known Sodium Leasing Area in Southwest Wyoming, primarily
encompassed by the Westvaco area and the Granger area. Due to differences in geology between these two mine areas, the
mineral leases and, ultimately, the trona resources and reserve estimates have been separated into Westvaco contiguous leases,
Granger contiguous leases and Granger non-contiguous leases. The table and figures below are summaries of our acreage under
each mineral lease type as of December 31, 2021.
Area by lessor (acres)
Contiguous leases
Non-contiguous leases
Location
Granger
Westvaco
Granger
Remaining
Federal
State
Sweetwater
Total Area
4,236
1,280
8,320
13,836
19,699
6,403
27,520
53,622
—
640
4,480
5,120
320
13,280
—
13,600
Our trona resources and mining operations are held under leases covering 86,178 acres 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 Sweetwater. We lease approximately 24,255 acres
from the U.S. Government under the Mineral Leasing Act of 1920 (Title 30 §181) which includes trona under its definition of a
“solid leasable mineral.” Federal minerals are administered by the U.S. Bureau of Land Management (“BLM”). We lease
40,320 acres from Sweetwater who acquired the mineral rights from Anadarko Land Corporation, a subsidiary of Occidental
following Occidental’s August 2019 acquisition of Anadarko Petroleum Corporation, which acquired the ownership from the
Union Pacific Resources Group (“UPRG”) in 2000. The lease includes 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 21,603 acres from the State of Wyoming. Our mineral leases have varying terms. Our private leases are
held indefinitely by production, BLM and State Leases expire and are renewed every 10 years. Royalty payments range from
2% to 8% of the sales value of soda ash products. We believe that all of our leases were entered into at market terms.
BXC owns preferred units in Alkali Holdings, which is an indirect parent entity of our subsidiary that owns all the
leases and operates all of our mining properties. See Item 1 “Business—Recent Developments and Status of Certain Growth
Initiatives—Granger Production Facility Expansion” for more information.
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Figure 2.3. Lease Tenure
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The table below shows certain key information for leases in the Westvaco contiguous leases, Granger contiguous
leases, and Granger non-contiguous leases that are included in the resource and reserve estimates, including lessor, lease term,
size, royalty information and expiration date.
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Our Westvaco site is a production stage property that mines trona through both dry mining and solution mining
methods. The Westvaco mine has been in uninterrupted, continuous operation since its start in 1947 by Westvaco Chemical
Company. We acquired the Westvaco facility in September 2017.
The location of the Westvaco site and contiguous lease boundary can be found in Figure 2.2. It is located in
Sweetwater County, Wyoming, 18 miles west of Green River and is accessible from Interstate 80 (I-80), a four-lane divided
highway. I-80 exit 72 is approximately seven miles from the processing plant. The Union Pacific Railroad passes just north of
the Westvaco facilities with siding to access the mainline. The two main population centers of Green River, Wyoming and Rock
Springs, Wyoming are 18 miles and 30 miles to the east, respectively. Evanston, Wyoming is 66 miles to the west. The area
population provides a more than adequate base for staffing the Westvaco facilities, with a pool of talent for management.
The Westvaco site has been in continuous operation since 1947. Westvaco Chemical Corporation notified Union
Pacific in 1946 of its intention to sink a mine shaft and to construct a trona processing plant. A shaft was sunk in 1947 to the top
of Bed 17 bringing the first skipload of trona to the surface in late 1947. In the fall of 1948, Westvaco Chemical Corporation
was acquired by the Food Machinery Corporation (later known as “FMC”). In 1952, the Westvaco Division of FMC formed the
Intermountain Chemical Company as Wyoming’s first trona mining company. In 1953, Intermountain Chemical Company
began producing refined soda ash by a sesquicarbonate process through a plant with a 300,000-ton capacity. The Alkali
Chemical Division of FMC, including the trona mining and processing operations in the Green River Basin of Wyoming, was
acquired by Tronox Alkali in May 2015. In September 2017, we acquired the Westvaco facility from Tronox Alkali and
currently operate the facility through Genesis Alkali Wyoming, LP.
Infrastructure on the Westvaco site is very well developed as the facilities have been in operation for nearly seventy
years. The infrastructure consists of sufficient truck and rail loadout facilities, electrical generation and transmission facilities,
tailings facilities, product storage facilities, process facilities, natural gas pipelines and distribution facilities and water
pipelines, treatment and distribution facilities. The Westvaco site also has ample buildings for offices, labs, change rooms,
warehouses and maintenance shops.
Our Granger site is a production stage property that mines trona through solution mining methods.
The location of the Granger site and contiguous lease boundary can be found in Figure 2.2. The Granger site is located
in Sweetwater County, Wyoming and can be accessed by traveling eight miles west of Green River, Wyoming on I-80, then
turning north on state highway 372 and traveling about 12 miles to county road 11. The Granger site is accessible to the Union
Pacific Railroad by a spur line that connects to the mainline near the town of Granger, Wyoming. The two main population
centers of Green River, Wyoming and Rock Springs, Wyoming are 18 miles and 30 miles to the east, respectively. Evanston,
Wyoming is 66 miles to the west. The area population provides a more than adequate base for staffing the Granger facilities,
with a pool of talent for management.
The Granger mine and processing facility operated as an underground mine from 1976 to 2002. FMC acquired the
properties in 1999 by acquiring Tg Soda Ash Inc., originally developed as a unit of Texasgulf and then owned by Elf Atochem.
FMC converted the mine and mill to solution mining in 2005. The Alkali Chemical Division of FMC, including the trona
mining and processing operations in the Green River Basin of Wyoming, was acquired by Tronox Alkali in May 2015. In
September 2017, we acquired the Granger facility from Tronox Alkali and currently operate the facility through Genesis Alkali
Wyoming, LP.
Infrastructure on the Granger site is very well developed as the facilities have operated for over 35 years. The
infrastructure consists of sufficient rail loadout facilities, electrical transmission facilities, tailings facilities, product storage
facilities, process facilities, natural gas pipelines and distribution facilities and water pipelines, treatment and distribution
facilities. The Granger site also has ample buildings for offices, labs, change rooms, warehouses and maintenance shops.
As both the Westvaco site and Granger site have been operating for many years, all permits necessary for the operation
of these facilities are in place. The Westvaco site includes approximately 36,000 permitted acres, of which the processing,
support facilities, and tailings and evaporation ponds cover about 2,600 surface acres. The Granger facility includes about
16,000 permitted acres of which the processing, support facilities, and tailings and evaporation ponds cover about 1,800 surface
acres. 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. With respect to each
facility, permits, licenses and approvals are obtained as needed in the normal course of business based on our mine plans and
federal, state, provincial and local regulatory provisions regarding mine permitting and licensing. There have been no
outstanding violations or orders that would prevent continued operation of the plants and mines. This includes air, land, surface
and groundwater, drinking water, wildlife, and waste. Approved reclamation plans are in place along with surety in the amounts
of approximately $43 million for the Westvaco site and $23 million for the Granger site. Based on our historical permitting
experience, we expect to be able to continue to obtain necessary mining permits and approvals to support historical rates of
production.
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At our Wyoming property, we use both mechanical and solution mining to mine the trona ore:
•
•
Dry Mining of Trona Ore. We extract trona ore from our Westvaco underground mine by mechanized, continuous
mining methods. Our current underground dry mine production is from trona bed 17, a near-horizontal bed
approximately 10 feet thick at a depth from the surface of 1,500-1,650 feet. Ore is extracted primarily by our single
longwall mining machine 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 the vertical hoisting shafts. 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 our processing facilities or stored on two 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 sodium carbonate and
sodium bicarbonate from the trona left behind during previous dry mining. Multiple pumping systems are used to
pump the enriched brine to the surface for processing.
Our mineral recovery consists of four processing plants producing soda ash at two surface sites, Westvaco and
Granger.
Dry mined and solution mined trona are processed into soda ash at our Westvaco site, located within the boundaries of
our Westvaco contiguous lease blocks, involving multiple processing lines, steam generation facilities, evaporation ponds, spare
parts warehouses, maintenance shops, and offices for engineering, production, and support staff. Mineral recovery at Westvaco
site consists of three plants: the Sesqui plant, the Mono plant and the evaporation, lime, decahydrate crystallization, and
monohydrate crystallization (“ELDM”) plant.
Our Sesqui and Mono plants process dry-mined trona into soda ash. Crushing, dissolution in water, filtration, and
crystallization techniques are used to produce the desired final products. The Mono plant consists of two separate processing
lines to produce soda ash. Mono I began operation in May 1972, while Mono II was started up in January 1976. In the Mono
plant, the ore is calcined with heat, prior to dissolution, to process the trona into soda ash by the removal of water and carbon
dioxide. A final calcining step using steam produces a dense soda ash product from the Mono process. The Sesqui plant was the
first soda ash plant built and operated at the Westvaco site. In our Sesqui plant, the calcination is performed at the end of the
process, producing a light density soda ash that is preferred in applications desiring increased absorptivity. The Sesqui process
also has the ability to produce refined sodium sesquicarbonate (which we sell under the names S-Carb® and Sesqui®™) for use
as a buffer in animal feed formulations and in cleaning and personal care applications.
Our ELDM plant was constructed in 1995 and started operations in 1996. Our ELDM plant uses the tailings return
water as a feed source for soda ash production. Solution mined trona is processed into dense soda ash in our ELDM operation.
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.
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Figure 2.4 Westvaco Surface Production Facilities
The Westvaco site also has a facility producing food, feed, and pharmaceutical grade sodium bicarbonate from a
Sesqui plant intermediate product. Fifty percent caustic is produced on the Westvaco site for commercial sale from a Mono
plant intermediate product.
The Westvaco site has successfully mined and processed trona ore at a profit for over 70 years. In this time, capital has
been expended as appropriate to sustain the operation at the current production and operating cost level. We plan for capital
expenditures necessary to replace equipment and facilities over time in order to sustain production and operating costs. We
believe that the Westvaco site and its operating equipment are maintained in good working condition.
Solution mined trona is processed into soda ash at our Granger plant, located within the boundaries of the Granger
contiguous lease blocks, and involves multiple processing lines, steam generation facilities, evaporation ponds, spare parts
warehouses, maintenance shops, and offices for engineering, production, and support staff. 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. The approximately 500,000 short tons of soda ash capacity at our Granger facility was put
in cold standby in April 2020 as a result of price and demand erosion driven largely by the Covid-19 pandemic.
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Figure 2.5. Granger Surface Production Facilities
The Granger site has successfully mined and processed trona ore at a profit for over 35 years. In this time, capital has
been expended as appropriate to sustain the operation at the current production and operating cost level. The Granger
Optimization Project is underway with the upgraded operation scheduled to start in the second half of 2023. Capital
expenditures are generally for sustaining production and operating costs except for some remaining capital for our Granger
Optimization Project. We believe that the Granger site and its operating equipment are maintained in good working condition.
The total book value of the Westvaco and Granger sites as of December 31, 2021 was approximately $1,439 million.
In many cases, market demand drives annual production so that actual production may be less than plant capacities.
The table below shows annual production from our trona property and its four plants for the fiscal years ended December 31,
2021, 2020 and 2019.
Total (in thousands of tons)
3,483
3,206
4,014
Year ended December 31,
2021
2020
2019
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Summaries of our mineral resources and reserves for the fiscal year ended December 31, 2021 are set forth in the
tables below:
Area
Resource Category(1)
Million short tons (dry
weight)
Grade (% Trona)(2)
Granger Contiguous Leases
Westvaco Contiguous Lease Area
Granger Non-Contiguous Leases
Total
Total
Measured
Indicated
Measured + Indicated
Measured
Indicated
Measured + Indicated
Inferred
Measured
Indicated
Measured + Indicated
Inferred
Measured + Indicated
Measured + Indicated + Inferred
618
145
763
1,072
158
1,230
4
87
60
147
3
2,140
2,147
84
89
85
88
84
87
80
85
84
85
84
86
86
(1) Mineral resources are exclusive of mineral reserves, which are summarized in the table below. Mineral resources are not mineral
reserves and do not have demonstrated economic viability. There is no certainty that all or any part of the mineral resources will be
converted into mineral reserves upon application of modifying factors.
(2) Based on the analysis described in Section 11.3 of the TRS, no economic cutoff grade has been applied to the resource given the
long history of uninterrupted trona mining on the property, spatial consistency of the trona content and overall low insoluble and
halite content. No elements or compounds from within the beds were identified as having a material impact on the ability to extract
trona from the beds via mechanical or solution mining methods.
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Reserve Area/Type
Westvaco dry extraction
Westvaco solution mining
Granger solution mining
Resource Category
Proven(2)
Probable(2)
Total Reserves(3)
Proven(2)
Probable(2)
Total Reserves(4)
Proven(2)
Probable(2)
Total Reserves(4)
Total solution mining
Total Reserves(4)
Total dry extraction and solution mining Total Reserves
December 31, 2021
December 31, 2020
Million short tons
(dry weight)(1)
Grade
(% Trona)(5)
Million short tons
(dry weight)(1)
Grade
(% Trona)(5)
257
179
436
—
371
371
—
72
72
443
879
88
88
88
88
88
85
85
88
87
290
158
448
—
392
392
—
50
50
442
890
90
86
86
85
85
86
88
(1) Our trona ore reserves are calculated from in-place trona-bearing material that can be economically and legally extracted and
processed into commercial products at the time of reserve determination. Our reserves estimates are developed using industry-
standard procedures and have been reviewed internally and externally to ensure compliance with subpart 1300 of Regulation S-K.
(2) We use “measured and indicated” resources as the primary basis in determining our proven and probable reserves. We define
proven reserves and probable reserves as follows:
a.
b.
Proven dry-mining reserves are measured reserves that fall within a 0.5 mile radius from drillhole data points or
previously mined areas with a 7.0 feet minimum ore thickness.
Probable dry-mining reserves are indicated reserves that fall between 0.5 miles and 1.0 miles from drillhole data points or
previously mined areas with a 7.0 feet minimum ore thickness.
c. All solution mining reserves are designated as probable based on the degree of confidence in the reserve estimate related
to uncertainties involving solution flow paths, trona ore surface area available for dissolution, and the inaccuracy of
depletion verification methods. They consist of both measured resources falling within a 0.5 mile radius from drillhole
data points or previously mined areas and indicated resources that fall between 0.5 miles and 1.0 miles from drillhole data
points or previously mined areas. Solution mining reserves are not limited to a minimum ore thickness, but rather are
subjected to a 50 foot halo limit into large blocks of trona adjacent to areas impacted by previous dry mining and adjacent
to areas planned for future dry mining.
(3) Estimated dry mining ore reserves include dilution from un-mineralized material within and marginal to the trona ore bed. We
exclude support pillars from dry mining reserves, but a portion of the trona contained in the pillars is recovered by solution mining.
We apply a bulk density factor of 133 lb/cu ft for conversion of volumes to mass. Key dry mining parameters include minimum
trona ore bed thickness.
(4) Our solution mining ore reserves are reported on an in-place basis, inclusive of dilution from insoluble material that remains in the
ground. The solution mining reserves are calculated using recovery parameters developed from our 20-plus years of cumulative
secondary recovery solution mining experience. Key factors include the surface area of remaining support pillars and other trona-
mineralized surfaces exposed to liquid solutions injected into voids created by dry mining, solubility and alkalinity data, and
predicted dissolution rates.
(5) Our ore reserves have a minimum trona grade of 66.2% (occurs in Bed 15). The balance of the ore consists of clays, shales, and
other impurities.
Total trona reserves for the fiscal year ended December 31, 2021 decreased 11 million short tons from fiscal year
ended December 31, 2020, representing approximately 1.2% of the total reserves.
Our 2020 reserve disclosure was partially based on the assessment of Norwest Corp, an external consulting company,
that generated a reserve estimate in 2015 and an updated reserve estimate as of September 1, 2017, meeting SEC 7 guidance.
Our year end 2020 reported reserves reflected that September 1, 2017 estimate, reconciled with 2017, 2018, 2019, and 2020
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depletion. Our 2021 reserves are partially based on as assessment completed by Stantec Consulting Inc., an external QP,
meeting the requirements of subpart 1300 of Regulation S-K.
Dry mining reserves at year end 2021 are 12 million short tons, or 2.7%, lower than year end 2020 reserves as a result
of 4.4 million tons of dry mine extraction in 2021 and a more conservative layout used in development of the updated long term
mine plan by the external consultant. The new layout leaves additional resource behind underneath areas near surface features
such as highways.
Solution mining reserves are essentially the same at year end 2021 as they were at year end 2020 despite 1.4 million
tons of solution based extraction in 2021 as a result of some modified assumptions applied by the external consultant in
development of the 2021 reserve estimate. The 2021 reserve assessment includes higher ultimate secondary solution mining
extraction percentage of the trona left behind by previous dry mining, based on actual secondary recovery that has been
achieved in certain areas of the Westvaco mine. The gain in extraction percentage is largely offset by a more conservative
assumption that removed certain areas of the Westvaco mine from the solution extractable base. The previous external
assessment, which provided the basis for the 2020 year end reserves, assumed those areas were recoverable after the ultimate
completion of dry mining at Westvaco.
Our mineral resource and reserve estimates are based on many factors, including the area and volume covered by our
mining rights, assumptions regarding our extraction rates (based upon an expectation of operating the mines on a long-term
basis) and the quality of in-place reserves. Key assumptions and parameters relating to our mineral resources and reserves at the
Westvaco site are discussed in the TRS, and include, among other things, the following:
•
•
•
•
•
•
•
•
•
•
•
•
•
The economic analysis of our resources and reserves was prepared based on 2022 dollars with annual inflation at 2.5%
which has been applied to revenue, operating costs, and capital spending.
The production schedule to mine and process the remaining reserves is based on the existing production capacity of the
mine and processing plants.
Bed 15, which lies approximately 35 to 55 feet below bed 17, can be effectively dry mined starting in roughly the year
2071, after the completion of longwall mining in overlying areas of Bed 17.
Future secondary solution mining recoveries are similar to those that have been demonstrated thus far in certain areas
of our Westvaco mine.
Prices for bulk soda ash are based on the 2020 USGS price, which was escalated to establish the 2022 price while
prices for bag and specialty products were consistent with recent history.
Cash production costs include dry mining, solution mining, processing, royalties and production taxes, insurance, and
administrative costs. Administrative costs include mine administration and corporate overhead allocations. Other costs
include distribution, sales general and administrative, and research and development costs.
The operating costs are based on our historical averages. Other costs are based on our five-year estimate. Costs are
assumed to be similar in the future with annual inflation similar to pricing inflation. Modeled underground dry mining
costs include a step change in approximately 50 years when longwall mining is phased out and replaced by borer and
continuous mining in Bed 15 and the remaining areas of Bed 17.
Capital expenditures are generally for sustaining production and operating costs. Sustaining cap-ex in the future is
assumed similar to recent history and short term projections, with inflation similar to product pricing escalation.
All leases remain valid throughout the time required to mine the reserves
All permits remain valid throughout the life of the operation, and no new laws are enacted that require any
extraordinary compliance which would significantly impact production or cost.
New permits and approved mine plans will be obtained for mining reserves that lie within existing leases, but outside
of our current mining permit areas.
Tailings storage capacity will be developed as necessary over the life of the mine and processing plants.
Because our Alkali Business is structured as a pass-through entity for income tax purposes, there is no provision for
income taxes in the cash flow analysis.
Internal Control Disclosure
The modeling and analysis of our resources and reserves has been developed by our mine personnel and reviewed by
several levels of internal management and external consultants, including the QP. The development of such resources and
reserves estimates, including related assumptions, was a collaborative effort between the QP and our management. This section
summarizes the internal control considerations for our development of estimations, including assumptions, used in resource and
reserve analysis and modeling.
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When determining resources and reserves, as well as the differences between resources and reserves, management
developed specific criteria, each of which must be met to qualify as a resource or reserve, respectively. These criteria, such as
demonstration of economic viability, points of reference and grade, are specific and attainable. The QP and our management
agree on the reasonableness of the criteria for the purposes of estimating resources and reserves. Calculations using these
criteria are reviewed and validated by the QP.
We base our mineral reserve estimates on detailed geological, geotechnical, mine engineering and mineral processing
inputs, and financial models developed and reviewed by management and technical staff of our Alkali Business, who possess
years of experience directly related to the resources, mining and processing characteristics or financial performance of our
operations. Additionally, our management and technical staff includes senior personnel who have remained closely involved
with each of our active mining and mineral processing operations.
In preparing our reserve estimates for our Alkali operations at Green River, Wyoming, we follow accepted mining
industry practice and are guided by our long-term experience in extraction of trona ore from underground mining and sodium
carbonate from solution mining in the district. Estimates of recoverable reserves for both techniques are routinely reconciled
with actual production, and our Alkali ore reserves disclosures comply with subpart 1300 of Regulation S-K.
All estimates require a combination of historical data and key assumptions and parameters. When possible, resources
and data from generally accepted industry sources, such as governmental resource agencies, were used to develop these
estimations.
Management also assesses risks inherent in mineral resource and reserve estimates, such as the accuracy of
geophysical data that is used to support mine planning, identify hazards and inform operations of the presence of mineable
deposits. Also, management is aware of risks associated with potential gaps in assessing the completeness of mineral extraction
licenses, entitlements or rights, or changes in laws or regulations that could directly impact the ability to assess mineral
resources and reserves or impact production levels. Risks inherent in overestimated reserves can impact financial performance
when revealed, such as changes in amortizations that are based on life of mine estimates.
Documentation of sample security measures, quality control and assurance (“QAQC”) was not observed by the QP.
However, given that there has been successful underground dry mining of Bed 17 and Bed 20 within and nearby the exploration
sample sites, it would appear that previous sampling methods, sample security, analysis methods, and internal QAQC measures
met the requirements for successful mine planning over the history of the Westvaco site and Granger site mining operations.
Item 3. Legal Proceedings
We are involved from time to time in various claims, lawsuits and administrative proceedings incidental to our
business. In our opinion, the ultimate outcome, if any, of such proceedings is not expected to have a material adverse effect on
our financial condition, results of operations or cash flows. See Note 21 to our Consolidated Financial Statements in Item 8.
Item 103 of SEC Regulation S-K requires disclosure of certain environmental matters when a governmental authority
is a party to the proceedings and such proceedings involve potential monetary sanctions that we reasonably believe will exceed
a specified threshold. Pursuant to recent SEC amendments to this item, we will be using a threshold of $1 million for such
proceedings. We believe that such threshold is reasonably designed to result in disclosure of environmental proceedings that are
material to our business or financial condition. Applying this threshold, there are no environmental matters to disclose for this
period.
Item 4. Mine Safety Disclosures
Information regarding mine safety and other regulatory action at our mine in Green River, Wyoming is included in
Exhibit 95 to this Form 10-K.
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PART II
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
Our Class A common units are listed on the New York Stock Exchange, or NYSE, under the symbol “GEL.”
At February 24, 2022, we had 122,539,221 Class A common units outstanding. As of December 31, 2021, the closing
price of our common units was $10.71 and we had approximately 31,000 record holders of our Class A common units, which
include holders who own units through their brokers “in street name.” Additionally, we have issued 25,336,778 Class A
Convertible Preferred Units for which there is no established public trading market.
•
•
Available cash generally means, for each fiscal quarter, all cash on hand at the end of the quarter:
less the amount of cash reserves that our general partner determines in its reasonable discretion is necessary or
appropriate to:
•
•
•
provide for the proper conduct of our business;
comply with applicable law, any of our debt instruments, or other agreements; or
provide funds for distributions to our unitholders for any one or more of the next four quarters;
plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital
borrowings. Working capital borrowings are generally borrowings that are made under our senior secured credit
facility and in all cases are used solely for working capital purposes or to pay distributions to partners.
The full definition of available cash is set forth in our partnership agreement and amendments thereto, which are
incorporated by reference as an exhibit to this Form 10-K.
See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and
Capital Resources – Capital Expenditures and Distributions Paid to our Unitholders” and Note 11 to our Consolidated Financial
Statements in Item 8 for further information regarding restrictions on our distributions. See Item 12. “Security Ownership of
Certain Beneficial Owners and Management and Related Unitholder Matters” for information regarding securities authorized
for issuance under equity compensation plans.
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Item 6. Selected Financial Data
None.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Introduction
We are a growth-oriented master limited partnership formed in Delaware in 1996. Our common units are traded on the
New York Stock Exchange, or NYSE, under the ticker symbol “GEL.” We are (i) a provider of an integrated suite of midstream
services (primarily transportation, storage, sulfur removal, blending, terminaling 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 crude oil and natural gas pipeline transportation and handling operations in the Gulf of Mexico 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 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 2021. 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 Alkali Business. Our Alkali Business mines and processes trona from
which it produces natural soda ash, also known as sodium carbonate (Na2CO3), a basic building block for a number of
ubiquitous products, including flat glass, container glass, dry detergent and a variety of chemicals and other industrial products.
Our Alkali Business has a diverse customer base in the United States, Canada, the European Community, the European Free
Trade Area and the South African Customs Union with many long-term relationships. It has been operating for over 70 years
and has an estimated remaining reserve life (based on 2021 production) of over 100 years.
Included in Management’s Discussion and Analysis are the following sections:
•
•
•
•
•
•
•
•
•
Overview of 2021 Results
Recent Developments and Initiatives
Results of Operations
Other Consolidated Results
Financial Measures
Liquidity and Capital Resources
Guarantor Summarized Financial Information
Critical Accounting Estimates
Recent Accounting Pronouncements
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Overview of 2021 Results
We reported Net Loss Attributable to Genesis Energy, L.P. of $165.1 million in 2021 compared to Net Loss
Attributable to Genesis Energy, L.P. of $416.7 million in 2020.
Net Loss Attributable to Genesis Energy, L.P. in 2020 was negatively impacted by impairment expense of
$280.8 million primarily associated with the rail logistics assets included within our onshore facilities and transportation
segment and a loss on sale of assets of $22.0 million. Net Loss Attributable to Genesis Energy, L.P. in 2021 was impacted,
relative to 2020, by higher segment margin of $10.3 million and higher non-cash revenues of approximately $25.4 million
primarily within our onshore facilities and transportation and offshore pipeline transportation segments as a result of how we
recognize revenue in accordance with GAAP on certain contracts.
These increases were partially offset by the following during 2021: (i) higher interest expense of $23.9 million; (ii)
higher depreciation, depletion, and amortization expense of $14.4 million; (iii) higher general and administrative costs of $4.3
million; and (iv) lower equity in earnings of equity investees of $6.1 million primarily due to lower volumes on our Poseidon
oil pipeline. See “Other Costs, Interest, and Income Taxes” below for additional discussion regarding the changes to interest
expense, depreciation depletion and amortization, and general and administrative costs. Additionally, 2021 includes an
unrealized (non-cash) loss from the valuation of the embedded derivative associated with our Class A Convertible Preferred
Units of $30.8 million compared to an unrealized (non-cash) loss of $0.9 million in 2020 recorded within “Other expense, net.”
“Other expense, net” in 2020 also includes a loss on the extinguishment of our 2022 and 2023 Notes of approximately $32.0
million partially offset by cancellation of debt income of $27.3 million from the repurchase of certain of our senior unsecured
notes on the open market throughout the year. Lastly, we allocated net income to our noncontrolling interest holders of $27.0
million during 2021 as compared to $16.4 million during 2020.
Cash flows from operating activities were $338.0 million for the 2021 period compared to $296.7 million for 2020.
This increase was primarily attributable to higher segment margin reported during 2021.
Available Cash before Reserves (as defined below in “Financial Measures”) decreased $51.4 million in 2021 to $203.9
million as compared to 2020 Available Cash before Reserves of $255.3 million, primarily due to higher interest expense of
$23.9 million, higher maintenance capital utilized of $12.3 million, and 2020 including cancellation of debt income of $27.3
million. These decreases were partially offset by an increase in segment margin of $10.3 million during 2021 further discussed
below in “Results from Operations.” See “Financial Measures” below for additional information on Available Cash before
Reserves.
Segment Margin was $617.7 million in 2021, an increase of $10.3 million as compared to 2020. We currently manage
our businesses through four divisions that constitute our reportable segments - offshore pipeline transportation, sodium minerals
and sulfur services, onshore facilities and transportation and marine transportation. A more detailed discussion of our segment
results and other costs is included below in “Results of Operations”.
Distributions to Unitholders
On February 14, 2022, we paid a distribution of $0.15 per unit related to the fourth quarter of 2021.
With respect to our Class A Convertible Preferred Units, we declared a quarterly cash distribution of $0.7374 per
preferred unit (or $2.9496 on an annualized basis) for each preferred unit held of record. These distributions were paid on
February 14, 2022 to unitholders holders of record at the close of business January 31, 2022.
Recent Developments and Initiatives
Our primary objectives continue to be to generate and grow stable cash flows and deleverage our balance sheet, while
maintaining financial flexibility and never wavering from our commitment to safe and responsible operations. We believe we
are well positioned to do this as a result of the following strategies and initiatives:
•
•
the long-term contracted commercial opportunities in the Gulf of Mexico, which are scheduled for first production
in the first half of 2022, that will provide significant incremental volumes on our offshore pipeline transportation
assets with existing connectivity and available capacity, which require minimal to no additional investment from
us;
the normalization and recovery of soda ash markets from the declines in 2020, including both price and volume
recovery;
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•
•
•
the increased capacity for soda ash production in 2023 with the expectation to bring the original Granger facility
production back online in the first quarter of 2023 and further increased production capacity from our Granger
Optimization Project, which is scheduled to begin first production in the second half of 2023;
the sale of a 36% minority equity interest in CHOPS for gross proceeds of approximately $418 million, which
represents a premium relative to the proportionate carrying value of CHOPS at the transaction date; and
our recent debt transactions, including the repayment of the $300 million outstanding under the Term Loan under
our new credit agreement, and the renewal and extension of the maturity on our senior secured credit facility to
mature in 2024 with a current maximum revolving borrowing capacity of $650 million.
These developments and initiatives are discussed in more detail below.
Granger Optimization Project
On September 23, 2019, we announced the Granger Optimization Project. We entered into agreements with BXC for
the purchase of up to a total of $350 million of preferred units (or 350,000 preferred units) in Alkali Holdings. The proceeds we
receive from BXC will assist in the funding of the anticipated cost of the GOP, subject to compliance with the covenants
contained in our agreements with BXC. The preferred unitholders receive PIK in lieu of cash distributions through September
2023, which represents the anticipated construction period.
On April 14, 2020, we entered into an amendment to our agreements with BXC to, among other things, extend the
construction timeline of the GOP by one year, to 2023. In consideration for the amendment, we issued 1,750 Alkali Holdings
preferred units to BXC, which was accounted for as issuance costs. As of December 31, 2021, there are 246,394 Alkali
Holdings preferred units outstanding. During the fourth quarter of 2021, we made the decision to fund the remaining
construction costs required to complete the GOP internally through a combination of our generated free cash flow and
availability under our Revolving Loan.
We expect to increase capacity for soda ash production in 2023 with the expectation to bring the original Granger
facility and its approximately 500,000 tons of production back online in the first quarter of 2023 and further increase production
capacity from our GOP, which is scheduled to begin first production in the second half of 2023 and ramp to its design capacity
of an additional 750,000 tons per year over the subsequent nine to twelve months.
Credit Facility Amendment
On April 8, 2021, we entered into our new credit agreement to replace our Fourth Amended and Restated Credit
Agreement. Our new credit agreement initially provided for a $950 million senior secured credit facility, comprised of a
Revolving Loan with a borrowing capacity of $650 million and a Term Loan of $300 million. Our Term Loan was paid off in
full with a portion of the proceeds received from the sale of a 36% interest in CHOPS (discussed further below). The new credit
agreement matures on March 15, 2024, subject to extension at our request for one additional year on up to two occasions and
subject to certain conditions.
Senior Unsecured Note Transactions
On April 22, 2021, we completed our offering of an additional $250 million in aggregate principal amount of our 2027
Notes (as defined in Note 10). The notes constitute an additional issuance of our existing 2027 Notes that we issued on
December 17, 2020 in an aggregate principal amount of $750 million. The additional $250 million of notes have identical terms
as (other than with respect to the issue price) and constitute part of the same series of the 2027 Notes. The $250 million of the
2027 Notes were issued at a premium of 103.75% plus accrued interest from December 17, 2020. We used the net proceeds
from the offering for general partnership purposes, including repaying a portion of the revolving borrowings outstanding under
our new credit agreement.
On December 17, 2020, we issued $750.0 million in aggregate principal amount of our 2027 Notes. That issuance
generated net proceeds of approximately $737 million, net of issuance costs incurred. We used $316.5 million of the net
proceeds to repay the portion of our 2023 Notes (including principal, accrued interest and tender premium) that were validly
tendered, and the remaining proceeds at the time were used to repay a portion of the borrowings outstanding under our senior
secured credit facility. On January 19, 2021, we redeemed the remaining principal balance outstanding on our 2023 Notes of
$80.9 million in accordance with the terms and conditions of the indenture governing the 2023 Notes. We incurred a total loss
of approximately $1.6 million relating to the extinguishment of our remaining 2023 Notes, inclusive of the redemption fee and
the write-off of the related unamortized debt issuance costs, which is recorded in “Other expense, net” in our Unaudited
Condensed Consolidated Statement of Operations for the year ended December 31, 2021.
Sale of a Minority Interest in CHOPS
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On November 17, 2021, we closed on the sale of a 36% minority equity interest in CHOPS for gross proceeds of
approximately $418 million (which represents a premium relative to the proportionate carrying value of CHOPS). Proceeds
from the sale, net of fees and expenses, were used to repay the full $300 million outstanding under our Term Loan and the
remainder will be utilized for general partnership purposes, including our decision to internally fund the remaining capital
expenditures associated with the GOP. We own 64% of CHOPS and remain the operator of the pipeline.
Covid-19 and Market Update
In March 2020, the World Health Organization categorized Covid-19 as a pandemic, and the President of the United
States declared the Covid-19 outbreak a national emergency. Our operations, which fall within the energy, mining and
transportation sectors, are considered critical and essential by the Department of Homeland Security's Cybersecurity and
Infrastructure Security Agency and we have continued to operate our assets during this pandemic.
We have a designated internal management team to provide resources, updates, and support to our entire workforce
during this pandemic, while maintaining a focus to ensure the safety and well-being of our employees, the families of our
employees, and the communities in which our businesses operate. We will continue to act in the best interests of our
employees, stakeholders, customers, partners, and suppliers and make any necessary changes as required by federal, state, or
local authorities as we continue to actively monitor the situation.
Covid-19 has caused continued volatility in commodity prices due to, among other things, reduced industrial activity
and travel demand, varying worldwide restrictions, and the timing of the re-opening of economies throughout the last two years
that are expected to continue in the near future. Additionally, actions taken by the Organization of the Petroleum Exporting
Countries (OPEC) and other oil exporting nations beginning in early March 2020 caused additional volatility in the price of oil
and gas. While we have seen continued recovery in commodity prices since the beginning of the pandemic, primarily due to
economies re-opening over time, there is still an element of volatility that we expect to continue at least for the near-term and
possibly longer, due to the continued uncertainty of the pandemic, which could further negatively impact oil, natural gas,
petroleum products and industrial products.
Due to the economic effects from commodity price volatility and Covid-19, demand and volumes throughout our
businesses were negatively impacted beginning in the second quarter of 2020. Additionally, during 2020, our businesses were
negatively impacted by lower refinery utilization, crude differentials, supply and demand imbalances in our Alkali Business,
and an unprecedented hurricane season. However, we began to see economic recovery across a majority of our asset footprint
as we exited 2020, which continued throughout 2021. Specifically, during 2021, oil and natural gas prices have seen a recovery
from the lows experienced in 2020 and our offshore pipeline transportation segment experienced volumes at its normal run rate
as we resumed normal operations on our CHOPS pipeline. Additionally, our Alkali Business has continued to see volume
demand recovery and continued pricing recovery on our ANSAC export volumes.
We will continue to monitor the market environment and will evaluate whether additional triggering events would
indicate possible impairments of long-lived assets, intangible assets and goodwill. Management’s estimates are based on
numerous assumptions about future operations and market conditions, which we believe to be reasonable but are inherently
uncertain. The uncertainties underlying our assumptions could cause our estimates to differ significantly from actual results,
including with respect to the duration and severity of the Covid-19 pandemic. In the current volatile economic environment and
to the extent conditions deteriorate, we may identify triggering events that may require future evaluations of the recoverability
of the carrying value of our long-lived assets, intangible assets and goodwill, which could result in impairment charges that
could be material to our results of operations.
Although the ultimate impacts of Covid-19 are still unknown at this time, we believe the fundamentals of our core
businesses continue to remain strong and, given the current industry environment and capital market behavior, we have
continued our focus on deleveraging our balance sheet as further explained above.
Results of Operations
In the discussions that follow, we will focus on our revenues, expenses and Net income (loss), as well as two measures
that we use to manage the business and to review the results of our operations - Segment Margin and Available Cash before
Reserves. Segment Margin and Available Cash before Reserves are defined in the “Financial Measures” section below.
Revenues, Costs and Expenses
Our revenues for the year ended December 31, 2021 increased $300.8 million, or 16%, from the year ended December
31, 2020, and our costs and expenses (excluding the loss on sale of assets and impairment expense in 2020) increased $282.0
million, or 16%, between the two periods, with a net increase to operating income (loss) of $18.8 million. The increase in our
operating income during 2021 is primarily attributable to increased volumes and pricing within our sodium minerals and sulfur
services segment and increased volumes in our offshore pipeline transportation segment. These increases were partially offset
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by lower rail unload and onshore pipeline volumes in our onshore facilities and transportation segment and lower day rates in in
our marine transportation segment, primarily associated with our inland barge operation and our M/T American Phoenix tanker,
as well as higher depreciation, depletion and amortization and general and administrative expenses during 2021.
A substantial portion of our revenues and costs are derived from the purchase and sale of crude oil in our crude oil
marketing business, which is included in our onshore facilities and transportation segment, revenues and costs associated with
our Alkali Business, which is included in our sodium minerals and sulfur services segment, and revenues and costs associated
with our offshore pipeline transportation segment. We describe, in more detail, the impact on revenues and costs for each of our
businesses below.
As it relates to our crude oil marketing business, the average closing prices for West Texas Intermediate crude oil on
the New York Mercantile Exchange (“NYMEX”) increased approximately 73% to $68.14 in 2021 as compared to $39.40 per
barrel in 2020. We would expect changes in crude oil prices to continue to proportionately affect our revenues and costs
attributable to our purchase and sale of crude oil and petroleum products, producing minimal direct impact on Segment Margin,
Net Income, and Available Cash before Reserves. We have limited our direct commodity price exposure in our crude oil and
petroleum products operations through the broad use of fee-based service contracts, back-to-back purchase and sale
arrangements, and hedges. As a result, changes in the price of crude oil would proportionately impact both our revenues and our
costs, with a disproportionately smaller net impact on our Segment Margin. However, we do have some indirect exposure to
certain changes in prices for oil and petroleum products, particularly if they are significant and extended. We tend to experience
more demand for certain of our services when prices increase significantly over extended periods of time, and we tend to
experience less demand for certain of our services when prices decrease significantly over extended periods of time. For
additional information regarding certain of our indirect exposure to commodity prices, see our segment-by-segment analysis
below and the previous section above entitled “Risks Related to Our Business”.
As it relates to our Alkali Business, our revenues are derived from the extraction of trona, as well as the activities
surrounding the processing and sale of natural soda ash and other alkali specialty products, including sodium sesquicarbonate
(S-Carb) and sodium bicarbonate (Bicarb), and are a function of our selling prices and volume sold. We sell our products to an
industry-diverse and worldwide customer base. Our selling prices are contracted at various times throughout the year and for
different durations. Our selling prices for volumes sold internationally and through ANSAC are contracted for the current year
either annually in the prior year or periodically throughout the current year (often quarterly), and our volumes priced and sold
domestically are contracted at various times and can be of varying durations, often multi-year terms. Our sales volumes can
fluctuate from period to period and are dependent upon many factors, of which the main drivers are the global market, customer
demand and economic growth. Positive or negative changes to our revenue, through fluctuations in sales volumes or selling
prices, can have a direct impact to Segment Margin, Net income (loss) and Available Cash before Reserves as these fluctuations
have a lesser impact to operating costs due to the fact that a portion of our costs are fixed in nature. Our costs, some of which
are variable in nature and others are fixed in nature, relate primarily to the processing and producing of soda ash (and other
alkali specialty products) and marketing and selling activities. In addition, costs include activities associated with mining and
extracting trona ore, including energy costs and employee compensation. In our Alkali Business, during 2021, as noted above,
we had positive effects to our revenues (with a lesser impact to costs) due to higher sales volumes and more favorable export
pricing of soda ash relative to 2020 as a result of increased economic and market demand. For additional information, see our
segment-by-segment analysis below.
Our offshore Gulf of Mexico crude oil and natural gas pipeline transportation and handling operations focus on
integrated and large independent energy companies who make intensive capital investments (often in excess of a billion dollars)
to develop large reservoir, long-lived crude oil and natural gas properties. Our revenues are primarily derived from the fees,
typically on a per barrel basis, we charge to transport and deliver commodities (or reserve capacity on our infrastructure in some
cases) downstream to other pipelines or refineries along the Gulf Coast. The shippers on our offshore pipelines are mostly
integrated and large independent energy companies whose production is ideally suited for the vast majority of refineries along
the Gulf Coast, unlike the lighter crude oil and condensates produced from numerous onshore shale plays. Their large-reservoir
properties and the related pipelines and other infrastructure needed to develop them are capital intensive and yet, we believe,
economically viable, in most cases, even in volatile commodity price environments. Costs include activities associated with
employee compensation and benefits, the maintenance of our pipelines and pipeline related infrastructure, marketing, and other
variable type expenses associated with operating the business. We do not expect changes in commodity prices to impact our Net
income (loss), Available Cash before Reserves or Segment Margin derived from our offshore Gulf of Mexico crude oil and
natural gas pipeline transportation and handling operations in the same manner in which they impact our revenues and costs
derived from the purchase and sale of crude oil and petroleum products.
In addition to our crude oil marketing business, Alkali Business and offshore Gulf of Mexico crude oil and natural gas
pipeline transportation and handling operations discussed above, we continue to operate in our other core businesses, including
our sulfur services business and our onshore-based refinery-centric operations located primarily in the Gulf Coast region of the
U.S., which focus on providing a suite of services primarily to refiners. Refiners are the shippers of approximately 98% of the
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volumes transported on our onshore crude pipelines, and refiners contract for approximately 80% of the revenues from our
marine inland barges, which are used primarily to transport intermediate refined products (not crude oil) between refining
complexes.
Additionally, changes in certain of our operating costs between the respective periods, such as those associated with
our sodium minerals and sulfur services, offshore pipeline and marine transportation segments, are not directly correlated with
crude oil prices. We discuss certain of those costs in further detail below in our segment-by-segment analysis.
Included below is additional detailed discussion of the results of our operations focusing on Segment Margin and other
costs including general and administrative expenses, depreciation, depletion and amortization, impairment expense and loss on
sale of assets, interest expense and income taxes.
Segment Margin
The contribution of each of our segments to total Segment Margin in each of the last three years was as follows:
Offshore pipeline transportation
Sodium minerals and sulfur services
Onshore facilities and transportation
Marine transportation
Total Segment Margin
Year Ended December 31,
2021
2020
2019
(in thousands)
$
317,560 $
270,078 $
320,023
166,773
98,824
34,572
130,083
147,254
60,058
223,908
111,412
57,919
$
617,729 $
607,473 $
713,262
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Year Ended December 31, 2021 Compared with Year Ended December 31, 2020
Offshore Pipeline Transportation Segment
Operating results and volumetric data for our offshore pipeline transportation segment are presented below:
Year Ended December 31,
2021
2020
(in thousands)
Offshore crude oil pipeline revenue, net to our ownership interest and excluding non-cash
revenues
Offshore natural gas pipeline revenue, excluding non-cash revenues
$
264,690 $
221,508
41,776
39,973
Offshore pipeline operating costs, net to our ownership interest and excluding non-cash
expenses
Distributions from equity investments(1)
Offshore pipeline transportation Segment Margin
(71,812)
82,906
(70,644)
79,241
$
317,560 $
270,078
Volumetric Data 100% basis:
Crude oil pipelines (average Bbls/day unless otherwise noted):
CHOPS(2)
Poseidon(2)
Odyssey
GOPL(3)
Total crude oil offshore pipelines
189,904
263,169
114,128
7,826
575,027
133,977
290,600
119,145
4,154
547,876
Natural gas transportation volumes (MMBtus/day)
345,870
324,395
Volumetric Data net to our ownership interest(4):
Crude oil pipelines (average Bbls/day unless otherwise noted):
CHOPS(2) (5)
Poseidon(2)
Odyssey
GOPL(3)
Total crude oil offshore pipelines
180,173
168,428
33,097
7,826
389,524
133,977
185,984
34,552
4,154
358,667
Natural gas transportation volumes (MMBtus/day)
107,417
106,781
(1) Offshore pipeline transportation Segment Margin includes distributions received from our offshore pipeline joint ventures
accounted for under the equity method of accounting in 2021 and 2020, respectively.
(2) Our CHOPS pipeline was out of service from August 26, 2020 to February 4, 2021 and had no volumes during this period due to
damage at a junction platform that the CHOPS pipeline goes up and over. We were able to divert all volumes during this period
onto our 64% owned Poseidon oil pipeline.
(3) One of our wholly-owned subsidiaries (GEL Offshore Pipeline, LLC, or “GOPL”) owns our undivided interest in the Eugene Island
pipeline system.
(4) Volumes are the product of our effective ownership interest throughout the year, including changes in ownership interest, multiplied
by the relevant throughput over the given year.
(5) On November 17, 2021, we divested a 36% minority interest in our CHOPS pipeline. The volumes for 2021 represent our 100%
ownership during 2021 through November 16, 2021 and our 64% ownership from November 17, 2021 through December 31, 2021.
Offshore Pipeline Transportation Segment Margin for 2021 increased $47.5 million, or 18%, from 2020, primarily due
to higher overall volumes on our crude oil and natural gas pipeline systems due to less unplanned downtime in 2021 and the
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impact on 2020 of incremental operating costs as a result of the named storms that impacted our business, which are further
discussed below.
During 2020, our offshore pipeline transportation segment experienced an unprecedented period of unplanned
downtime and interruption from Tropical Storm Cristobal and Hurricanes Laura, Marco, Delta and Zeta as a result of producers
shutting in and us taking the necessary safety precautions to remove all personnel from the platforms that we operate and
maintain. In addition to the majority of our assets being shut in, our CHOPS pipeline, although not damaged, was out of service
from August 26, 2020 until February 4, 2021, at which time it resumed service, due to damage at a junction platform that the
CHOPS pipeline goes up and over. Additionally and as a result of these events, we incurred incremental operating expenses
during 2020 related to certain regulatory inspections and analyses performed to ensure our assets were safe to return to service.
While we experienced downtime from named storms in 2021, particularly Hurricane Ida, the impact to our results in the period
was not as significant as the events during 2020 and storms in 2021 did not damage any of our infrastructure in the Gulf of
Mexico. In addition to our increased overall volumes as a result of less downtime in 2021, we also transported higher volumes
on our 100% owned SEKCO pipeline as a result of increased production activity from the Buckskin and Lucius fields, which
are fully dedicated to SEKCO pipeline and further downstream to Poseidon pipeline.
Sodium Minerals and Sulfur Services Segment
Operating results for our sodium minerals and sulfur services segment were as follows:
Volumes sold :
NaHS volumes (Dry short tons “DST”)
Soda Ash volumes (short tons sold)
NaOH (caustic soda) volumes (DST sold)
Revenues (in thousands):
NaHS revenues, excluding non-cash revenues
NaOH (caustic soda) revenues
Revenues associated with our Alkali Business
Other revenues
Total segment revenues, excluding non-cash revenues(1)
Year Ended December 31,
2021
2020
114,292
107,428
2,994,507
2,781,926
84,278
77,274
$
128,959 $
115,797
42,182
696,117
4,728
33,731
645,582
2,506
$
871,986 $
797,616
Sodium minerals and sulfur services operating costs, excluding non-cash items(1)
(705,213)
(667,533)
Segment Margin (in thousands)
Average index price for NaOH per DST(2)
$
$
166,773 $
130,083
787 $
674
(1) Totals are for external revenues and costs prior to intercompany elimination upon consolidation.
(2) Source: IHS Chemical.
Sodium minerals and sulfur services Segment Margin for 2021 increased $36.7 million, or 28%, from 2020. This
increase is primarily due to higher volumes and more favorable export and domestic pricing in our Alkali Business during 2021
and higher NaHS volumes in our refinery services business. During 2020, volume demand in our Alkali Business was
significantly impacted by the worldwide economic shutdowns and uncertainty from the Covid-19 pandemic. As economies
have continued to open up and reduce restrictions, we have seen demand recovery in 2021, both domestically and
internationally through ANSAC, and we produced at a high rate (including selling out of production during the year) at our
Westvaco facility during 2021. Our increased demand and more favorable pricing during 2021 were partially offset by lower
sales volumes at our Granger facility, as it was put in cold standby during the second half of 2020 and had no production during
2021. We plan to bring our Granger facility and its approximate 500,000 tons of annual production back online during the first
quarter of 2023, which is anticipated to be several months before the completion of the GOP, as a result of the expected
continued improvement in market conditions, including export pricing, through 2022 and into 2023. In our refinery services
business, we reported higher NaHS volumes in 2021 primarily due to improved demand for our domestic pulp and paper
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customer base that was negatively impacted in 2020 as a result of the timing of spring turnarounds and outages due to the
Covid-19 pandemic. This was partially offset by lower demand from our mining customers, primarily in Peru.
Onshore Facilities and Transportation Segment
Our onshore facilities and transportation segment utilizes an integrated set of pipelines and terminals, trucks, and
barges to facilitate the movement of crude oil and refined products on behalf of producers, refiners and other customers. This
segment includes crude oil and refined products pipelines, terminals, and rail unloading facilities operating primarily within the
U.S. Gulf Coast crude oil market. In addition, we utilize our trucking fleet that supports the purchase and sale of gathered and
bulk purchased crude oil, as well as purchased and sold refined products. Through these assets we offer our customers a full
suite of services, including the following as of December 31, 2021:
•
•
•
•
•
•
facilitating the transportation of crude oil from producers to refineries and from owned and third party terminals to
refiners via pipelines;
shipping crude oil and refined products to and from producers and refiners via trucks and pipelines;
unloading railcars at our crude-by-rail terminals;
storing and blending of crude oil and intermediate and finished refined products;
purchasing/selling and/or transporting crude oil from the wellhead to markets for ultimate use in refining; and
purchasing products from refiners, transporting those products to one of our terminals and blending those products to a
quality that meets the requirements of our customers and selling those products (primarily fuel oil, asphalt and other
heavy refined products) to wholesale markets.
We also may use our terminal facilities to take advantage of contango market conditions for crude oil gathering and
marketing and to capitalize on regional opportunities which arise from time to time for both crude oil and petroleum products.
Despite crude oil being considered a somewhat homogeneous commodity, many refiners are very particular about the
quality of crude oil feedstock they process. Many U.S. refineries have distinct configurations and product slates that require
crude oil with specific characteristics, such as gravity, sulfur content and metals content. The refineries evaluate the costs to
obtain, transport and process their preferred feedstocks. That particularity provides us with opportunities to help the refineries
in our areas of operation identify crude oil sources and transport crude oil meeting their requirements. The imbalances and
inefficiencies relative to meeting the refiners’ requirements may also provide opportunities for us to utilize our purchasing and
logistical skills to meet their demands. The pricing in the majority of our crude oil purchase contracts contains a market price
component and a deduction to cover the cost of transportation and to provide us with a margin. Contracts sometimes contain a
grade differential which considers the chemical composition of the crude oil and its appeal to different customers. Typically, the
pricing in a contract to sell crude oil will consist of the market price components and the grade differentials. The margin on
individual transactions is then dependent on our ability to manage our transportation costs and to capitalize on grade
differentials.
In our refined products marketing operations, we supply primarily fuel oil, asphalt and other heavy refined products to
wholesale markets and some end-users such as paper mills and utilities. We also provide a service to refineries by purchasing
“heavier” petroleum products that are the residual fuels from gasoline production, transporting them to one of our terminals and
blending them to a quality that meets the requirements of our customers.
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Operating results for our onshore facilities and transportation segment were as follows:
Gathering, marketing, and logistics revenue
Crude oil and CO2 pipeline tariffs and revenues
Distributions from unrestricted subsidiaries not included in income(1)
Crude oil and products costs, excluding unrealized gains and losses from derivative
transactions
Operating costs, excluding non-cash charges for long-term incentive compensation and
other non-cash expenses
Other
Segment Margin
Volumetric Data (average Bbls/day unless otherwise noted):
Onshore crude oil pipelines:
Texas
Jay
Mississippi
Louisiana(2)
Onshore crude oil pipelines total
CO2 pipeline (average Mcf/day):
Free State(3)
Total crude oil and petroleum products sales
Rail unload volumes(4)
Year Ended December 31,
2021
2020
(in thousands)
$
651,097 $
439,338
35,303
70,000
58,249
70,490
(584,880)
(371,738)
(60,992)
(11,704)
(67,710)
18,625
$
98,824 $
147,254
65,918
7,941
5,206
44,564
123,629
62,213
8,443
5,638
57,543
133,837
—
101,845
24,239
11,782
27,073
32,174
(1) 2021 includes total cash payments received from our previously owned NEJD pipeline of $70.0 million not included in income.
2020 includes total cash payments received from our previously owned NEJD pipeline of $56.8 million, of which $48.0 million
were not included in income, and distributions from our Free State pipeline of $22.5 million not included in income, both of which
are defined as unrestricted subsidiaries under our senior secured credit agreement.
(2) Total daily volume for the years ended December 31, 2021 and 2020 include 32,526 and 26,708 Bbls/day respectively of
intermediate refined products associated with our Port of Baton Rouge Terminal pipelines.
(3) The volumes presented for 2020 represent the average Mcf/day through October 29, 2020, after which we divested the related asset.
(4)
Includes total barrels for unloading at all rail facilities.
Segment Margin for our onshore facilities and transportation segment decreased $48.4 million, or 33% , in 2021 as
compared to 2020. The decrease is primarily due to: (i) 2020 including $22.5 million of distributions from our Free State
pipeline, which was associated with the proceeds received from our divestiture of the pipeline during the fourth quarter of 2020,
as well as its contributions to segment margin for the first nine months of 2020; and (ii) lower actual volumes during 2021 and
lower contracted minimum commitments with our main customer associated with our Baton Rouge corridor assets (including
rail, terminal and pipeline volumes) as these commitments stepped down beginning in 2021, as well as the use of prepaid
transportation credits (that built up in 2020) in 2021 by our main customer. These decreases were partially offset by higher cash
receipts in 2021 of $13.2 million associated with our previously owned NEJD pipeline.
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Marine Transportation Segment
Within our marine transportation segment, we own a fleet of 91 barges (82 inland and 9 offshore) with a combined
transportation capacity of 3.2 million barrels, 42 push/tow boats (33 inland and 9 offshore), and a 330,000 barrel capacity ocean
going tanker, the M/T American Phoenix. Operating results for our marine transportation segment were as follows:
Revenues (in thousands):
Inland freight revenues
Offshore freight revenues
Other rebill revenues(1)
Total segment revenues
Operating costs, excluding non-cash charges for long-term incentive compensation
and other non-cash expenses(1)
Segment Margin (in thousands)
Fleet Utilization:(2)
Inland Barge Utilization
Offshore Barge Utilization
Year Ended December 31,
2021
2020
$
73,465
68,703
48,659
91,036
81,158
38,064
190,827
$
210,258
156,255
34,572
$
$
150,200
60,058
$
$
$
$
81.9 %
95.9 %
77.8 %
95.4 %
(1) Under certain of our marine contracts, we “rebill” our customers for a portion of our operating costs.
(2) Utilization rates are based on a 365 day year, as adjusted for planned downtime and drydocking.
Marine Transportation Segment Margin for 2021 decreased $25.5 million, or 42%, from 2020. This decrease is
primarily attributable to lower day rates in our inland barge business during 2021 and a lower day rate associated with our M/T
American Phoenix tanker. During 2021, we saw continued pressure on our inland day rates as a result of Midwest and Gulf
Coast refineries running at lower utilization rates to better align with overall demand as a result of the current operating
environment and uncertainty as a result of the Covid-19 pandemic. During 2020, our M/T American Phoenix received a higher
day rate under its historical five-year term contract that ended on September 30, 2020 compared to its shorter term contracts it
operated under during 2021. The M/T American Phoenix is currently contracted through the first quarter of 2022 with an
investment grade refining company. While we began to see a positive trend to day rates as we exited 2021, we have continued
to enter into short term contracts (less than a year) in both the inland and offshore markets because we believe the day rates
currently being offered by the market have yet to fully recover from their cyclical lows.
Other Costs and Interest
General and administrative expenses
General and administrative expenses not separately identified below:
Corporate
Segment
Long-term incentive based compensation plan expense (benefit)
Third-party costs related to business development activities and growth projects
Year Ended December 31,
2021
2020
(in thousands)
$
43,329 $
4,162
4,748
8,946
53,335
4,088
(1,420)
917
Total general and administrative expenses
$
61,185 $
56,920
Total general and administrative expenses increased $4.3 million between 2021 and 2020. The increase is primarily
due to an increase in third-party costs associated with business development activities and growth projects primarily related to
the sale of a 36% interest in CHOPS during 2021. Additionally, we recorded higher costs associated with our long-term
incentive compensation plan as a result of the assumptions used to value our outstanding awards. These increases were partially
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offset by a decrease in our corporate general and administrative costs primarily related to a charge of approximately $13 million
incurred during 2020 related to certain severance and restructuring expenses.
Depreciation, depletion, and amortization expense
Depreciation and depletion expense
Amortization expense
Total depreciation, depletion and amortization expense
Year Ended December 31,
2021
2020
(in thousands)
$
$
298,953 $
279,605
10,793
15,717
309,746 $
295,322
Total depreciation, depletion, and amortization expense increased $14.4 million between 2021 and 2020. The increase
in depreciation and depletion expense is primarily attributable to the acceleration of depreciation on our asset retirement
obligation assets as a result of updates to the estimated timing and costs associated with certain of our non-core offshore gas
assets. This increase was partially offset by lower depreciation expense associated with our rail logistics assets in 2021 as they
were impaired during the second quarter of 2020, and lower amortization expense in 2021 due to our contract intangible asset
associated with the M/T American Phoenix being fully amortized during the third quarter of 2020.
Impairment expense and Loss on sale of assets
During the year ended December 31, 2020, we recorded impairment expense of $277.5 million associated with the rail
logistics assets included within our onshore facilities and transportation segment. We also recorded $3.3 million of impairment
expense in 2020 associated with the full write-off of one of our non-core offshore gas platforms that does not have future use
within our operations. We did not record impairment expense during the year ended December 31, 2021. See Note 7 to our
Consolidated Financial Statements in Item 8 for additional discussion.
During the year ended December 31, 2020, we recorded a loss on sale of assets of $22.0 million associated with the
divestiture of our Free State pipeline. The loss recorded represents the difference between the proceeds received and the net
book value of the assets sold.
Interest expense, net
Year Ended December 31,
2021
2020
(in thousands)
Interest expense, senior secured credit facility (including commitment fees)
$
22,287 $
Interest expense, senior unsecured notes
Amortization of debt issuance costs, premium, and discount
Capitalized interest
Net interest expense
206,352
9,452
(4,367)
233,724 $
$
38,842
163,330
9,499
(1,892)
209,779
Net interest expense increased $23.9 million between 2021 and 2020, primarily due to increased interest expense
associated with our senior unsecured notes. On December 17, 2020, we issued our $750 million 2027 Notes that accrue interest
at 8.00% and we purchased and extinguished the remaining principal balance of our 6.00% 2023 Notes on January 19, 2021. On
April 22, 2021, we issued an additional $250 million in aggregate principal amount of notes under the same terms as our 2027
Notes. The excess proceeds received from the issuance of our 2027 Notes were used to repay borrowings on the Revolving
Loan under our senior secured credit facility, which reduced interest expense associated with our senior secured credit facility.
Additionally, interest expense associated with our senior secured credit facility further decreased relative to 2020 as proceeds
from the sale of a 36% interest in CHOPS were used to repay the full $300 million outstanding under our Term Loan.
Capitalized interest increased as a result of our decision to internally fund the remaining capital expenditures associated with
the GOP beginning in the fourth quarter of 2021.
Other Consolidated Results
Net loss for the year ended December 31, 2021 included an unrealized loss on the valuation of our embedded
derivative associated with our Class A Convertible Preferred Units of $30.8 million compared to an unrealized loss of $0.9
million for the year ended December 31, 2020. Those amounts are included in “Other expense, net” in the Consolidated
Statements of Operations.
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A discussion of the operating results for the year ended December 31, 2020 compared with the year ended December
31, 2019 has been omitted from this Form 10-K. This discussion can be found within our previously filed 2020 Form 10-K,
which was filed with the SEC on March 1, 2021.
Financial Measures
Overview
This Annual Report on Form 10-K includes the financial measure of Available Cash before Reserves, which is a “non-
GAAP” measure because it is not contemplated by or referenced in generally accepted accounting principles in the United
States of America (GAAP). We also present total Segment Margin as if it were a non-GAAP measure. Our non-GAAP
measures may not be comparable to similarly titled measures of other companies because such measures may include or
exclude other specified items. The accompanying schedules provide reconciliations of these non-GAAP financial measures to
their most directly comparable financial measures calculated in accordance with GAAP. A reconciliation of Net income (loss)
to Segment Margin is included in our segment disclosures in Note 13 to our Consolidated Financial Statements in Item 8. Our
non-GAAP financial measures should not be considered (i) as alternatives to GAAP measures of liquidity or financial
performance or (ii) as being singularly important in any particular context; they should be considered in a broad context with
other quantitative and qualitative information. Our Available Cash before Reserves and total Segment Margin measures are just
two of the relevant data points considered from time to time.
When evaluating our performance and making decisions regarding our future direction and actions (including making
discretionary payments, such as quarterly distributions) our board of directors and management team has access to a wide range
of historical and forecasted qualitative and quantitative information, such as our financial statements; operational information;
various non-GAAP measures; internal forecasts; credit metrics; analyst opinions; performance, liquidity and similar measures;
income; cash flow expectations for us; and certain information regarding some of our peers. Additionally, our board of
directors and management team analyze, and place different weight on, various factors from time to time. We believe that
investors benefit from having access to the same financial measures being utilized by management, lenders, analysts and other
market participants. We attempt to provide adequate information to allow each individual investor and other external user to
reach her/his own conclusions regarding our actions without providing so much information as to overwhelm or confuse such
investor or other external user. Our non-GAAP financial measures should not be considered as an alternative to GAAP
measures such as net income, operating income, cash flow from operating activities or any other GAAP measure of liquidity or
financial performance.
Segment Margin
We define Segment Margin as revenues less product costs, operating expenses, and segment general and
administrative expenses (all of which are net of the effects of our noncontrolling interest holders), plus or minus applicable
Select Items (defined below), and eliminating any gain or loss on sale of assets. Although, we do not necessarily consider all of
our Select Items to be non-recurring, infrequent or unusual, we believe that an understanding of these Select Items is important
to the evaluation of our core operating results. Our chief operating decision maker (our Chief Executive Officer) evaluates
segment performance based on a variety of measures including Segment Margin, segment volumes where relevant and capital
investment.
A reconciliation of Net income (loss) to Segment Margin is included in our segment disclosures in Note 13 to our
Consolidated Financial Statements in Item 8.
Available Cash before Reserves
Purposes, Uses and Definition
Available Cash before Reserves, often referred to by others as distributable cash flow, is a quantitative standard used
throughout the investment community with respect to publicly-traded partnerships and is commonly used as a supplemental
financial measure by management and by external users of financial statements such as investors, commercial banks, research
analysts and rating agencies, to aid in assessing, among other things:
(1) the financial performance of our assets;
(2) our operating performance;
(3) the viability of potential projects, including our cash and overall return on alternative capital investments as
compared to those of other companies in the midstream energy industry;
(4) the ability of our assets to generate cash sufficient to satisfy certain non-discretionary cash requirements,
including interest payments and certain maintenance capital requirements; and
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(5) our ability to make certain discretionary payments, such as distributions on our preferred and common units,
growth capital expenditures, certain maintenance capital expenditures and early payments of indebtedness.
We define Available Cash before Reserves (“Available Cash before Reserves”) as Net income (loss) attributable to
Genesis Energy, L.P. before interest, taxes, depreciation, depletion, and amortization (including impairment, write-offs,
accretion and similar items) after eliminating other non-cash revenues, expenses, gains, losses and charges (including any loss
on asset dispositions), plus or minus certain other select items that we view as not indicative of our core operating results
(collectively, “Select Items”), as adjusted for certain items, the most significant of which in the relevant reporting periods have
been the sum of maintenance capital utilized, net interest expense and cash tax expense. Although we do not necessarily
consider all of our Select Items to be non-recurring, infrequent or unusual, we believe that an understanding of these Select
Items is important to the evaluation of our core operating results. The most significant Select Items in the relevant reporting
periods are set forth below.
I. Applicable to all Non-GAAP Measures
Differences in timing of cash receipts for certain contractual arrangements(1)
Distributions from unrestricted subsidiaries not included in income(2)
Certain non-cash items:
Unrealized loss on derivative transactions excluding fair value hedges, net of changes
in inventory value(3)
Loss on debt extinguishment(4)
Adjustment regarding equity investees(5)
Other
Sub-total Select Items, net(6)
II. Applicable only to Available Cash before Reserves
Certain transaction costs(7)
Other
Total Select Items, net(8)
Year Ended
December 31,
2021
2020
(in thousands)
$ 15,482
$ 40,848
70,000
70,490
30,700
1,189
1,627
31,730
26,207
17,042
207
3,465
144,223
164,764
8,946
1,398
937
(454)
$ 154,567 $ 165,247
(1) Represents the difference in timing of cash receipts from customers during the period and the revenue we recognize in accordance
with GAAP on our related contracts. For purposes of our non-GAAP measures, we add those amounts in the period of payment and
deduct them in the period in which GAAP recognizes them.
(2) 2021 includes $70.0 million in cash receipts associated with principal repayments on our previously owned NEJD pipeline not
included in income. 2020 includes cash payments received from our NEJD pipeline of $48.0 million not included in income and
distributions from our previously owned Free State pipeline of $22.5 million, both of which are defined as unrestricted subsidiaries
under our senior secured credit agreement.
(3) 2021 includes an unrealized loss of $30.8 million from the valuation of the embedded derivative associated with our Class A
Convertible Preferred Units and 2020 includes an unrealized loss of $0.9 million from the valuation of this embedded derivative.
(4) 2021 includes the transaction costs and write-off of the unamortized issuance costs associated with the redemption of our remaining
2023 Notes. 2020 includes transaction costs associated with the tender and redemption of our 2022 Notes and tender of our 2023
Notes, along with the write-off of the associated unamortized issuance costs and discount associated with the previously held 2022
Notes.
(5) Represents the net effect of adding distributions from equity investees and deducting earnings of equity investees net to us.
(6) Represents all Select Items applicable to Segment Margin.
(7) Represents transaction costs relating to certain merger, acquisition, divestiture, transition and financing transactions incurred in
advance of the associated transaction.
(8) Represents Select Items applicable to Available Cash before Reserves.
Disclosure Format Relating to Maintenance Capital
We use a modified format relating to maintenance capital requirements because our maintenance capital expenditures
vary materially in nature (discretionary vs. non-discretionary), timing and amount from time to time. We believe that, without
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such modified disclosure, such changes in our maintenance capital expenditures could be confusing and potentially misleading
to users of our financial information, particularly in the context of the nature and purposes of our Available Cash before
Reserves measure. Our modified disclosure format provides those users with information in the form of our maintenance capital
utilized measure (which we deduct to arrive at Available Cash before Reserves). Our maintenance capital utilized measure
constitutes a proxy for non-discretionary maintenance capital expenditures and it takes into consideration the relationship
among maintenance capital expenditures, operating expenses and depreciation from period to period.
Maintenance Capital Requirements
Maintenance capital expenditures are capitalized costs that are necessary to maintain the service capability of our
existing assets, including the replacement of any system component or equipment which is worn out or obsolete. Maintenance
capital expenditures can be discretionary or non-discretionary, depending on the facts and circumstances.
Prior to 2014, substantially all of our maintenance capital expenditures were (a) related to our pipeline assets and
similar infrastructure, (b) non-discretionary in nature and (c) immaterial in amount as compared to our Available Cash before
Reserves measure. Those historical expenditures were non-discretionary (or mandatory) in nature because we had very little (if
any) discretion as to whether or when we incurred them. We had to incur them in order to continue to operate the related
pipelines in a safe and reliable manner and consistently with past practices. If we had not made those expenditures, we would
not have been able to continue to operate all or portions of those pipelines, which would not have been economically feasible.
An example of a non-discretionary (or mandatory) maintenance capital expenditure would be replacing a segment of an old
pipeline because one can no longer operate that pipeline safely, legally and/or economically in the absence of such replacement.
Beginning with 2014, we believe a substantial amount of our maintenance capital expenditures from time to time will
be (a) related to our assets other than pipelines, such as our marine vessels, trucks and similar assets, (b) discretionary in nature
and (c) potentially material in amount as compared to our Available Cash before Reserves measure. Those expenditures will be
discretionary (or non-mandatory) in nature because we will have significant discretion as to whether or when we incur them.
We will not be forced to incur them in order to continue to operate the related assets in a safe and reliable manner. If we chose
not make those expenditures, we would be able to continue to operate those assets economically, although in lieu of
maintenance capital expenditures, we would incur increased operating expenses, including maintenance expenses. An example
of a discretionary (or non-mandatory) maintenance capital expenditure would be replacing an older marine vessel with a new
marine vessel with substantially similar specifications, even though one could continue to economically operate the older vessel
in spite of its increasing maintenance and other operating expenses.
In summary, as we continue to expand certain non-pipeline portions of our business, we are experiencing changes in
the nature (discretionary vs. non-discretionary), timing and amount of our maintenance capital expenditures that merit a more
detailed review and analysis than was required historically. Management’s increasing ability to determine if and when to incur
certain maintenance capital expenditures is relevant to the manner in which we analyze aspects of our business relating to
discretionary and non-discretionary expenditures. We believe it would be inappropriate to derive our Available Cash before
Reserves measure by deducting discretionary maintenance capital expenditures, which we believe are similar in nature in this
context to certain other discretionary expenditures, such as growth capital expenditures, distributions/dividends and equity
buybacks. Unfortunately, not all maintenance capital expenditures are clearly discretionary or non-discretionary in nature.
Therefore, we developed a measure, maintenance capital utilized, that we believe is more useful in the determination of
Available Cash before Reserves.
Maintenance capital utilized
We believe our maintenance capital utilized measure is the most useful quarterly maintenance capital requirements
measure to use to derive our Available Cash before Reserves measure. We define our maintenance capital utilized measure as
that portion of the amount of previously incurred maintenance capital expenditures that we utilize during the relevant quarter,
which would be equal to the sum of the maintenance capital expenditures we have incurred for each project/component in prior
quarters allocated ratably over the useful lives of those projects/components.
Our maintenance capital utilized measure constitutes a proxy for non-discretionary maintenance capital expenditures
and it takes into consideration the relationship among maintenance capital expenditures, operating expenses and depreciation
from period to period. Because we did not use our maintenance capital utilized measure before 2014, our maintenance capital
utilized calculations will reflect the utilization of solely those maintenance capital expenditures incurred since December 31,
2013.
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Available Cash before Reserves for the years ended December 31, 2021 and 2020 was as follows:
Net loss attributable to Genesis Energy, L.P.
Income tax expense
Depreciation, depletion, amortization, and accretion
Impairment expense
Loss on sale of assets
Plus (minus) Select Items, net
Maintenance capital utilized
Cash tax expense
Distributions to preferred unitholders
Redeemable noncontrolling interest redemption value adjustments(1)
Available Cash before Reserves
(1) Includes distributions paid-in-kind and accretion adjustments on the redemption feature.
Liquidity and Capital Resources
General
Year Ended December 31,
2021
2020
(in thousands)
$
(165,067) $
(416,678)
1,670
315,896
—
—
154,567
1,327
302,602
280,826
22,045
165,247
(53,150)
(40,833)
(690)
(650)
(74,736)
(74,736)
25,398
16,113
$
203,888 $
255,263
As of December 31, 2021, we believe our balance sheet and liquidity position remained strong, including $599.7
million of borrowing capacity available, subject to compliance with our covenants, under our $650 million senior secured credit
facility. We anticipate that our future internally-generated funds and the funds available under our senior secured credit facility
will allow us to meet our ordinary course capital needs. Our primary sources of liquidity have historically been cash flows from
operations, borrowing availability under our senior secured credit facility, proceeds from the sale of non-core assets, the
creation of strategic arrangements to share capital costs through joint ventures or strategic alliances, and the proceeds from
issuances of equity (common and preferred) and senior unsecured notes.
Our primary cash requirements consist of:
working capital, primarily inventories and trade receivables and payables;
routine operating expenses;
capital growth and maintenance projects;
acquisitions of assets or businesses;
interest payments related to outstanding debt;
asset retirement obligations; and
quarterly cash distributions to our preferred and common unitholders.
•
•
•
•
•
•
•
Capital Resources
Our ability to satisfy future capital needs will depend on our ability to raise substantial amounts of additional capital
from time to time, including through equity and debt offerings (public and private), borrowings under our senior secured credit
facility and other financing transactions, and to implement our growth strategy successfully. No assurance can be made that we
will be able to raise necessary funds on satisfactory terms.
At December 31, 2021, we had $49.0 million borrowed under our senior secured credit facility, with $9.7 million of
the borrowed amount designated as a loan under the inventory sublimit. Our senior secured credit facility does not include a
“borrowing base” limitation except with respect to our inventory loans. Due to the revolving nature of loans under our senior
secured credit facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date
of March 15, 2024. The total amount available for borrowings under our senior secured credit facility at December 31, 2021
was $599.7 million, subject to compliance with our covenants.
At December 31, 2021, our long-term debt totaled approximately $3.0 billion, consisting of $49.0 million outstanding
under our senior secured credit facility (including $9.7 million borrowed under the inventory sublimit tranche), $721.0 million
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of our 2028 notes, $1,000.0 million of our 2027 Notes, $359.8 million of our 2026 Notes, $534.8 million of our 2025 Notes,
and $341.1 million of our 2024 Notes.
Future payment obligations related to our long-term debt as of December 31, 2021, including both principal and
estimated interest payments, are summarized in the table below:
Senior secured credit facility-Revolving Loan(1)
2024 Notes
2025 Notes
2026 Notes
2027 Notes
2028 Notes
Total estimated payments
Interest Rate
Maturity Date
Principal
Estimated Annual
Interest Payable
Varies
5.625%
6.500%
6.250%
8.000%
7.750%
March 15, 2024 $
49,000 $
(in thousands)
June 15, 2024
October 1, 2025
May 15, 2026
341,135
534,834
359,799
January 15, 2027
1,000,000
February 1, 2028
720,975
2,940
19,189
34,764
22,487
80,000
55,876
$
3,005,743 $
215,256
(1) Amounts shown above for estimated interest payments represent the amounts that would be paid on an annual basis if the debt
outstanding at December 31, 2021 under our Revolving Loan remained outstanding through the final maturity date of March 15,
2024, and interest rates remained constant from December 31, 2021 through the maturity date.
We have the right to redeem each of our series of notes beginning on specified dates as summarized below, at a
premium to the face amount of such notes that varies based on the time remaining to maturity on such notes. Additionally, we
may redeem up to 35% of the principal amount of each of our series of notes with the proceeds from an equity offering of our
common units during certain periods. A summary of the applicable redemption periods is provided in the table below.
Redemption right beginning on
Redemption of up to 35% of the
principal amount of notes with the
proceeds of an equity offering
permitted prior to
2024 Notes
June 15,
2019
2025 Notes
October 1,
2020
2026 Notes
February 15,
2021
2027 Notes
January 15,
2024
2028 Notes
February 1,
2023
June 15,
2019
October 1,
2020
February 15,
2021
January 15,
2024
February 1,
2023
On December 17, 2020, we issued $750.0 million in aggregate principal amount of our 2027 Notes. That issuance
generated net proceeds of approximately $737 million, net of issuance costs incurred. We used $316.5 million of the net
proceeds to repay the portion of our 2023 Notes (including principal, accrued interest and tender premium) that were validly
tendered, and the remaining proceeds at the time were used to repay a portion of the borrowings outstanding under our senior
secured credit facility. On January 19, 2021, we redeemed the remaining principal balance outstanding on our 2023 Notes of
$80.9 million in accordance with the terms and conditions of the indenture governing the 2023 Notes. We incurred a total loss
of $1.6 million relating to the redemption extinguishment of our remaining 2023 Notes, inclusive of the redemption fee and the
write-off of the related unamortized debt issuance costs, which is recorded in “Other expense, net” in our Consolidated
Statement of Operations for the year ended December 31, 2021.
On April 8, 2021, we entered into our new credit agreement to replace our Fourth Amended and Restated Credit
Agreement. Our new credit agreement provides for a $950 million senior secured credit facility, comprised of the Revolving
Loan with a borrowing capacity of $650 million and the Term Loan with a borrowing capacity of $300 million. Our Term Loan
was paid off in full on November 17, 2021 with a portion of the proceeds received from the sale of a 36% minority interest in
CHOPS. The new credit agreement matures on March 15, 2024, subject to extension at our request for one additional year on
up to two occasions and subject to certain conditions.
On April 22, 2021, we completed our offering of an additional $250 million in aggregate principal amount of our 2027
Notes. The notes constitute an additional issuance of our existing 2027 Notes that we issued on December 17, 2020 in an
aggregate principal amount of $750 million. The additional $250 million of notes have identical terms (other than with respect
to the issue price) as and constitute part of the same series of the 2027 Notes. The $250 million of the 2027 Notes were issued at
a premium of 103.75% plus accrued interest from December 17, 2020. We used the net proceeds from the offering for general
partnership purposes, including repaying a portion of the revolving borrowings outstanding under our new credit agreement.
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For additional information on our long-term debt and covenants see Note 10 to our Consolidated Financial Statements
in Item 8.
Class A Convertible Preferred Units
On September 1, 2017, we sold $750 million of Class A Convertible Preferred Units in a private placement, comprised
of 22,249,494 units for a cash purchase price per unit of $33.71 (subject to certain adjustments, the “Issue Price”) to two initial
purchasers. Our general partner executed an amendment to our partnership agreement in connection therewith, which, among
other things, authorized and established the rights and preferences of our Class A Convertible Preferred Units. Our Class A
Convertible Preferred Units are a new class of security that ranks senior to all of our currently outstanding classes or series of
limited partner interests with respect to distribution and/or liquidation rights. Holders of our Class A Convertible Preferred
Units vote on an as-converted basis with holders of our common units and have certain class voting rights, including with
respect to any amendment to the partnership agreement that would adversely affect the rights, preferences or privileges, or
otherwise modify the terms, of those Class A Convertible Preferred Units.
Each of our Class A Convertible Preferred Units accumulate quarterly distribution amounts in arrears at an annual rate
of 8.75% (or $2.9496), yielding a quarterly rate of 2.1875% (or $0.7374), subject to certain adjustments. With respect to any
quarter ending on or prior to March 1, 2019, we exercised our option to pay the holders of our Class A Convertible Preferred
Units the applicable distribution in additional Class A Convertible Preferred Units equal the product of (i) the number of then
outstanding Class A Convertible Preferred Units and (ii) the quarterly rate. For all subsequent periods ending after March 1,
2019, we have paid and will pay all distribution amounts in respect of our Class A Convertible Preferred Units in cash. As of
December 31, 2021, there are 25,336,778 Class A Convertible Preferred Units outstanding.
Redeemable Noncontrolling interests
On September 23, 2019, we, through a subsidiary, Alkali Holdings, entered into an amended and restated Limited
Liability Company Agreement of Alkali Holdings (the “LLC Agreement”) and a Securities Purchase Agreement (the
“Securities Purchase Agreement”) whereby BXC purchased $55,000,000 of preferred units (or 55,000 preferred units) and
committed to purchase, during a three-year commitment period, up to a total of $350,000,000 of preferred units (or 350,000
preferred units) in Alkali Holdings. Alkali Holdings will use the net proceeds from the preferred units to fund a portion of the
anticipated cost of the Granger Optimization Project. On April 14, 2020, we entered into an amendment to our agreements with
BXC to, among other things, extend the construction timeline of the Granger Optimization Project by one year, which we
currently anticipate completing in the second half of 2023. In consideration for the amendment, we issued 1,750 Alkali
Holdings preferred units to BXC, which was accounted for as issuance costs. As part of the amendment, the commitment period
was increased to four years, and the total commitment of BXC was increased to, subject to compliance with the covenants
contained in our agreements with BXC, up to $351,750,000 of preferred units (or 351,750 preferred units) in Alkali Holdings.
As of December 31, 2021, there are 246,394 Alkali Holdings preferred units outstanding.
BXC has the right to a quarterly distribution equal to 10% per annum on the liquidation preference of each preferred
unit. The liquidation preference is defined as one thousand dollars per preferred unit, plus any accrued and unpaid distributions
(including as a result of any distributions paid-in-kind). Distributions are payable quarterly within 45 days after the end of the
fiscal quarter. Distributions may be paid in-kind in lieu of cash distributions during the first 48 months following the
September 23, 2019 initial closing date. Subsequent to the PIK period, all distributions must be paid in cash. In addition to the
quarterly distributions paid to BXC, Alkali Holdings will distribute all of its distributable cash to the Partnership each quarter,
which is equal to all cash and cash equivalents in the operating accounts of Alkali Holdings less cash reserves and a minimum
$5 million cash balance to be maintained for working capital needs.
From time to time after we have drawn at least $251,750,000, we have the option to redeem the outstanding preferred
units in whole for cash at a price equal to the initial $1,000 per preferred unit purchase price, plus no less than the greater of a
predetermined fixed internal rate of return amount or a multiple of invested capital metric, net of cash distributions paid to date
(“Base Preferred Return”). Additionally, if all outstanding preferred units are being redeemed, we have not drawn at least
$251,750,000, and BXC is not a “defaulting member” under the LLC Agreement, BXC has the right to a make-whole amount
on the number of undrawn preferred units.
BXC is obligated to purchase a minimum of $251,750,000 of preferred units unless certain customary closing
conditions are not satisfied, including the existence of a triggering event or a material uncured breach of the Securities Purchase
Agreement by Alkali Holdings. A triggering event would occur if Alkali Holdings fails to pay cash distributions subsequent to
the paid-in-kind period, fails to redeem preferred units when required to by a change of control event, or if any preferred units
remain outstanding on the six and a half year anniversary date, amongst other events. The preferred units must be redeemed, in
whole or in part, following certain change of control events, fundamental changes, or the liquidation, winding up, or dissolution
of Alkali Holdings and, as applicable, the Partnership. If such an event were to occur, the preferred units would rank senior to
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Alkali Holdings common units and any class or series of equity of Alkali Holdings established after the issuance of the
preferred units.
At any time following the six and a half year anniversary of the Securities Purchase Agreement, or following the
occurrence of certain triggering events, if the preferred units issued and outstanding have not been redeemed in full for cash,
BXC has the right to gain control of the board of Alkali Holdings and effectuate a monetization event using its reasonable good
faith efforts to maximize the consideration received to the holders of our common units, including the sale of Alkali Holdings
(including all of its equity or assets and all of its equity in its subsidiaries), the proceeds of which would first be used to redeem
the preferred units at the Base Preferred Return prior to any distribution to us.
See Note 11 to our Consolidated Financial Statements in Item 8 for additional information regarding our mezzanine
capital.
Shelf Registration Statements
We have the ability to issue additional equity and debt securities in the future to assist us in meeting our future
liquidity requirements, particularly those related to opportunistically acquiring assets and businesses and constructing new
facilities and refinancing outstanding debt.
We have a universal shelf registration statement (our “2021 Shelf”) on file with the SEC which we filed on April 19,
2021 to replace our previous universal shelf registration statement that expired on April 20, 2021. Our 2021 Shelf allows us to
issue an unlimited amount of equity and debt securities in connection with certain types of public offerings. However, the
receptiveness of the capital markets to an offering of equity and/or debt securities cannot be assured and may be negatively
impacted by, among other things, our long-term business prospects and other factors beyond our control, including market
conditions. Our 2021 Shelf is set to expire in April 2024.
Cash Flows from Operations
We generally utilize the cash flows we generate from our operations to fund our common and preferred distributions
and working capital needs. Excess funds that are generated are used to repay borrowings under our senior secured credit facility
and/or to fund a portion of our capital expenditures. Our operating cash flows can be impacted by changes in items of working
capital, primarily variances in the carrying amount of inventory and the timing of payment of accounts payable and accrued
liabilities related to capital expenditures and interest charges, and the timing of accounts receivable collections from our
customers.
We typically sell our crude oil in the same month in which we purchase it, so we do not need to rely on borrowings
under our senior secured credit facility to pay for such crude oil purchases, other than inventory. During such periods, our
accounts receivable and accounts payable generally move in tandem as we make payments and receive payments for the
purchase and sale of crude oil.
In our petroleum products activities, we buy products and typically either move those products to one of our storage
facilities for further blending or sell those products within days of our purchase. The cash requirements for these activities can
result in short term increases and decreases in the borrowings under our senior secured credit facility.
In our Alkali Business, we typically extract trona from our mining facilities, process into soda ash and other alkali
products, and deliver and sell to our customers all within a relatively short time frame. If we did experience any differences in
timing of extraction, processing and sales of this trona or Alkali products, this could impact the cash requirements for these
activities in the short term.
The storage of our inventory of crude oil, petroleum products and alkali products can have a material impact on our
cash flows from operating activities. In the month we pay for the stored crude oil or petroleum products (or pay for extraction
and processing activities in the case of alkali products), we borrow under our senior secured credit facility (or use cash on hand)
to pay for the crude oil or petroleum products (or extraction/processing of alkali products), utilizing a portion of our operating
cash flows. Conversely, cash flow from operating activities increases during the period in which we collect the cash from the
sale of the stored crude oil, petroleum products or alkali products. Additionally, we may be required to deposit margin funds
with the NYMEX when commodity prices increase as the value of the derivatives utilized to hedge the price risk in our
inventory fluctuates. These deposits also impact our operating cash flows as we borrow under our senior secured credit facility
or use cash on hand to fund the deposits.
Net cash flows provided by our operating activities were $338.0 million and $296.7 million for 2021 and 2020,
respectively. The increase in operating cash flow for 2021 compared to 2020 was primarily due to an increase in reported
segment margin during 2021.
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Capital Expenditures and Distributions Paid to Our Unitholders
We use cash primarily for our operating expenses, working capital needs, debt service, acquisition activities, internal
growth projects and distributions we pay to our common and preferred unitholders. We finance maintenance capital
expenditures and smaller internal growth projects and distributions primarily with cash generated by our operations. We have
historically funded material growth capital projects (including acquisitions and internal growth projects) with borrowings under
our senior secured credit facility, equity issuances (common and preferred units), the issuance of senior unsecured notes, and/or
the creation of strategic arrangements to share capital costs through joint ventures or strategic alliances.
Capital Expenditures for Fixed and Intangible Assets and Equity Investees
The following table summarizes our expenditures for fixed and intangible assets and equity investees in the periods
indicated:
Capital expenditures for fixed and intangible assets:
Maintenance capital expenditures:
Offshore pipeline transportation assets
Sodium mineral and sulfur services assets
Marine transportation assets
Onshore facilities and transportation assets
Information technology systems
Total maintenance capital expenditures
Growth capital expenditures:
Offshore pipeline transportation assets
Sodium minerals and sulfur services assets
Marine transportation assets
Onshore facilities and transportation assets
Information technology systems
Total growth capital expenditures
Total capital expenditures for fixed and intangible assets
Capital expenditures related to equity investees
Years Ended December 31,
2021
2020
2019
(in thousands)
$
8,749 $
8,715 $
51,241
34,456
4,476
946
99,868
43,744
31,357
3,644
383
87,843
$
41,445 $
4,608 $
175,877
51,767
—
133
8,259
225,714
325,582
352
—
489
6,331
63,195
151,038
—
16,848
42,065
40,820
2,966
1,197
103,896
961
65,772
—
3,610
2,301
72,644
176,540
—
Total capital expenditures
$
325,934 $
151,038 $
176,540
Expenditures for capital assets to grow the partnership distribution will depend on our access to debt and equity
capital. We will look for opportunities to acquire assets from other parties that meet our criteria for stable cash flows. We
continue to pursue a long term growth strategy that may require significant capital.
Growth Capital Expenditures
On September 23, 2019 we announced the GOP. We entered into agreements with BXC for the purchase of up to a
total of $350,000,000 of preferred units (or 350,000 preferred units) of Alkali Holdings. The proceeds we receive from BXC
will fund a portion of the anticipated cost of the Granger Optimization Project. On April 14, 2020, we entered into an
amendment to our agreements with BXC to, among other things, extend the construction timeline of the Granger Optimization
Project by one year, which we currently anticipate completing in the second half of 2023. As part of the amendment, the total
commitment of BXC was increased to, subject to compliance with the covenants contained in our agreements with BXC, up to
$351,750,000 of preferred units (or 351,750 preferred units) in Alkali Holdings. As of December 31, 2021, we had issued
246,394 of preferred units to BXC. The expansion is expected to increase our production at the Granger facility by
approximately 750,000 tons per year. During the fourth quarter of 2021, we made the decision to internally fund the remaining
capital expenditures associated with the GOP utilizing the available borrowing capacity under our Revolving Loan and free
cash flow.
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Maintenance Capital Expenditures
Maintenance capital expenditures incurred primarily relate to our marine transportation segment to replace and
upgrade certain equipment associated with our vessels and in our Alkali Business, which is included in our sodium minerals and
sulfur services segment, due to the costs to maintain our related equipment and facilities. Additionally, our offshore
transportation assets incur maintenance capital expenditures to replace, maintain, and upgrade equipment at certain of our
offshore platforms and pipelines that we operate. We expect future expenditures to be within a reasonable range of 2021’s
expenditures dependent upon the timing of when we incur certain costs. See previous discussion under “Available Cash before
Reserves” for how such maintenance capital utilization is reflected in our calculation of Available Cash before Reserves.
Distributions to Unitholders
Our partnership agreement requires us to distribute 100% of our available cash (as defined therein) within 45 days
after the end of each quarter to unitholders of record. Available cash generally means, for each fiscal quarter, all cash on hand at
the end of the quarter:
•
•
less the amount of cash reserves that our general partner determines in its reasonable discretion is necessary or
appropriate to:
•
•
•
provide for the proper conduct of our business;
comply with applicable law, any of our debt instruments, or other agreements; or
provide funds for distributions to our common and preferred unitholders for any one or more of the next four
quarters;
plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital
borrowings. Working capital borrowings are generally borrowings that are made under our senior secured credit
facility and in all cases are used solely for working capital purposes or to pay distributions to partners.
On February 14, 2022, we paid a distribution of $0.15 per unit related to the fourth quarter of 2021. With respect to
our Class A Convertible Preferred Units, we have declared a quarterly cash distribution of $0.7374 per preferred unit (or
$2.9496 on an annualized basis) for each preferred unit held of record. These distributions were paid on February 14, 2022 to
unitholders holders of record at the close of business January 31, 2022.
Our historical distributions to common unitholders and Class A Convertible Preferred unitholders are shown in the
table below (in thousands, except per unit amounts).
Distribution For
2019
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
2020
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
2021
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
Date Paid
Per Common
Unit
Amount
Total
Amount
Per Preferred
Unit Amount
Total
Amount
May 15, 2019
August 14, 2019
November 14, 2019
February 14, 2020
May 15, 2020
August 14, 2020
November 13, 2020
February 12, 2021
May 14, 2021
August 13, 2021
$
$
$
$
$
$
$
$
$
$
0.5500 $
67,419 $
0.2458 $
0.5500 $
67,419 $
0.7374 $
0.5500 $
67,419 $
0.7374 $
0.5500 $
67,419 $
0.7374 $
0.1500 $
18,387 $
0.7374 $
0.1500 $
18,387 $
0.7374 $
0.1500 $
18,387 $
0.7374 $
0.1500 $
18,387 $
0.7374 $
0.1500 $
18,387 $
0.7374 $
0.1500 $
18,387 $
0.7374 $
November 12, 2021
February 14, 2022
$
(1) $
0.1500 $
18,387 $
0.7374 $
0.1500 $
18,387 $
0.7374 $
6,138
18,684
18,684
18,684
18,684
18,684
18,684
18,684
18,684
18,684
18,684
18,684
(1) This distribution was paid on February 14, 2022 to unitholders of record as of January 31, 2022.
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Contractual Obligations and Commitments
In addition to the principal and interest payment commitments associated with our long-term debt discussed above, we
have other contractual obligations and commitments as of December 31, 2021, which are summarized below.
• We have estimated operating lease payment obligations totaling $248.5 million, of which $28.9 million is expected to
be paid in 2022 (see Note 4 to our Consolidated Financial Statements in Item 8 for details on our lease obligations).
• We have unconditional purchase obligations from agreements to purchase goods and services that are enforceable and
legally binding and specify all significant terms. The estimated total for our unconditional purchase obligations is
$164.1 million, of which $147.9 million is estimated to be paid in 2022. Contracts to purchase crude oil, petroleum
products, and other chemicals and utilities are generally at market-based prices.The estimated volumes and market
prices at December 31, 2021 were used to value those obligations. The actual physical volumes and settlement prices
may vary due to uncertainties involved in these estimates which include levels of production at the wellhead, changes
in market prices and other conditions beyond our control.
• We have estimated cash requirements from contractual obligations associated with certain of our growth capital
projects (including our GOP) of approximately $150-200 million in 2022. Additionally, we have current asset
retirement obligations of approximately $36 million that we expect to pay in 2022. These requirements are expected to
be funded primarily with free cash flow generated from our operations and availability under our Revolving Loan.
Guarantor Summarized Financial Information
Our $3.0 billion aggregate principal amount of senior unsecured notes co-issued by Genesis Energy, L.P. and Genesis
Energy Finance Corporation are fully and unconditionally guaranteed jointly and severally by all of Genesis Energy, L.P.’s
current and future 100% owned domestic subsidiaries (the “Guarantor Subsidiaries”), except the subsidiaries that hold our
Alkali Business (collectively, the “Alkali Subsidiaries”), Genesis Free State Pipeline, LLC, Genesis NEJD Pipeline, LLC, and
certain other subsidiaries. The assets owned by Genesis Free State Pipeline, LLC were sold on October 30, 2020 and the
ownership of Genesis NEJD Pipeline LLC's pipeline was transferred on October 30, 2020. See Note 7 to our Consolidated
Financial Statements in Item 8 for additional information regarding our asset sales. Genesis NEJD Pipeline, LLC is 100%
owned by Genesis Energy, L.P. The remaining non-Guarantor Subsidiaries are owned, directly or indirectly, by Genesis Crude
Oil, L.P., a Guarantor Subsidiary. The Guarantor Subsidiaries largely own the assets that we use to operate our business other
than our Alkali Business. As a general rule, the assets and credit of our unrestricted subsidiaries are not available to satisfy the
debts of Genesis Energy, L.P., Genesis Energy Finance Corporation or the Guarantor Subsidiaries, and the liabilities of our
unrestricted subsidiaries do not constitute obligations of Genesis Energy, L.P., Genesis Energy Finance Corporation or the
Guarantor Subsidiaries except, in the case of Alkali Holdings and Genesis Energy, L.P., to the extent agreed to in the services
agreement between the Partnership and Alkali Holdings dated as of September 23, 2019. Genesis Energy Finance Corporation
has no independent assets or operations. See Note 10 to our Consolidated Financial Statements in Item 8 for additional
information regarding our consolidated debt obligations.
The guarantees are senior unsecured obligations of each Guarantor Subsidiary and rank equally in right of payment
with other existing and future senior indebtedness of such Guarantor Subsidiary, and senior in right of payment to all existing
and future subordinated indebtedness of such Guarantor Subsidiary. The guarantee of our senior unsecured notes by each
Guarantor Subsidiary is subject to certain automatic customary releases, including in connection with the sale, disposition or
transfer of all of the capital stock, or of all or substantially all of the assets, of such Guarantor Subsidiary to one or more persons
that are not us or a restricted subsidiary, the exercise of legal defeasance or covenant defeasance options, the satisfaction and
discharge of the indentures governing our senior unsecured notes, the designation of such Guarantor Subsidiary as a non-
Guarantor Subsidiary or as an unrestricted subsidiary in accordance with the indentures governing our senior unsecured notes,
the release of such Guarantor Subsidiary from its guarantee under our senior secured credit facility, or liquidation or dissolution
of such Guarantor Subsidiary (collectively, the “Releases”). The obligations of each Guarantor Subsidiary under its note
guarantee are limited as necessary to prevent such note guarantee from constituting a fraudulent conveyance under applicable
law. We are not restricted from making investments in the Guarantor Subsidiaries and there are no significant restrictions on the
ability of the Guarantor Subsidiaries to make distributions to Genesis Energy, L.P.
The rights of holders of our senior unsecured notes against the Guarantor Subsidiaries may be limited under the U.S.
Bankruptcy Code or state fraudulent transfer or conveyance law.
The following is the summarized financial information for Genesis Energy, L.P. and the Guarantor Subsidiaries on a
combined basis after elimination of intercompany transactions among the Guarantor Subsidiaries (which includes related
receivable and payable balances) and the investment in and equity earnings from the non-Guarantor Subsidiaries.
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Balance Sheets
ASSETS:
Current assets
Fixed assets, net
Non-current assets(1)
LIABILITIES AND CAPITAL:(2)
Current liabilities
Non-current liabilities
Class A Convertible Preferred Units
Statements of Operations
Revenues(3)
Operating costs
Operating income
Net loss before income taxes
Net loss(2)
Less: Accumulated distributions to Class A Convertible Preferred Units
Net loss available to common unitholders
Genesis Energy, L.P. and
Guarantor Subsidiaries
December 31, 2021
(in thousands, except unit amount)
$
$
325,666
2,197,127
817,199
341,782
3,334,091
790,115
Genesis Energy, L.P. and
Guarantor Subsidiaries
Year Ended December 31, 2021
(in thousands)
$
$
1,402,308
1,361,557
40,752
(171,308)
(172,967)
(74,736)
(247,703)
(1) Excluded from non-current assets in the table above are $36.7 million of net intercompany receivables due to Genesis Energy, L.P.
and the Guarantor Subsidiaries from the non-Guarantor Subsidiaries as of December 31, 2021.
(2) There are no noncontrolling interests held at the Issuer or Guarantor Subsidiaries for the period presented.
(3) Excluded from revenues in the table above are $5.5 million of sales from Guarantor Subsidiaries to non-Guarantor Subsidiaries for
the year ended December 31, 2021.
Critical Accounting Estimates
The preparation of our consolidated financial statements in conformity with U.S. GAAP requires us to make estimates
and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if
any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting
period. We base these estimates and assumptions on historical experience and other information that are believed to be
reasonable under the circumstances. Although we believe our estimates to be reasonable, these estimates and assumptions about
future events and their effects cannot be determined with certainty, and, accordingly, are evaluated on a regular basis and
revised as needed as new events occur or more information is acquired, and as the business environment in which we operate
changes. Significant accounting policies that we employ are presented in Note 2 to our Consolidated Financial Statements in
Item 8.
We have defined critical accounting estimates as those that: (i) are material due to the levels of subjectivity and
judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change; and (ii) the impact to
the financial condition or operating performance of the Company is material. Our most critical accounting estimates are
discussed below.
Fair Value of Assets and Liabilities Acquired and Identification of Associated Goodwill and Intangible Assets
In conjunction with each acquisition we make, we must allocate the cost of the acquired entity to the assets and
liabilities assumed based on their estimated fair values at the date of acquisition. As additional information becomes available,
we may adjust the original estimates within a short time period subsequent to the acquisition. In addition, we are required to
recognize intangible assets separately from goodwill. Determining the fair value of assets and liabilities acquired, as well as
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intangible assets such as customer relationships, contracts, trade names and non-compete agreements involves professional
judgment and is ultimately based on acquisition models and management’s assessment of the value of the assets and liabilities
acquired, and to the extent available, third-party assessments. Intangible assets with finite lives are amortized over their
estimated useful life as determined by management. Goodwill, if any, is not amortized but instead is periodically assessed for
impairment, as discussed further below. Uncertainties associated with these estimates include fluctuations in economic
obsolescence factors in the area and potential future sources of cash flow.
Depreciation, Amortization and Depletion of Long-Lived Assets and Intangibles
In order to calculate depreciation, depletion and amortization we must estimate the useful lives of our fixed and
intangible assets (including the reserve life of our mineral leaseholds) at the time the assets are placed in service. We compute
depreciation and amortization on a straight-line basis using the best estimated useful life at the time the asset is placed into
service. The actual period over which we will use the asset may differ from the assumptions we have made about the estimated
useful life. Any subsequent events that result in a change in these estimates can impact future depreciation and amortization
calculations, and these changes are adjusted as we become aware of such circumstances. At a minimum, we will assess the
useful lives and residual values of all long-lived assets on an annual basis to determine if adjustments are required.
We compute depletion using the units of production method using actual production and our estimated reserve life.
The actual reserve life may differ from the assumptions we have made about the estimated reserve life.
Impairment of Long-Lived Assets
When events or changes in circumstances indicate that the carrying amount of a fixed asset, intangible asset, equity
method investment, or right of use asset with finite lives may not be recoverable, we review our assets for impairment. We
compare the carrying value of the associated asset to the estimated undiscounted future cash flows expected to be generated
from that asset. Estimates of future net cash flows include estimating future volumes and/or contractual commitments, future
margins or tariff rates, future operating costs and other estimates and assumptions consistent with our business plans. If we
determine that an asset’s unamortized cost may not be recoverable due to impairment, we may be required to reduce the
carrying value and/or the subsequent useful life of the asset. Any such write-down of the value and unfavorable change in the
useful life of a long-lived asset would increase costs and expenses at that time. For the year ended December 31, 2021, we did
not recognize an impairment expense associated with our long-lived assets. For the year ended December 31, 2020, we
recognized impairment expense of $280.8 million associated with long-lived assets (refer to Note 7 in our Consolidated
Financial Statements in Item 8 for additional details).
Goodwill represents the excess of the purchase prices we paid for certain businesses over their respective fair values.
We do not amortize goodwill; however, we evaluate, and test if necessary, our goodwill (at the reporting unit level) for
impairment on October 1 of each fiscal year, and more frequently, if indicators of impairment are present.
We may perform a qualitative assessment of relevant events and circumstances about the likelihood of goodwill
impairment. If it is deemed more likely than not the fair value of the reporting unit is less than its carrying amount, we calculate
the fair value of the reporting unit. Otherwise, further testing is not required. We may also elect to exercise our unconditional
option to bypass this qualitative assessment, in which case we would also calculate the fair value of the reporting unit. The
qualitative assessment is based on reviewing the totality of several factors, including macroeconomic conditions, industry and
market considerations, cost factors, overall financial performance, other entity specific events (for example, changes in
management) or other events such as selling or disposing of a reporting unit. The determination of a reporting unit’s fair value
is predicated on our assumptions regarding the future economic prospects of the reporting unit. Such assumptions include
(i) discrete financial forecasts for the assets contained within the reporting unit, which rely on management’s estimates of
operating margins, (ii) long-term growth rates for cash flows beyond the discrete forecast period, (iii) appropriate discount rates
and (iv) estimates of the cash flow multiples to apply in estimating the market value of our reporting units. Changes in these
estimates could have a significant impact on fair value. If the fair value of the reporting unit (including its inherent goodwill) is
less than its carrying value, a charge to earnings may be required to reduce the carrying value of goodwill to its implied fair
value. If future results are not consistent with our estimates, we could be exposed to future impairment losses that could be
material to our results of operations. We monitor the markets for our products and services, in addition to the overall market, to
determine if a triggering event occurs that would indicate that the fair value of a reporting unit is less than its carrying value.
One of our other monitoring procedures is the comparison of our market capitalization to our book equity to determine if there
is an indicator of impairment.
We performed a quantitative assessment as of October 1, 2021 for our refinery services reporting unit, which is the
only reporting unit as of our assessment date that has goodwill. No impairment was recorded in our refinery services reporting
unit during 2021 as the fair value far exceeded the carrying value. Additionally, when performing sensitivity analyses to the
significant inputs in the fair value, including the discount rate and assumptions related to the future cash flows, a 10% change in
these assumptions did not impact of our overall conclusion surrounding the valuation of our goodwill.
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For additional information regarding our goodwill, see Note 9 to our Consolidated Financial Statements in Item 8.
Revenue recognition - Estimation of variable consideration
Our offshore pipeline transportation segment has certain long-term contracts with customers that include variable
consideration that must be estimated at contract inception and re-assessed at each reporting period. Total consideration for these
arrangements is recognized as revenue over the applicable contract period and is based on our measure of satisfaction of our
corresponding performance obligation, and the difference in timing of revenue recognition and billings results in contract assets
and liabilities. The estimated performance obligation over the life of a contract includes significant judgments by management
including volume and forecasted production information, future price indexing, our ability to transport volumes produced by
our customers, and the contract period. Changes in these assumptions or a contract modification could have a material effect on
the amount of variable consideration recognized as revenue.
Fair Value of Derivatives
We reflect estimates for the fair value of our derivatives based on our internal records and information from third
parties. We have commodity and other derivatives that are accounted for as assets and liabilities at fair value in our
Consolidated Balance Sheets. The valuations of our derivatives that are exchange traded are based on market prices on the
applicable exchange on the last day of the period. For our derivatives that are not exchange traded, the estimates we use are
based on indicative broker quotations. Changes in these estimates could cause a material change to our financial results.
We also have an embedded derivative associated with our Class A Convertible Preferred Units that is accounted for as
a liability at fair value in our Consolidated Balance Sheets as of December 31, 2021 and 2020. The fair value of the embedded
derivative associated with our Class A Convertible Preferred Units is estimated using a Monte Carlo simulation approach that
contains inputs, including our common unit price relative to the issuance price, dividend yield, discount yield, equity volatility,
30-year U.S. Treasury rates, and default and redemption probabilities and timing estimates, which involve management
judgment. During the year ended December 31, 2021, we recorded unrealized losses of $30.8 million associated with fair value
changes of the embedded derivative associated with our Class A convertible Preferred Unit that were primarily driven by
fluctuations in the discount yield from period to period. A significant increase or decrease in these inputs could materially
affect our fair value estimate, resulting in impacts to our Consolidated Financial Statements. For example, a 10% increase or
decrease in the volatility used in the calculation could cause a decrease or an increase to the fair value of our embedded
derivative of approximately $10 million and $13 million, respectively.
Liability and Contingency Accruals and Asset Retirement Obligations
We accrue reserves for contingent liabilities including environmental remediation and potential legal claims. When our
assessment indicates that it is probable that a liability has occurred and the amount of the liability can be reasonably estimated,
we make accruals. We base our estimates on all known facts at the time and our assessment of the ultimate outcome, including
consultation with external experts and counsel. We revise these estimates as additional information is obtained or resolution is
achieved.
We also make estimates related to future payments for environmental costs to remediate existing conditions
attributable to past operations. Environmental costs include costs for studies and testing as well as remediation and restoration.
We sometimes make these estimates with the assistance of third parties involved in monitoring the remediation effort.
Significant changes in new information or judgments could have a material impact to our financial results.
At December 31, 2021, we were not aware of any contingencies or environmental liabilities that would have a material
effect on our financial position, results of operations or cash flows.
Additionally, certain of our assets have contractual and regulatory obligations to perform dismantlement and removal
activities, and in some instances remediation, when the assets are abandoned. Our asset retirement obligations are recorded as a
liability at fair value and have significant assumptions and inputs, including the estimated costs and timing of the associated
abandonment activities as well as the discount and inflation rates utilized to calculate the present value of the future estimated
costs, that could materially impact our financial results. During 2021, we recognized changes in estimates (primarily due to
updated estimated costs and the timing of when we expect to spend these costs) associated with certain of our non-core offshore
natural gas assets of approximately $36 million. We could have impacts to our future earnings based on the actual costs we
incur relative to our estimated costs.
Employee Benefits
We sponsor a defined benefit pension plan for union-only employees of our Alkali Business. We recognize the net
funded status of the pension plan under GAAP as a net liability, included within “Other long-term liabilities” as of December
31, 2021 and 2020 on our Consolidated Balance Sheets. The funded status represents the difference between the fair value of
the pension plan’s assets and the estimated benefit obligation of the plan. The benefit obligation represents the present value of
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the estimated future benefits we expect to pay to plan participants based on service at the end of each period. The benefit
obligation and plan assets are measured at the end of each year, or more frequently, upon the occurrence of a significant event,
such as a settlement or curtailment. We utilize actuarial valuations to measure our funded status in the plan, which include
assumptions such as discount rates, expected long-term rate of return on our plan assets, the timing of our contributions and
payments, employee headcount and compensation changes, amongst others. Significant changes to certain of these assumptions
can have a material impact to our financial statements. We recognized an actuarial gain of $3.1 million during 2021, primarily
as a result of the discount rate utilized to calculate our benefit obligation increasing from 3.06% at December 31, 2020 to 3.27%
at December 31, 2021.
Recent Accounting Pronouncements
Recently Issued and Recently Adopted
We have adopted the guidance under ASC Topic 326 Financial Instruments - Credit Losses (“ASC 326”), as of
January 1, 2020. The standard changed the impairment model for most financial assets and certain other instruments. For trade
and other receivables, held-to-maturity debt securities, loans, and other instruments, entities are required to use a new forward-
looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. We have assessed
our receivables for expected losses by considering current and historical information pertaining to our trade accounts and
existing contract assets. Our assessment resulted in an immaterial impact to consolidated financial statements as of the adoption
date and for the years ended December 31, 2021 and 2020.
During the first quarter of 2020, the SEC amended the financial disclosure requirements for guarantors and issuers of
guaranteed securities registered or being registered in Rule 3-10 of Regulation S-X to go in effect January 4, 2021. The
amendment simplifies the disclosure requirements and permits the amended disclosures to be provided outside the footnotes in
audited annual or unaudited interim consolidated financial statements in all filings. We have included the required summarized
financial information in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
We have adopted guidance under ASC Topic 842, Lease Accounting (“ASC 842”), as of January 1, 2019 utilizing the
modified retrospective method of adoption. Additionally, we elected to implement the practical expedients that pertain to
easements, separation of lease components, and the package of practical expedients, which among other things, allows us to
carry over previous lease conclusions reached under ASC 840. As a result of adopting the new lease standard, we recorded an
operating lease right of use asset of approximately $209 million with a corresponding lease liability as of the transition date.
Refer to Note 4 in our Consolidated Financial Statements in Item 8 for further details, including the activity during 2021 and
2021 relating to our associated leases.
In January 2017, the FASB issued guidance to simplify the goodwill impairment testing at annual or interim periods.
The guidance eliminates Step 2 from the goodwill impairment testing process, and any identified impairment charge would be
simplified to be the difference between the carrying value and fair value of a reporting unit, but would not exceed the total
amount of goodwill allocated to the reporting unit in question. The guidance is effective for annual reporting periods, and
interim periods therein, beginning after December 15, 2019. We elected to early adopt this standard as of January 1, 2017.
Refer to Note 9 in our Consolidated Financial Statements in Item 8 for further information.
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Item 7a. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to various market risks, including (i) commodity price risk and (ii) interest rate risk. We use various
derivative instruments primarily to manage commodity price risk. Our risk management policies and procedures are designed to
help ensure that our hedging activities address our risks by monitoring our derivative positions, as well as our physical volumes,
grades, locations, and delivery schedules. We do not acquire and hold futures contracts or other derivatives for the purpose of
speculating on price changes. The following discussion addresses each category of risk:
Commodity Price Risk
We use derivative instruments to hedge price risk associated with the following commodities:
•
•
Crude Oil and Petroleum Products — We utilize crude oil and petroleum product derivatives to hedge commodity
price risk inherent in our onshore facilities and transportation segment. Our objectives for these derivatives include
hedging fixed price purchase and sales, crude inventories, and basis differentials. We manage these exposures with
various instruments including futures, swaps, and options. Our risk management policies are designed to monitor our
physical volumes, grades and delivery schedules to ensure our hedging activities address the market risks inherent in
our gathering and marketing activities. As of December 31, 2021 we had entered into derivative instruments that will
settle between January 2022 and February 2022.
Natural Gas — We utilize natural gas derivatives to hedge commodity price risk inherent in our sodium minerals and
sulfur services segment. Our objectives for these derivatives include hedging anticipated purchases of natural gas used
by our Alkali business to generate heat and power for operations. We manage these exposures with various
instruments including futures, swaps, and options. As of December 31, 2021 we had entered into derivative
instruments that will settle between January 2022 and December 2022.
The accounting treatment for our commodity derivatives is discussed further in Note 18 to our Consolidated Financial
Statements in Item 8.
The table below presents information about our open commodity derivative contracts at December 31, 2021. Notional
amounts in barrels or MMBtu, the weighted average contract price, total contract amount and total fair value amount in U.S.
dollars of our open positions are presented below. Fair values were determined by using the notional amount in barrels or
MMBtu multiplied by the December 31, 2021 quoted market prices. The table does not include offsetting physical exposures
hedged by our derivative contracts.
Unit of
Measure
for Volume
Contract
Volumes
(in 000’s)
Unit of
Measure
for Price
Weighted
Average
Market
Price
Contract
Value
(in 000’s)
Mark-to
Market
Change
(in 000’s)
Settlement
Value
(in 000’s)
Futures and Swap Contracts
Sell (Short) Contracts:
Crude Oil
Natural Gas Swaps
Natural Gas
Bbl
MMBtu
MMBtu
199
Bbl
4,560 MMBtu
940 MMBtu
Buy (Long) Contracts:
Crude Oil
#6 Fuel Oil
Natural Gas
Option Contracts
Written Contracts:
Crude Oil
Natural Gas
Purchased Contracts:
Crude Oil
Natural Gas
Bbl
Bbl
61
15
Bbl
Bbl
MMBtu
5,190 MMBtu
Bbl
MMBtu
11
Bbl
350 MMBtu
Bbl
MMBtu
3
Bbl
150 MMBtu
91
$
$
$
$
$
$
$
$
$
$
72.28 $ 14,384 $
582 $ 14,966
0.02 $
105 $
(1,259) $
(1,154)
3.99 $
3,753 $
30 $
3,783
75.52 $
4,607 $
(19) $
4,588
64.40 $
966 $
24 $
990
4.01 $ 20,830 $
(1,557) $ 19,273
2.50 $
0.21 $
27 $
73 $
(14) $
(66) $
1.76 $
0.06 $
5 $
9 $
(4) $
(8) $
13
7
1
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We manage our risks of volatility in NaOH prices by indexing prices for the sale of NaHS to the market price for
NaOH in most of our contracts. Given the competitive advantages associated with our naturally produced soda ash as
previously discussed (relative to that which is synthetically produced), we believe this somewhat mitigates market risk within
our Alkali Business.
Interest Rate Risk
We are also exposed to market risks due to the floating interest rates on our senior secured credit facility. Obligations
under our senior secured credit facility bear interest at the LIBOR rate or alternate base rate (which approximates the prime
rate), at our option, plus the applicable margin. We have not historically hedged our interest rates. On December 31, 2021, we
had $49.0 million of debt outstanding under our senior secured credit facility. Due to the significant decline in the LIBOR rate
which began in 2020 and continued in 2021, a 10% change in LIBOR would have resulted in an immaterial impact to Net
income (loss) for the year ended December 31, 2021.
In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848), which provides expedients and
exceptions for accounting treatment of contracts which are affected by the anticipated discontinuation of LIBOR and other rates
resulting from rate reform. The Alternative Reference Rates Committee, a group of market participants convened under the
auspices of the U.S. Federal Reserve Board and other U.S. regulators, has recommended the Secured Overnight Financing Rate
(“SOFR”), calculated based on repurchase agreements backed by treasury securities, as its recommended alternative benchmark
rate to replace LIBOR. The consequences of these developments cannot be entirely predicted but may include an increase in the
interest rate on our senior secured credit facility when transitioning from LIBOR to SOFR, which may have an adverse effect
on our financial condition, operating results or cash flows.
The Preferred Distribution Rate Reset Election of our Class A Convertible Preferred Units is an embedded derivative
that must be bifurcated from the related host contract, the preferred unit purchase agreement, and recorded at fair value in our
Consolidated Balance Sheets. The valuation model utilized for this embedded derivative contains inputs including our common
unit price, U.S. treasury rates and dividend yields to ultimately calculate the fair value of our Class A Convertible Preferred
Units with and without the Preferred Distribution Rate Reset Option. See Note 18 to our Consolidated Financial Statements in
Item 8 for a discussion of embedded derivatives.
Item 8. Financial Statements and Supplementary Data
The information required hereunder is included in this report as set forth in the “Index to Consolidated Financial
Statements.”
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
We maintain disclosure controls and procedures and internal controls designed to ensure that information required to
be disclosed in our filings under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within
the time periods specified in the Securities and Exchange Commission’s rules and forms. Our chief executive officer and chief
financial officer, with the participation of our management, have evaluated our disclosure controls and procedures as of the end
of the period covered by this Annual Report on Form 10-K and have determined that such disclosure controls and procedures
are effective in providing assurance of the timely recording, processing, summarizing and reporting of information, and in
accumulation and communication to management on a timely basis material information relating to us (including our
consolidated subsidiaries) required to be disclosed in this Annual Report on Form 10-K.
Changes in Internal Controls over Financial Reporting
There were no changes during our last fiscal quarter that materially affected, or are reasonably likely to materially
affect, our internal control over financial reporting.
Management’s Report on Internal Control over Financial Reporting
Management of the Partnership is responsible for establishing and maintaining effective internal control over financial
reporting as defined in Rules 13a-15(f) under the Securities Exchange Act of 1934. The Partnership’s internal control over
financial reporting is designed to provide reasonable assurance to the Partnership’s management and board of directors
regarding the preparation and fair presentation of published financial statements.
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Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of the Partnership’s internal control over financial reporting as of December
31, 2021. In making this assessment, management used the criteria established in Internal Control – Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). Based on our
assessment, we believe that, as of December 31, 2021, the Partnership’s internal control over financial reporting is effective
based on those criteria.
Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, our management included a report of their assessment of
the design and effectiveness of our internal controls over financial reporting as part of this Annual Report on Form 10-K for the
fiscal year ended December 31, 2021. Ernst & Young LLP, the Partnership’s independent registered public accounting firm,
has issued an attestation report on the effectiveness of the Partnership’s internal control over financial reporting. Ernst &
Young’s attestation report on the Partnership’s internal control over financial reporting appears in Item 8. “Financial Statements
and Supplementary Data.”
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Item 9B. Other Information
None.
Item 10. Directors, Executive Officers and Corporate Governance
Management of Genesis Energy, L.P.
Part III
We are a Delaware limited partnership. We conduct our operations and own our operating assets through our
subsidiaries and joint ventures. Our general partner, Genesis Energy, LLC, a wholly-owned subsidiary that owns a non-
economic general partner interest in us, has sole responsibility for conducting our business and managing our operations. It
also employs most of our personnel, including executive officers. Employees of our Alkali operations are employed by our
subsidiary, Genesis Alkali, LLC.
The board of directors of our general partner (which we refer to as “our board of directors”) must approve significant
matters (such as material business strategies, mergers, business combinations, acquisitions or dispositions of assets, issuances of
common units, incurrences of debt or other financings and the payments of distributions on common and preferred units). The
holders of our Class B Common Units are entitled to (i) vote in the election of our board of directors, subject to the Davison
family’s rights under its unitholder rights agreement (described below), as well as (ii) vote on substantially all other matters on
which our Class A holders are entitled to vote. The holders of our Class A Common Units are not entitled to vote in the election
of directors, but they are entitled to vote in a very limited number of other circumstances, including our merger with another
company. As is common with MLPs, our partnership structure does not grant our unitholders (in such capacity) the right to
directly or indirectly participate in our management or operations other than through the exercise of their limited voting rights.
Collectively, members of the Davison family own 11.0% of our Class A Common Units and 77.0% of our Class B
Common Units, for a combined ownership percentage of 11.0% of total Common Units. Pursuant to its unitholder rights
agreement, the Davison family is entitled to elect up to three of our directors based on its members’ collective ownership
percentage of our outstanding common units: (i) with 15% or more ownership, they have the right to appoint three directors,
(ii) with less than 15% ownership but more than 10%, they have the right to appoint two directors, and (iii) with less than 10%
ownership, they have the right to appoint one director. That unitholder rights agreement also provides that, so long as the
Davison family has the right to elect three directors thereunder, our board of directors cannot have more than 11 directors
without the Davison family’s consent. In addition to their rights under that unitholder rights agreement, if the members of the
Davison family act as a group, they have the ability to elect at least a majority of our directors because they own a majority of
our Class B units.
Under our limited partnership agreement, the organizational documents of our general partner and indemnification
agreements with our directors, subject to specified limitations, we will indemnify to the fullest extent permitted by Delaware
law, from and against all losses, claims, damages or similar events, any director or officer, or while serving as director or
officer, any person who is or was serving as a tax matters member or as a director, officer, tax matters member, employee,
partner, manager, fiduciary or trustee of our partnership or any of our affiliates. Additionally, we will indemnify to the fullest
extent permitted by law, from and against all losses, claims, damages or similar events, any person who is or was an employee
(other than an officer) or agent of our general partner.
Our board of directors currently consists of Sharilyn S. Gasaway, James E. Davison, James E. Davison, Jr., Kenneth
M. Jastrow II, Conrad P. Albert, Jack T. Taylor and Mr. Sims. Our board of directors has determined that each of Ms. Gasaway
and Messrs. Jastrow, Albert and Taylor is an independent director under the NYSE rules.
Board Leadership Structure and Risk Oversight
Board Leadership Structure
Our board of directors has no policy that requires the positions of the Chairman of the Board and the Chief Executive
Officer to be held by the same or different persons or that we designate a lead or presiding independent director. Our board of
directors believes it is important to retain the flexibility to make those determinations based on an assessment of the
circumstances existing from time to time, including the composition, skills and experience of our board of directors and its
members, specific challenges faced by the company or the industry in which it operates, and governance efficiency.
Presently, our board of directors believes that, because Mr. Sims is the director most familiar with our business and
industry and the most capable of leading the discussion of, and executing on, our business strategy, he is best situated to serve
as Chairman, regardless of the fact that he is the Chief Executive Officer of our general partner. Our board of directors also
believes that the appointment of a lead independent director, who will preside over executive sessions of non-management
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directors of our board of directors, will facilitate teamwork and communication between the non-management directors and
management. Our board of directors appointed Mr. Jastrow as our lead independent director because of his executive
experience and service as a director of other companies. Our board of directors believes that the combined role of Chairman
and Chief Executive Officer working with the lead independent director is currently in the best interest of unitholders,
providing the appropriate balance between developing our strategy and overseeing management.
On September 1, 2017, we sold $750 million of Class A Convertible Preferred Units in a private placement, comprised
of 22,249,494 units for a cash purchase price per unit of $33.71 (subject to certain adjustments, the “Issue Price”) to two initial
purchasers. In connection with the private placement, we have granted each initial purchaser (including its applicable affiliate
transferees) certain rights, including (i) the right to appoint an observer, who shall have the right to attend our board meetings
for so long as an initial purchaser (including its affiliates) owns at least $200 million of our Class A Convertible Preferred Units
and (ii) the right to appoint two directors to our general partner’s board of directors if (and so long as) we fail to pay in full any
three quarterly distribution amounts, whether or not consecutive, attributable to any period ending after March 1, 2019.
We are committed to sound principles of governance. Such principles are critical for us to achieve our performance
goals and maintain the trust and confidence of investors, personnel, suppliers, business partners and stakeholders. We believe
independent directors are a key element for strong governance, although we have reserved or exercised our right as a limited
partnership under the listing standards of the NYSE not to comply with certain requirements of the NYSE. For example,
although at least a majority of the members of our board of directors is independent under the NYSE rules, we reserve the right
not to comply with Section 303A.01 of the NYSE Listed Company Manual in the future, which would require that our board of
directors be comprised of at least a majority of independent directors. In addition, among other things, we have elected not to
comply with Sections 303A.04 and 303A.05 of the NYSE Listed Company Manual, which would require our board of directors
to maintain a nominating/corporate governance committee and a compensation committee, each consisting entirely of
independent directors. Our corporate governance guidelines are available on our website (www.genesisenergy.com) free of
charge. For further discussion of director independence, please see Item 13. “Certain Relationships and Related Transactions,
and Director Independence—Director Independence.”
Risk Oversight
We face a number of risks, including exposure to matters relating to the environment, regulation, competition,
fluctuations in commodity prices and interest rates, pandemics and severe weather. Management is responsible for the day-to-
day management of the risks our company faces, although our board of directors, as a whole and through its committees, has
responsibility for the oversight of risk management. In fulfilling its risk oversight role, our board of directors must determine
whether risk management processes designed and implemented by our management are adequate and functioning as designed.
Senior management regularly delivers presentations to our board of directors on strategic matters, operations, risk management
and other matters, and are available to address any questions or concerns raised by our board of directors. Board of directors
meetings also regularly include discussions with senior management regarding strategies, key challenges and risks and
opportunities for our company.
Our board committees assist our board of directors in fulfilling its oversight responsibilities in certain areas of risk. For
example, the audit committee assists with risk management oversight in the areas of financial reporting, internal controls,
cybersecurity, compliance with legal and regulatory requirements and our risk management policy relating to our hedging
program. The governance, compensation and business development committee assists our board of directors with risk
management relating to our compensation policies and programs.
Our board of directors believes that it is important to align (when practical) the interests of the members of our board
of directors and certain of our officers with the interests of our long-term stakeholders. Our board of directors has adopted
certain policies to further promote that alignment of interests. For example, among other things, our policies prohibit our
directors and officers from (i) buying, selling or engaging in transactions with respect to our common units while they are
aware of material non-public information and (ii) engaging in short sales of our securities. Certain of our directors and/or
officers own substantial amounts of our units, some of which are pledged, including being held in broker margin accounts. See
Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.”
Audit Committee
The audit committee of our board of directors generally oversees our accounting policies and financial reporting and
the audit of our financial statements. The audit committee assists our board of directors in its oversight of the quality and
integrity of our financial statements and our compliance with legal and regulatory requirements. Our independent registered
public accounting firm is given unrestricted access to the audit committee. Our board of directors has determined that the
members of the audit committee meet the independence and experience standards established by NYSE and the Securities
Exchange Act of 1934, as amended. In accordance with the NYSE rules and the Securities Exchange Act of 1934, as amended,
our board of directors has named three of its members to serve on the audit committee—Sharilyn S. Gasaway, Conrad P. Albert
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and Jack T. Taylor. Ms. Gasaway is the chairperson. Our board of directors believes that Ms. Gasaway and Mr. Taylor qualify
as audit committee financial experts as such term is used in the rules and regulations of the SEC. The charter of the audit
committee is available on our website (www.genesisenergy.com) free of charge. Each member of the audit committee is an
independent director under NYSE rules.
Governance, Compensation and Business Development Committee
The governance, compensation and business development committee, or G&C Committee, of our board of directors
generally (i) monitors compliance with corporate governance guidelines, (ii) reviews and makes recommendations regarding
board and committee composition, structure, size, compensation and related matters, and (iii) oversees compensation plans and
compensation decisions for our employees. All the members of our board of directors, other than our CEO, serve as members of
the G&C Committee. Mr. Jastrow is the chairperson. The charter of the G&C Committee is available on our website
(www.genesisenergy.com) free of charge.
Conflicts Committee
To the extent requested by our board of directors, a conflicts committee of our board of directors would be appointed
to review specific matters in connection with the resolution of conflicts of interest and potential conflicts of interest between
any of our affiliates and us. If a specific review is requested by our board of directors, our conflicts committee would be formed
by our Board and would be comprised solely of independent directors. See Item 13. “Certain Relationships and Related
Transactions, and Director Independence—Review or Special Approval of Material Transactions with Related Persons.”
Executive Sessions of Non-Management Directors
Our board of directors holds executive sessions in which non-management directors meet without any members of
management present in connection with regular board meetings. The purpose of these executive sessions is to promote open and
candid discussion among the non-management directors. Mr. Jastrow, as the lead independent director, serves as the presiding
director at those executive sessions. In accordance with NYSE rules, interested parties can communicate directly with non-
management directors by mail in care of the General Counsel and Secretary or in care of the chairperson of the audit committee
at 919 Milam, Suite 2100, Houston, TX 77002. Such communications should specify the intended recipient or recipients.
Commercial solicitations or communications will not be forwarded. We have established a toll-free, confidential telephone
hotline so that interested parties may communicate with the chairperson of the audit committee or with all the non-management
directors as a group. All calls to this hotline are reported to the chairperson of the audit committee who is responsible for
communicating any necessary information to the other non-management directors. The number of our confidential hotline is
(844) 988-1965.
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Directors and Executive Officers
Set forth below is certain information concerning our directors and executive officers, effective as of February 24,
2022.
Name
Grant E. Sims
Conrad P. Albert
James E. Davison
James E. Davison, Jr.
Sharilyn S. Gasaway
Kenneth M. Jastrow II
Jack T. Taylor
Robert V. Deere
Edward T. Flynn
Richard R. Alexander
Karen N. Pape
Kristen O. Jesulaitis
William S. Goloway
Garland G. Gaspard
Chad A. Landry
Ryan S. Sims
Age
66
75
84
55
53
74
70
67
63
46
63
52
61
67
58
38
Director, Chairman of the Board, and Chief Executive Officer
Position
Director
Director
Director
Director
Director
Director
Chief Financial Officer
Executive Vice President
Vice President
Senior Vice President and Controller
General Counsel
Vice President
Senior Vice President
Vice President
Senior Vice President
Grant E. Sims has served as a director and Chief Executive Officer of our general partner since August 2006 and
Chairman of the Board of our general partner since October 2012. Mr. Sims was affiliated with Leviathan Gas Pipeline
Partners, LP from 1992 to 1999, serving as the Chief Executive Officer and a director beginning in 1993 until he left to pursue
personal interests, including investments. Leviathan (subsequently known as El Paso Energy Partners, L.P. and then GulfTerra
Energy Partners, L.P.) was a NYSE listed master limited partnership. Mr. Sims has an established track record of developing
strong companies and has led his companies through a period of substantial growth while increasing geographic and operational
diversity. Mr. Sims provides leadership skills, executive management experience and significant knowledge of our business
environment, which he has gained through his vast experience with other MLPs.
Conrad P. Albert has served as a director of our general partner since July 2013. Mr. Albert is a private investor and
was formerly a director of Anadarko Petroleum Corporation from 1986 to 2006. Mr. Albert also served as a director of
DeepTech International, Inc. from 1992 to 1998. From 1969 to 1991, Mr. Albert served in various positions with Manufacturers
Hanover Trust Company, ultimately serving as Executive Vice President in charge of worldwide energy lending and corporate
finance. Mr. Albert’s extensive financial, executive and directorial experience and his service in various roles in the
management of other energy-related companies will allow him to provide valuable expertise to our board of directors.
James E. Davison has served as a director of our general partner since July 2007. Mr. Davison served as chairman of
the board of Davison Transport, Inc. for over 30 years. He also serves as President of Terminal Services, Inc. Mr. Davison has
over forty years of experience in the energy-related transportation and sulfur removal businesses. Mr. Davison brings to our
board of directors significant energy-related transportation and sulfur removal experience and industry knowledge.
James E. Davison, Jr. has served as a director of our general partner since July 2007. Mr. Davison is also a director of
another public company, Origin Bancorp, Inc., and serves on its finance, risk and insurance committees. Mr. Davison is the son
of James E. Davison. Mr. Davison’s executive and leadership experience enable him to make valuable contributions to our
board of directors.
Sharilyn S. Gasaway has served as a director of our general partner since March 2010 and serves as chairperson of the
audit committee. Ms. Gasaway is a private investor and was Executive Vice President and Chief Financial Officer of Alltel
Corporation, a wireless communications company, from 2006 to 2009, and served as Controller of Alltel Corporation from
2002 through 2006. In her role as CFO, Ms. Gasaway was responsible for the company's finance, financial reporting, and risk
management roles, and gained extensive experience in corporate performance and strategic planning. She brings this vast
knowledge to the Partnership. Ms. Gasaway is a director of JB Hunt Transport Services, Inc., a public company where she also
serves as the chair of the audit committee. Additionally, Ms. Gasaway serves on the compensation and nominating committees
of JB Hunt Transport Services, Inc. Ms. Gasaway provides our board of directors valuable business experience, risk
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management and financial expertise, including an understanding of the accounting, compliance and financial matters that we
address on a regular basis.
Kenneth M. Jastrow II has served as a director of our general partner since March 2010 and serves as our lead
independent director and the chairperson of the G&C Committee. Mr. Jastrow served as Chairman and Chief Executive Officer
of Temple-Inland, Inc., a manufacturing company and the former parent of Forestar Group, from 2000 to 2007. Prior to that,
Mr. Jastrow served in various roles at Temple-Inland, including President and Chief Operating Officer, Group Vice President
and Chief Financial Officer. Mr. Jastrow served as a director of MGIC Investment Corporation and a director and Director
Emeritus of KB Home. Mr. Jastrow formerly served as Non-Executive Chairman of Forestar Group, Inc. Mr. Jastrow’s
executive experience and service as director of other companies enable him to make valuable contributions to our board of
directors and particularly well suited to be the lead independent director.
Jack T. Taylor has served as a director of our general partner since July 2013. Mr. Taylor is currently a director of
Sempra Energy and Murphy USA Inc. Additionally, Mr. Taylor currently serves on the audit committee of Sempra Energy and
Murphy USA Inc. Mr. Taylor was a partner of KPMG LLP for 29 years, where from 2005 to 2010 he served as KPMG's Chief
Operating Officer-Americas and Executive Vice Chair of U.S. Operations and from 2001 to 2005 he served as the Vice
Chairman of U.S. Audit and Risk Advisory Services. Mr. Taylor’s extensive experience with financial and public accounting
issues, his various leadership roles at KPMG LLP and his extensive knowledge of the energy industry make him a valuable
resource to our board of directors.
Robert V. Deere has served as Chief Financial Officer of our general partner since October 2008. Mr. Deere served as
Vice President, Accounting and Reporting at Royal Dutch Shell (Shell) from 2003 through 2008.
Edward T. Flynn has served as Executive Vice President of our general partner and President, Genesis Alkali since we
acquired that business from Tronox Ltd. in September 2017 (where he also previously served as Executive Vice President).
Prior to joining Tronox, Mr. Flynn served as President of FMC Minerals. He was previously President of FMC’s Industrial
Chemicals Group. Mr. Flynn is a member of the Board of Directors and Chairman of the Board for ANSAC.
Richard R. Alexander has served as Vice President of our general partner since November 2014. Mr. Alexander is
responsible for the commercial aspects of our marine transportation segment. Since 2008, Mr. Alexander has served in various
capacities within our marine operations.
Karen N. Pape has served as Senior Vice President and Controller of our general partner since July 2007 and served as
Vice President and Controller from May 2002 until July 2007.
Kristen O. Jesulaitis has served as our General Counsel since July 2011. She is responsible for all legal functions of
Genesis, including acquisitions and commercial transactions, compliance and regulatory affairs, corporate governance,
securities, and finance. Prior to joining Genesis, Ms. Jesulaitis was a partner at the law firm Akin Gump Strauss Hauer & Feld
LLP principally engaged in the areas of corporate and securities law, with primary focus in the midstream energy sector.
William S. Goloway has served as Vice President of our general partner since January 2017. Mr. Goloway has been
responsible for the commercial aspects of our offshore Gulf of Mexico assets from the time we acquired these offshore assets
from Enterprise Products in 2015. Prior to this acquisition, Mr. Goloway served in various roles within the offshore group at
Enterprise Products since 2005.
Garland G. Gaspard has served as Senior Vice President of our general partner since January 2017 and is responsible
for the operational aspects of our onshore and offshore pipelines, rail facilities, terminals, offshore facilities and assets,
engineering, trucking and health, safety, security and environmental compliance. Mr. Gaspard joined Genesis in 2015 as a
result of our acquisition of the offshore Gulf of Mexico assets from Enterprise Products and has had responsibility for the
operational aspects of our offshore assets since that time. Prior to this acquisition, Mr. Gaspard served in various capacities
within Enterprise Products' operations including underground gas storage, natural gas liquids, natural gas pipelines and offshore
operations.
Chad A. Landry has served as Vice President of our general partner since January 2017. Mr. Landry joined Genesis in
2013 and since that time has been responsible for all operational and commercial aspects of our sodium minerals and sulfur
services segment. Prior to joining Genesis, he spent 14 years at Axiall Corporation (Georgia Gulf), most recently as Vice
President - Chlor-Alkali & Vinyls.
Ryan S. Sims has served as Senior Vice President of our general partner since March 2019. Mr. Sims served as Vice
President from January 2017 to March 2019. Mr. Sims joined Genesis in 2011 and is responsible for our finance, planning,
corporate development, and investor relations functions. He has also previously been responsible for the operational and
commercial aspects of our rail and terminals businesses. Prior to joining Genesis, Mr. Sims spent six years in the investment
banking industry. Mr. Sims is the son of Grant E. Sims, our Chairman and Chief Executive Officer.
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Common Unit Ownership by Directors and Executive Officers
We encourage our directors and officers to own our common units, although we do not feel it is necessary to require
them to own a minimum number. Certain of our directors and officers own substantial amounts of our securities, although any
(or all) of them may sell, pledge or otherwise dispose of all or a portion of those securities at any time, subject to any applicable
legal and company policy requirements. See Item 10. “Directors, Executive Officers and Corporate Governance-Board
Leadership Structure and Risk Oversight-Risk Oversight.”
Code of Ethics
We have adopted a Code of Business Conduct and Ethics that is applicable to, among others, the principal financial
officer and the principal accounting officer. Our Code of Business Conduct and Ethics is posted at our website
(www.genesisenergy.com), where we intend to report any changes or waivers.
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Item 11. Executive Compensation
The Compensation Discussion and Analysis below discusses our compensation process and our objectives and
philosophy with respect to our Named Executive Officers (“NEOs”) for the fiscal year ended December 31, 2021.
Compensation Discussion and Analysis
Named Executive Officers
Our NEOs for 2021 were:
•
•
•
•
•
Grant E. Sims, Chief Executive Officer;
Robert V. Deere, Chief Financial Officer;
Edward T. Flynn, Executive Vice President;
Garland G. Gaspard, Senior Vice President; and
Kristen O. Jesulaitis, General Counsel.
Board and Governance, Compensation and Business Development Committee
Our board of directors is responsible for, and effectively determines, compensation programs applicable to our NEOs
and to the board itself. Our board of directors has delegated to the G&C Committee, of which a majority of the members are
“independent,” according to NYSE listing standards, the authority and responsibility to regularly analyze and evaluate our
compensation policies, to determine the annual compensation of our NEOs, and to make recommendations to our board of
directors with respect to such matters. As described in more detail below, the G&C Committee engaged Meridian
Compensation Partners, LLC, or Meridian, as its independent compensation adviser for 2021. We also utilize committees
comprised solely of certain of our independent directors (i.e., the audit committee or special committees) to review and make
recommendations with respect to certain matters such as obtaining exemptions from the “insider trading” rules under
Section 16 of the Exchange Act in connection with certain acquisitions. Because the G&C Committee is comprised of all the
members of our board of directors, excluding our CEO, determinations and recommendations by the G&C Committee are
effectively determinations by our board of directors, which has approval authority for all such compensation matters. For a
more detailed discussion regarding the purposes and composition of board committees, please see Item 10. “Directors,
Executive Officers and Corporate Governance.”
Committee/Board Process
Following the end of each calendar year, our CEO reviews the compensation of all the other NEOs and makes a
proposal to the G&C Committee regarding their compensation. The CEO's proposal is based on (among other things) our
financial results for the prior year, the relevant executive’s areas of responsibility, market data provided by our independent
compensation adviser, and recommendations from the relevant executive’s supervisor (if other than our CEO). The G&C
Committee reviews the compensation of our CEO and the proposal of our CEO regarding the compensation of the other NEOs
and makes a final determination (and a recommendation to our board of directors) regarding the compensation of our NEOs.
Depending on the nature and quantity of changes made to that proposal, there may be additional G&C Committee meetings
and discussions with our CEO in advance of that determination. Our board of directors has final approval authority for all
such compensation matters.
Committee/Board Approval
The G&C Committee determines salaries, annual cash incentives and long-term awards for executive officers, taking
into consideration the CEO’s recommendation regarding the NEOs. In April, any applicable salary increases, retention and
annual bonuses, and long-term incentive awards are made or granted.
Role of Compensation Consultant and Peer Group Analysis
The G&C Committee’s charter authorizes it to retain independent compensation consultants from time to time to
serve as a resource in support of its efforts to carry out certain duties. In 2021, the G&C Committee engaged Meridian, an
independent compensation consultant, to assist the G&C Committee in assessing and structuring competitive compensation
packages for the executive officers that are consistent with our compensation philosophy. The G&C Committee assessed the
independence of Meridian pursuant to current exchange listing requirements and SEC guidance and concluded that no conflict
of interest exists that would prevent Meridian from serving as an independent consultant to the G&C Committee.
At the request of the G&C Committee, Meridian reviewed and provided input on the compensation of our NEOs,
trends in executive compensation, meeting materials circulated to the G&C Committee, and management’s recommendations
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regarding executive compensation plans. Meridian also developed assessments of market levels of compensation through an
analysis of peer data and information disclosed in our peer companies’ public filings, but did not determine or recommend the
amount of compensation.
The peer group used for this market analysis in 2021 consisted of the following 15 companies in the energy industry:
Plains All American Pipeline, L.P., Targa Resources Corp., DCP Midstream, LP, Enable Midstream Partners, LP,
HollyFrontier Corporation, EnLink Midstream, LLC, Magellan Midstream Partners, L.P., Delek US Holdings, Inc., NGL
Energy Partners LP, NuStar Energy L.P., Sunoco LP, Crestwood Equity Partners LP, USA Compression Partners, LP, U.S.
Silica Holdings, Inc. and Calumet Specialty Products Partners, L.P. These companies were selected as the compensation peer
group for any or all of the following reasons:
1) they reflect our industry competitors for products and services;
2) they operate in similar markets or have comparable geographical reach;
3) they are of similar size and maturity to us; or
4) they are companies that have similar credit profiles to us and/or their growth or capital programs are similar to
ours.
The G&C Committee reviews the peer group annually and may, from time to time, add or remove companies in order
to assure the composition of the group meets the criteria outlined above.
The information that Meridian compiled included compensation trends for MLPs and levels of compensation for
similarly-situated executive officers of companies within this peer group. We believe that compensation levels of executive
officers in our peer group are relevant to our compensation decisions because we compete with those companies for executive
management talent.
Compensation Objectives and Philosophy
The primary objectives of our compensation program are to:
•
•
•
encourage our executives to build and operate the partnership in a way that is aligned with our common and
preferred unitholders’ interests, focusing on growing total unitholder returns and growing the asset base with an
emphasis on maintaining a focus on the long-term stability of the enterprise so as to not promote inappropriate risk
taking;
offer near-term and long-term compensation opportunities that are consistent with industry norms; and
provide appropriate levels of retention to the executive team to ensure long-term continuity and stability for the
successful execution of key growth initiatives and projects.
We strive to accomplish these objectives by providing all employees, including our NEOs, with a total compensation
package that is market competitive and both service and performance-based. In our assessment of the market competitiveness
of compensation, we take into consideration the compensation offered by companies in our peer group described above, but
we have not identified a specific percentile of peer company pay as a target. Rather, we use market information as one
consideration in setting compensation along with individual performance, our financial and operational performance and our
safety and sustainability performance.
We pay base salaries at levels that we feel are appropriate for the skills and qualities of the individual NEOs based on
their past performance, current scope of responsibilities and future potential. The incentive-based components of each NEO’s
compensation include annual cash bonus opportunities and participation in the long-term incentive program. The annual cash
bonus rewards incremental operational and financial achievements required to meet investor expectations in the short-term
while the long-term component focuses rewards to the long-term stability of the enterprise. Both incentive components are
generally linked to base salary and are consistent in general with our understanding of market practice and with our judgment
regarding each individual’s role in the organization.
As described in more detail below, we believe that the combination of base salaries, cash bonuses and long-term
cash-based incentive awards provide an appropriate balance of short and long-term incentives, and alignment of the incentives
for our executives, including our NEOs, with the interests of our unitholders.
The amount of compensation contingent on performance is a significant percentage of total compensation, therefore
ensuring that business decisions and actions lead to the long-term growth and sustainability of the organization. Our bonus
plan (including annual and retention bonuses) is driven by the generation of Available Cash before Reserves (as defined in
Item. 7 “Management's Discussion and Analysis of Financial Condition and Results of Operations-Financial Measures”)
which is an important metric of value for our unitholders, and our safety record, with the goal of retention of key employees
and NEOs. Our long-term incentive plan is also linked to our generation of Available Cash before Reserves, our sustainability
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and safety record, as well as the partnership's Consolidated Leverage ratio (as defined in its senior secured credit facility
agreement).
Elements of Our Compensation Program and Compensation Decisions for 2021
The primary elements of our compensation program are a combination of annual cash and long-term incentive-based
compensation. For the year ended December 31, 2021, the elements of our compensation program for the NEOs consisted of
an annual base salary, discretionary annual bonus awards, and awards under our long-term incentive compensation program.
Additionally, in order to attract qualified executive personnel, we may make one-time new-hire awards of equity.
Base Salaries
We believe that base salaries should provide a fixed level of competitive pay that reflects the executive officer’s
primary duties and responsibilities, and which provides a foundation for incentive opportunities and benefit levels. As
discussed above, the base salaries of our NEOs are reviewed annually by the G&C Committee, taking into account
recommendations from our CEO regarding NEOs other than himself. We pay base salaries at a level that we feel is appropriate
for the skills and qualities of the individual NEOs based on their past performance, current scope of responsibilities and future
potential. Base salaries may be adjusted to achieve what is determined to be a reasonably competitive level or to reflect
promotions, the assignment of additional responsibilities, individual performance or company performance. Salaries are also
periodically adjusted based on analysis of peer group practices as described above.
In April 2021, the G&C Committee reviewed the assessments of market levels of compensation developed by
Meridian in conjunction with a discussion of individual performance and responsibilities. As a result of and taking into
account current market conditions, the 2021 base salaries of all NEOs remained the same from 2020.
Bonuses
Our NEOs typically participate in a bonus program, or the Bonus Plan, in which a majority of company employees
participate. As designed by the G&C Committee, each NEO has an annual bonus target based on a stated percentage of his or
her base salary. The targeted amount for the NEOs is established based on the analysis of market practices of the peer group
and consideration of the level of salary and targeted long-term incentives for each NEO. Based on the G&C Committee's
subjective review of 2021 operational and financial performance, in the context of total NEO compensation, a discretionary
bonus was granted to Mr. Flynn in the amount of $600,000 associated with the performance of the Alkali Business. This bonus
will be paid in March 2022, contingent on Mr. Flynn’s employment on the payment date. Further, it was determined by the
G&C Committee that each NEO will be considered for a retention bonus for 2021, as further discussed below.
Our NEOs may participate in a retention bonus program for which certain key employees, managers and officers are
eligible. These retention bonuses are discretionary and are awarded based on individual and company performance with the
goal of retaining key employees. In 2021, Mr. Sims was granted a retention bonus of $850,000, Ms. Jesulaitis and Mr. Flynn
were granted retention bonuses of $500,000 each, and Messrs. Deere and Gaspard were granted retention bonuses of $300,000
each, to be paid in five equal installments at the following dates: September 2022, December 2022, March 2023, June 2023,
and September 2023 contingent upon continued employment at those dates.
Given the near-term economic challenges faced by us and the industry generally, we believe that these retention
bonuses are an appropriate mechanism to incentivize key executives to remain with us so that we may benefit from their
experience in the industry and other competitive opportunities available to them. Over the long term, the G&C committee
intends to continue performance-based cash incentives as a cornerstone of our executive pay program.
Long-Term Incentive Compensation
We generally provide certain long-term compensation (cash and equity-based) to directors, officers, and certain
employees through our long-term incentive compensation plans, or LTIPs. Our G&C Committee designs those awards to align
the interests of plan participants with the interests of our long-term unitholders by promoting a sense of proprietorship and
personal involvement in our development, growth, and financial success. Our LTIPs have given us flexibility to grant deferred
compensation awards in the form of equity or cash-based compensation that vests outright or upon the satisfaction of one or
more conditions that reward measurable service and performance, including the passage of time, continued employment,
financial, and operating (including safety and sustainability) metrics and the appreciation in our unit price over time.
In 2018, our G&C Committee adopted our 2018 LTIP. Like our 2010 LTIP, our 2018 LTIP permits awards of
equity-based compensation in the form of phantom units and distribution equivalent rights, or DERs. Phantom units are
notional units representing unfunded and unsecured promises to pay to the participant a specified amount of cash based on the
market value of our common units should specified vesting requirements be met. DERs are tandem rights to receive on a
quarterly basis an amount of cash equal to the amount of distributions that would have been paid on outstanding phantom units
had they been limited partner units issued by us. In addition, our 2018 LTIP permits cash-based awards.
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Our G&C Committee administers our LTIPs and has broad authority to grant awards under and alter, amend, or
terminate our LTIPs. For example, our G&C Committee has the authority to determine (i) who (if anyone) will receive awards
from time to time as well as (ii) the size, nature, terms and conditions of such award. Our G&C Committee also has the
authority to adopt, alter, and repeal rules, guidelines and practices relating to our LTIPs and interpret our LTIPs. Our board of
directors can terminate the LTIPs at any time.
During 2019 and 2021, we also granted cash-based awards to certain officers and other employees under our 2018
LTIP, including our NEOs. We established target grant values for NEOs based on an analysis of market practices of our
compensation peer group and consideration of the level of salary and targeted bonus for each NEO.
For 2021, 2020 and 2019, the G&C Committee established the following long-term incentive cash grant target values
for each of our NEOs:
Name
Grant E. Sims
Robert V. Deere
Edward T. Flynn
Garland G. Gaspard
Kristen O. Jesulaitis
Long-Term Incentive
Cash Grant Value
2021 (1)
2020 (2)
2019
$
3,600,000 $
800,000
1,500,000
600,000
650,000
$
—
—
—
—
—
2,200,000
800,000
1,200,000
500,000
450,000
(1)
(2)
See additional discussion of awards granted to NEOs under the 2018 LTIP during 2021 included in the “Grants of Plan-Based
Awards” disclosure below.
As a part of the process to reduce and control our cost structure, management recommended no awards to be granted to NEOs
under the 2018 LTIP during 2020, which was approved by our board of directors.
In addition to the established target values noted above for 2021, on April 7, 2021, we granted one-time supplemental
cash-based awards to certain officers and other employees under our 2018 LTIP, including our NEOs. The supplemental
awards are 100% service-based and will be paid out on their two year anniversary, or April 7, 2023, contingent on each
employee’s continued employment at that date. These awards were granted and include a shorter vesting period with the goal
of retaining key employees. The amounts of one-time supplemental awards granted to our NEOs were as follows: $720,000 for
Mr. Sims, $160,000 for Mr. Deere, $300,000 for Mr. Flynn, $130,000 for Ms. Jesulaitis and $120,000 for Mr. Gaspard.
Other Compensation and Benefits
We offer certain other benefits to our NEOs, including medical, dental, disability and life insurance, and contributions
on their behalf to our 401(k) plan. NEOs participate in these plans on the same basis as all other employees. Other than the
401(k) plan, we do not sponsor a pension plan in which our NEOs are eligible to participate, and we do not provide post-
retirement medical benefits that would be available to our NEOs.
No perquisites of any material nature are provided to our NEOs.
Tax and Accounting Implications
Since we are a partnership and not a corporation for federal income tax purposes, we are not subject to the executive
compensation tax deduction limitations of Section 162(m) of the Internal Revenue Code. Accordingly, none of the
compensation paid to our NEOs is subject to limitation as to tax deductibility. However, if the relevant tax laws change in the
future, the Committee will consider the implications of such changes to us. For our equity-based and cash-based compensation
arrangements, we record compensation expense over the vesting period of the awards, as discussed further in Note 16 of our
Consolidated Financial Statements in Item 8.
Compensation Committee Report
The G&C Committee has reviewed and discussed with management the Compensation Discussion and Analysis
included above. Based on that review and discussion, the G&C Committee recommended to our board of directors that this
Compensation Discussion and Analysis be included in this Form 10-K.
The foregoing report is provided by the following directors, who constitute the G&C Committee:
Kenneth M. Jastrow II, Chairman
James E. Davison
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James E. Davison, Jr.
Sharilyn S. Gasaway
Conrad P. Albert
Jack T. Taylor
The information contained in this report shall not be deemed to be soliciting material or filed with the SEC or subject
to the liabilities of Section 18 of the Exchange Act, except to the extent that we specifically incorporate it by reference into a
document filed under the Securities Act or the Exchange Act.
Compensation Risk Assessment
Our board of directors does not believe that our compensation policies and practices for employees are reasonably
likely to have a material adverse effect on us. We compensate most employees with a combination of competitive base salary
and incentive compensation. Meridian advised the G&C Committee that our programs include multiple features and practices
that appropriately control motivations for excessive risk taking. Our board of directors believes that the mix and design of the
elements of employee compensation do not encourage employees to assume excessive or inappropriate risk taking.
Our board of directors concluded that the following risk oversight and compensation design features guard against
excessive risk-taking:
•
•
•
•
•
•
the company has strong internal financial controls;
base salaries are consistent with employees’ responsibilities so that they are not motivated to take excessive
risks to achieve a reasonable level of financial security;
the determination of incentive awards is based on a review of a variety of indicators of performance as well
as a meaningful subjective assessment of personal performance, thus diversifying the risk associated with
any single indicator of performance;
incentive awards are capped by the G&C Committee;
compensation decisions include discretionary authority to adjust annual awards and payments, which further
reduces any business risk associated with our plans; and
long-term incentive awards are designed to provide appropriate awards for dedication to a corporate strategy
that delivers long-term returns to unitholders.
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Summary Compensation Table
The following Summary Compensation Table summarizes the total compensation paid or accrued to our NEOs in
2021, 2020 and 2019.
Name & Principal Position
Year
Salary ($)
Bonus ($) (2)
Non-equity
Incentive Plan
Compensation
($) (3)
All Other
Compensation ($)
(4)
Total ($)
Grant E. Sims
2021 $ 650,000 $ 480,000 $
495,360 $
8,154
1,633,514
Chief Executive Officer
2020 650,000
480,000
(Principal Executive Officer)
2019 650,000
—
—
—
37,034
1,167,034
87,176
737,176
Robert V. Deere
Chief Financial Officer
(Principal Financial Officer)
Edward T. Flynn (1)
Executive Vice President
Garland G. Gaspard
Senior Vice President
Kristen O. Jesulaitis
General Counsel
2021 450,000
240,000
165,120
25,554
880,674
2020 450,000
240,000
2019 450,000
—
—
—
46,814
736,814
80,813
530,813
2021 500,000
60,000
180,000
22,637
762,637
2020 500,000
850,000
2019 500,000
980,000
—
—
27,868
1,377,868
26,396
1,506,396
2021 340,000
240,000
123,840
25,554
729,394
2020 340,000
390,000
2019 340,000
198,000
—
—
36,721
766,721
51,151
589,151
2021 400,000
300,000
109,740
15,384
825,124
2020 400,000
318,750
2019 375,000
134,750
—
—
28,773
747,523
35,283
545,033
(1) Mr. Flynn's bonus for 2020 includes a discretionary bonus of $360,000 relating to 2019 but paid in March 2020, contingent upon
Mr. Flynn's continued employment on the payment date. Mr. Flynn's bonus for 2019 includes a discretionary bonus of $730,000
relating to 2018 but paid in March 2019, contingent upon his continued employment on the payment date.
(2) The amounts shown represent any retention bonuses vested and paid during each of 2019, 2020, and 2021, as well as any cash or
special bonus awards earned relative to each year.
(3) The amounts shown represent the non-equity incentive plan awards vested and paid in 2021 from the awards granted in 2018
under our 2018 LTIP.
(4) The following table presents the components of “All Other Compensation” for each NEO for the year ended December 31, 2021.
Name
Grant E. Sims
Robert V. Deere
Edward T. Flynn
Garland G. Gaspard
Kristen O. Jesulaitis
401(k) Matching and Profit
Sharing Contributions(1)
Insurance
Premiums(2)
Totals
$
— $
8,154 $
17,400
14,423
17,400
13,038
8,154
8,214
8,154
2,346
8,154
25,554
22,637
25,554
15,384
The amounts in this table represent:
(1) Contributions by us to our 401(k) plan on each NEO’s behalf.
(2) Term life insurance premiums paid by us on each NEO’s behalf.
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Grants of Plan-Based Awards
The following table shows the cash-based awards granted to our NEOs in 2021 under our 2018 LTIP.
Estimated Future Payouts Under
Non-Equity Incentive Plan Awards
Name
Grant Date(1)
Vest Date
Threshold
Target
Maximum
Grant E. Sims
Robert V. Deere
Edward T. Flynn
Garland G. Gaspard
Kristen O. Jesulaitis
4/7/2021
4/7/2024 2,160,000
3,600,000
6,480,000
4/7/2021
4/7/2024
480,000
800,000
1,440,000
4/7/2021
4/7/2024
900,000
1,500,000
2,700,000
4/7/2021
4/7/2024
360,000
600,000
1,080,000
4/7/2021
4/7/2024
390,000
650,000
1,170,000
(1) For awards granted to NEOs on April 7, 2021, 80% of the amount represents the cash to be paid if the company meets certain
performance conditions (threshold, target and maximum) associated with our Available Cash before Reserves, our Consolidated
Leverage Ratio (as defined in the credit agreement), and safety and sustainability metrics during 2023. The remaining 20% of the
awards are service-based. See additional discussion in “Long-Term Incentive Compensation” above relating to the 2018 LTIP.
There were no equity based awards granted to our NEOs as of December 31, 2021.
Termination or Change of Control Benefits
We consider maintaining a stable and effective management team to be essential to protecting and enhancing the best
interests of us and our unitholders. To that end, we recognize that the possibility of a change of control or other acquisition
event may raise uncertainty and questions among management, and such uncertainty could adversely affect our ability to retain
our key employees, which would be to our unitholders’ detriment. Because our management team was built over time, as
described above, and our NEOs became NEOs under different circumstances, the compensation and benefits awarded to our
individual NEOs in the event of termination or a change of control varies. In extending these benefits, we considered a number
of factors, including the prevalence of similar benefits adopted by other publicly traded MLPs. See “Potential Payments Upon
Termination or Change of Control” below for further discussion of these benefits, including the definitions of certain terms
such as change of control and cause.
We believe that the interests of unitholders will best be served if the interests of our management and unitholders are
aligned. We believe the termination and change of control benefits described above strike an appropriate balance between the
potential compensation payable and the objectives described above.
Potential Payments upon Termination or Change of Control
Under a change of control for the outstanding LTIP awards granted in April 2019, the unvested service tranche of the
cash award granted will become fully vested and the unvested performance tranche of the cash award granted will vest at
150% of the performance metric. Under a change of control for the outstanding LTIP awards granted in April 2021, the
unvested service tranche of the cash awards granted will become fully vested and the unvested performance tranche of the
cash award granted will vest at 200% of the performance metric.
Based upon a hypothetical termination date of December 31, 2021, the termination benefits for Messrs. Sims, Deere,
Flynn, Gaspard and Ms. Jesulaitis for voluntary termination or termination for cause would be zero.
If termination occurs due to death or disability, Messrs. Sims, Deere, Flynn, Gaspard and Ms. Jesulaitis would vest in
outstanding awards under our 2018 LTIP at 100%, including the awards granted in both 2021 and 2019, and assuming a 1.0
Unit Appreciation Multiplier, or UAM, for the awards granted in 2019, would result in payments under the 2018 LTIP of the
following amounts upon death or disability:
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Grant E. Sims
Robert V. Deere
Edward T. Flynn
Garland G. Gaspard
Kristen O. Jesulaitis
$ 6,520,000
1,760,000
3,000,000
1,220,000
1,230,000
Based on a hypothetical simultaneous change of control and termination date of December 31, 2021, the change of
control termination benefits for Messrs. Sims, Deere, Flynn, Gaspard and Ms. Jesulaitis would have been as follows:
Cash payment for vested awards under 2018 LTIP
granted in 2019
Cash payment for vested awards under 2018 LTIP
granted in 2021
Total
Director Compensation in Fiscal Year 2021
Grant E.
Sims
Robert V.
Deere
Edward T.
Flynn
Garland G.
Gaspard
Kristen O.
Jesulaitis
$ 3,080,000 $ 1,120,000 $ 1,680,000 $ 700,000 $ 607,500
7,200,000
1,600,000
3,000,000
1,200,000
1,300,000
$ 10,280,000 $ 2,720,000 $ 4,680,000 $ 1,900,000 $ 1,907,500
The table below reflects compensation for our non-employee directors. Mr. Sims does not receive any compensation
attributable to his status as a director.
Name
James E. Davison
James E. Davison, Jr.
Sharilyn S. Gasaway
Kenneth M. Jastrow II
Conrad P. Albert
Jack T. Taylor
Fees Earned or
Paid in Cash
($) (1)
Stock
Awards
($) (2) (3)
All Other
Compensation
($) (4)
Total
$
80,000 $ 100,000 $
80,000
102,500
92,500
90,500
92,500
100,000
112,500
112,500
102,500
102,500
18,711 $ 198,711
198,711
18,711
236,050
21,050
226,050
21,050
212,179
19,179
214,179
19,179
(1) Amounts include annual retainer fees and fees for attending meetings.
(2) Amounts in this column represent the fair value of the awards of phantom units under our 2010 LTIP on the date of grant, as
calculated in accordance with accounting guidance for equity-based compensation.
(3) Outstanding awards to directors at December 31, 2021 consist of phantom units granted under our 2010 LTIP. Messrs. James
Davison and James Davison, Jr. each hold 33,097 outstanding phantom units, Ms. Gasaway and Mr. Jastrow each hold 37,236
outstanding phantom units, and Messrs. Albert and Taylor each hold 33,926 outstanding phantom units, respectively.
(4) Amounts in this column represent the amounts paid for tandem DERs related to outstanding phantom units granted under our 2010
LTIP.
Directors who are not officers of our general partner are entitled to a base compensation of $180,000 per year, with
$80,000 paid in cash and $100,000 paid in phantom units. Cash is paid, and phantom units are awarded, on the first day of
each calendar quarter. During 2019, 2020 and 2021, we awarded phantom units under our 2010 LTIP only to directors, all of
which were service-based awards with no performance conditions. The number of phantom units awarded is determined by
dividing the closing market price of our units on the date of the award into the amount to be paid in phantom units. So long as
he or she is a director on the relevant date of determination, each director will receive: (i) a quarterly distribution equal to the
number of phantom units held by such director multiplied by the quarterly distribution amount we will pay in respect of each
of our outstanding common units on such distribution date, and (ii) for all phantom units granted prior to July 2021, on the
third anniversary of each award date for such director, an amount equal to the number of phantom units granted to such
director on such award date multiplied by the average closing price of our common units for the 20 trading days ending on the
day immediately preceding such anniversary date. Beginning in July 2021, all phantom units granted to our directors will vest
and pay out after their one year anniversary at an amount equal to the number of phantom units granted multiplied by the
average closing price of our common units for the 20 trading days ending on the day immediately preceding such anniversary
date.
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The lead director and chairpersons of the audit committee and G&C Committee receive an additional amount of base
compensation split equally between cash and phantom units, which cash compensation is paid in equal quarterly installments.
Such additional amount is $10,000 for the lead director, $25,000 for the chair of the audit committee and $15,000 for the chair
of the G&C Committee.
In addition, each non-employee director receives additional cash compensation for each “Additional Meeting” (board
and/or committee) in which he or she participates. Participation by a director in-person will entitle her/him to additional
compensation of $2,500 per meeting, and participation by a director by means of telecommunication will entitle her/him to
additional compensation of $2,000 per meeting. Such payments are made in conjunction with the quarterly payments of base
compensation. Additional Meetings consist of (i) with respect to our board of directors any meetings (in-person or by
telecommunication) other than (x) the five pre-set meetings of our board of directors for each calendar year and (y) brief
follow-up telecommunication conferences relating to the Annual Report on Form 10-K or any Quarterly Report on Form 10-Q
the company files with the SEC, and (ii) any committee meeting.
CEO Pay Ratio
Our CEO to median employee pay ratio is calculated in accordance with the SEC’s pay ratio rules, Item 402(u) of
Regulation S-K, which requires the disclosure of (i) the median of the annual total compensation of all employees of the
company (except the CEO), (ii) the annual total compensation for the CEO, and (iii) the ratio of these two amounts.
We identified the median employee during the year ended December 31, 2020 by examining the 2020 total cash
compensation for all individuals excluding our CEO, who were employed by us on December 31, 2020. Consistent with Item
402(u), we initially excluded from our employees those individuals who provide services as independent contractors, based on
application of the tests used for tax purposes as set forth in the Internal Revenue Service’s Publication 15A: “Employer’s
Supplemental Tax Guide”. We selected December 31, 2020, which is within the last three months of 2020, as the date upon
which we would identify the median employee because it enabled us to make such identification in a reasonably efficient and
economical manner. We did not make any assumptions, adjustments, or estimates with respect to total cash compensation, and
we did not annualize the compensation for any full-time employees that were not employed by us for all of 2020. We believe
the use of total cash compensation for all employees is a consistently applied compensation measure because we do not widely
distribute annual equity awards to employees. Since all of our employees are located in the U.S., including the Commonwealth
of Puerto Rico, and paid in U.S. dollars, we did not make any cost-of-living adjustments in identifying the median employee.
We utilized the same median employee for the CEO to median employee pay ratio calculation as of December 31,
2021, as we did not experience any significant changes in the employee population or employee compensation arrangements
during 2021 that we reasonably believe would impact the CEO to median employee pay ratio disclosure. As of December 31,
2021, the company had 1,903 employees, including 1,892 full-time employees, and 11 temporary employees.
We calculated the annual total compensation for the median employee using the same methodology we use for our
named executive officers as set forth in the 2021 Summary Compensation Table above in this 10-K filing. Mr. Sims, our
CEO, had 2021 annual total compensation of $1,633,514, as reflected in the Summary Compensation Table. Our median
employee’s annual total compensation for 2021 was $108,501. Based on this information, Mr. Sims’ total annual
compensation was approximately fifteen times that of our median employee in 2021, or 15:1.
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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
Beneficial Ownership of Partnership Units
Beneficial Ownership of Common Units
The following table sets forth certain information as of February 24, 2022, regarding the beneficial ownership of our
common units by beneficial owners of 5% or more by class of unit and by directors and the executive officers of our general
partner and by all directors and executive officers as a group. This information is based on data furnished by the person named.
Name and Address of Beneficial Owner
Class A Common Units
Class B Common Units
Amount and Nature of
Beneficial Ownership
(1) Percent
of Class
Amount and Nature of
Beneficial Ownership
Percent
of Class
Conrad P. Albert
James E. Davison
James E. Davison, Jr.
Sharilyn S. Gasaway
Kenneth M. Jastrow II
Jack T. Taylor
Grant E. Sims
Robert V. Deere
Edward T. Flynn
Richard R. Alexander
Karen N. Pape
Kristen O. Jesulaitis
Ryan S. Sims
William S. Goloway
Garland G. Gaspard
Chad A. Landry
15,000
*
3,678,178
5,423,932
(2)
(3)
3.0 %
4.4 %
289,445
150,000
32,865
*
*
*
3,010,000
(4)
2.5 %
829,987
100,000
20,245
(5)
152,131
55,000
16,300
10,000
12,000
30,000
*
*
*
*
*
*
*
*
*
—
—
9,453
23.6 %
13,648
34.1 %
1,081
2.7 %
—
—
—
—
7,087
17.7 %
1,052
2.6 %
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
All directors and executive officers as a group (16 in total)
13,825,083
11.3 %
32,321
80.8 %
Steven K. Davison
JPMorgan Chase & Co.
Invesco LTD
FMR LLC
ALPS Advisors, Inc.
*
Less than 1%
2,212,941
(6)
1.8 %
9,330,457
7.6 %
14,249,305
11.6 %
15,182,325
12.4 %
14,185,423
11.6 %
7,676
19.2 %
—
—
—
(1) The Class B Common Units, which also are included in the Class A Common Unit total, are identical in most respects to the Class
A Common Units and have voting and distribution rights equivalent to those of the Class A Common Units. In addition, the Class
B Common Units have the right to elect all of our board of directors and are convertible into Class A Common Units under certain
circumstances, subject to certain exceptions.
(2)
In addition to his direct ownership interests, Mr. Davison is the sole stockholder of Terminal Services, Inc., which owns 1,010,835
Class A Common Units.
(3) 1,339,383 of these Class A Common Units are held by trusts for Mr. Davison's children. 187,856 of these Class A Common Units
are held by the James E. and Margaret A. B. Davison Special Trust.
(4) Mr. Sims pledged 2,943,650 of these Class A Common Units as collateral for loans from a bank.
(5)
Includes 4,745 Class A Common Units held by Mr. Alexander’s parents over which Mr. Alexander has trading authority. Mr.
Alexander pledged 10,000 Class A Common Units as collateral for margin brokerage accounts.
(6)
Includes 147,941 Class A Common units held by the Steven Davison Family Trust.
Except as noted, each unitholder in the above table is believed to have sole voting and investment power with respect
to the units beneficially held, subject to applicable community property laws.
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Beneficial Ownership of Preferred Units
The following table sets forth certain information as of December 31, 2021, regarding the beneficial ownership of our
Class A Convertible Preferred Units. This information is based on data furnished by the persons named.
Name and Address of Beneficial Owner
Class A Convertible Preferred Units
GSO Rodeo Holdings LP (2)
KKR Rodeo Aggregator L.P.(3)
Amount and Nature of Beneficial
Ownership
Percent of Class (1)
12,668,389
12,668,389
50.0 %
50.0 %
(1) The percentage of beneficial ownership is calculated based on 25,336,778 Class A Convertible Preferred Units deemed outstanding
as of December 31, 2021.
(2) Reflects Class A Convertible Preferred Units directly owned by GSO Rodeo Holdings LP. GSO Rodeo Holdings Associates LLC
is the general partner of GSO Rodeo Holdings LP. GSO Holdings I L.L.C. is the managing member of GSO Rodeo Holdings
Associates LLC. Blackstone Holdings II L.P. is the managing member of GSO Holdings I L.L.C. Blackstone Holdings I/II GP Inc.
is the general partner of Blackstone Holdings II L.P. The Blackstone Group Inc. is the sole member of Blackstone Holdings I/II GP,
L.L.C. Blackstone Group Management L.L.C. is the sole holder of Class C common stock of The Blackstone Group Inc. Blackstone
Group Management L.L.C. is wholly-owned by Blackstone’s senior managing directors and controlled by its founder, Stephen A.
Schwarzman. In addition, Bennett J. Goodman may be deemed to have shared voting power and/or investment power with respect
to the securities held by GSO Rodeo Holdings LP. Each of the foregoing (other than GSO Rodeo Holdings LP) disclaims beneficial
ownership of the Class A Convertible Preferred Units beneficially owned by GSO Rodeo Holdings LP. The business address for
GSO Rodeo Holdings LP is c/o GSO Capital Partners LP, 345 Park Avenue, New York, New York 10154.
(3) Reflects Class A Convertible Preferred Units directly owned by KKR Aggregator L.P.. KKR Rodeo Aggregator GP LLC, as the
general partner of KKR Rodeo Aggregator L.P., KKR Global Infrastructure Investors II (Rodeo) L.P., as the sole member of KKR
Rodeo Aggregator GP LLC, KKR Associates Infrastructure II AIV L.P., as the general partner of KKR Global Infrastructure
Investors II (Rodeo) L.P., KKR Infrastructure II AIV GP LLC, as the general partner of KKR Associates Infrastructure II AIV L.P.,
KKR Financial Holdings LLC, as the Class B member of KKR Infrastructure II AIV GP LLC, KKR Fund Holdings L.P., as the
Class A member of KKR Infrastructure II AIV GP LLC and the sole member of KKR Financial Holdings LLC, KKR Fund
Holdings GP Limited, as a general partner of KKR Fund Holdings L.P., KKR Group Holdings Corp., as the sole shareholder of
KKR Fund Holdings GP Limited and a general partner of KKR Fund Holdings L.P., KKR & Co. Inc., as the sole shareholder of
KKR Group Holdings Corp., KKR Management LLC, as the Class B common stockholder of KKR & Co. Inc., and Messrs. Kravis
and Roberts, as the designated members of KKR Management LLC, may be deemed to be the beneficial owners having shared
voting and investment power with respect to the Class A Convertible Preferred Units described in this footnote. The principal
business address of each of the entities and persons identified in this paragraph, except Mr. Roberts, is c/o Kohlberg Kravis Roberts
& Co. L.P., 9 West 57th Street, Suite 4200, New York, NY 10019. The principal business address for Mr. Roberts is c/o Kohlberg
Kravis Roberts & Co. L.P., 2800 Sand Hill Road, Suite 200, Menlo Park, CA 94025.
Beneficial Ownership of General Partner Interest
Genesis Energy, LLC owns a non-economic general partner interest in us. Genesis Energy, LLC is our wholly-owned
subsidiary.
The mailing address for Genesis Energy, LLC and all officers and directors is 919 Milam, Suite 2100, Houston, Texas,
77002.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Transactions with Related Persons
Our CEO, Mr. Sims owns an aircraft, which is used by us for business purposes in the course of operations. We pay
Mr. Sims a fixed monthly fee and reimburse the aircraft management company for costs related to our usage of the aircraft,
including fuel and the actual out-of-pocket costs. In connection with this arrangement, we made payments to Mr. Sims totaling
$0.7 million, during 2021. Based on current market rates for chartering of private aircraft under long-term, priority
arrangements with industry recognized chartering companies, we believe that the terms of this arrangement are no worse than
what we could have expected to obtain in an arms-length transaction.
Family members of certain of our executive officers and directors may work for us from time to time. In 2021, Mr.
Sims (our CEO and a director) had two sons that worked for us, one as senior vice president of finance and corporate
development and the other as director of commercial development in our offshore pipeline transportation segment. Mr. James
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Davison, Sr. (a director) had one son (who is also a brother of James E. Davison, Jr., a director) that worked as a director in our
onshore facilities and transportation department in 2021. In the aggregate, these family members received total W-2
compensation of less than $1,300,000.
On September 23, 2019 we announced the Granger Optimization Project to expand our existing Granger facility. We
entered into agreements with BXC, the beneficial owner of more than 5% of our Class A Convertible Preferred Units, for the
purchase of up to a total of $350,000,000 of preferred units (or 350,000 preferred units) of Alkali Holdings. The proceeds we
receive from BXC will fund a portion of the anticipated cost of the Granger Optimization Project. On April 14, 2020, we
entered into an amendment to our agreements with BXC to, among other things, extend the construction timeline of the Granger
Optimization Project by one year, which we currently anticipate completing in the second half of 2023. We issued 1,750 Alkali
Holdings preferred units to BXC in consideration for the amendment. As part of the amendment, the total commitment of BXC
was increased to, subject to compliance with the covenants contained in our agreements with BXC, up to $351,750,000 of
preferred units (or 351,750 preferred units) in Alkali Holdings. The Alkali Holdings preferred unitholders receive PIK
distributions in lieu of cash distributions during the new anticipated construction period. During 2021, we issued 105,145 Alkali
Holdings preferred units to BXC to fund the Granger Optimization Project and satisfy the company's obligation to pay tax
distributions. As of December 31, 2021, we had issued 246,394 of preferred units to BXC.
Director Independence
Because we are a limited partnership, the listing standards of the NYSE do not require that we have a majority of
independent directors (although at least a majority of the members of our board of directors is independent, as defined by the
NYSE rules) or that we have either a nominating committee or a compensation committee of our board of directors. We are,
however, required to have an audit committee consisting of at least three members, all of whom are required to be
“independent” as defined by the NYSE.
Under NYSE rules, to be considered independent, our board of directors must determine that a director has no material
relationship with us other than as a director. The rules specify the criteria by which the independence of directors will be
determined, including guidelines for directors and their immediate family members with respect to employment or affiliation
with us or with our independent public accountants. Our board of directors has determined that each of Ms. Gasaway and
Messrs. Jastrow, Albert and Taylor is an independent director under the NYSE rules. See Item 10. “Directors, Executive
Officers and Corporate Governance” for additional discussion relating to our directors and director independence.
Item 14. Principal Accounting Fees and Services
The following table summarizes the fees for professional services rendered by Ernst & Young for the years ended
December 31, 2021 and 2020.
Audit Fees(1)
All Other Fees(2)
Total
2021
2020
(in thousands)
$
$
3,087 $
2,804
3
6
3,090 $
2,810
(1)
Includes fees for the annual audit and quarterly reviews (including internal control evaluation and reporting), SEC registration
statements and accounting and financial reporting consultations and research work regarding Generally Accepted Accounting
Principles.
(2)
Includes fees associated with licenses for accounting research software.
Pre-Approval Policy
The services by Ernst & Young in 2021 and 2020 were pre-approved in accordance with the pre-approval policy and
procedures adopted by the audit committee. This policy describes the permitted audit, audit-related, tax and other services,
which we refer to collectively as the Disclosure Categories that the independent auditor may perform. The policy requires that
each fiscal year, a description of the services, or the Service List expected to be performed by the independent auditor in each of
the Disclosure Categories in the following fiscal year be presented to the audit committee for approval.
Any requests for audit, audit-related, tax and other services not contemplated on the Service List must be submitted to
the audit committee for specific pre-approval and cannot commence until such approval has been granted. Normally, pre-
approval is provided at regularly scheduled meetings.
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In considering the nature of the non-audit services provided by Ernst & Young in 2021 and 2020, the audit committee
determined that such services are compatible with the provision of independent audit services. The audit committee discussed
these services with Ernst & Young and management of our general partner to determine that they are permitted under the rules
and regulations concerning auditor independence promulgated by the SEC to implement the Sarbanes-Oxley Act of 2002, as
well as the American Institute of Certified Public Accountants.
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Item 15. Exhibits and Financial Statement Schedules
(a)(1) Financial Statements
See “Index to Consolidated Financial Statements and Financial Statement Schedules”.
(a)(2) Financial Statement Schedules.
See “Index to Consolidated Financial Statements and Financial Statement Schedules”.
(a)(3) Exhibits
3.1
3.2
3.3
3.4
3.5
3.6
3.7
3.8
3.9
3.10
4.1
4.2
4.3
4.4
4.5
4.6
4.7
Certificate of Limited Partnership of Genesis Energy, L.P. (incorporated by reference to Exhibit 3.1 to
Amendment No. 2 of the Registration Statement on Form S-1 filed on November 15, 1996, File No.
333-11545).
Amendment to the Certificate of Limited Partnership of Genesis Energy, L.P. (incorporated by
reference to Exhibit 3.2 to the Company's Quarterly Report on Form 10-Q for the quarterly period
ended June 30, 2011, File No. 001-12295).
Fifth Amended and Restated Agreement of Limited Partnership of Genesis Energy, L.P. (incorporated
by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on January 3, 2011, File
No. 001-12295).
First Amendment to Fifth Amended and Restated Agreement of Limited Partnership of Genesis Energy,
L.P., dated September 1, 2017 (incorporated by reference to Exhibit 3.1 to the Company’s Current
Report on Form 8-K filed on September 7, 2017, File No. 001-12295).
Second Amendment to Fifth Amended and Restated Agreement of Limited Partnership of Genesis
Energy, L.P., dated December 31, 2017 (incorporated by reference to Exhibit 3.1 to the Company’s
Current Report on Form 8-K filed on January 4, 2018, File No. 001-12295).
Certificate of Conversion of Genesis Energy, Inc., a Delaware corporation, into Genesis Energy, LLC, a
Delaware limited liability company (incorporated by reference to Exhibit 3.1 to the Company's Current
Report on Form 8-K filed on January 7, 2009, File No. 001-12295).
Certificate of Formation of Genesis Energy, LLC (formerly Genesis Energy, Inc.) (incorporated by
reference to Exhibit 3.2 to the Company's Current Report on Form 8-K filed on January 7, 2009, File
No. 001-12295).
Second Amended and Restated Limited Liability Company Agreement of Genesis Energy, LLC dated
December 28, 2010 (incorporated by reference to Exhibit 3.2 to the Company's Current Report on Form
8-K filed on January 3, 2011, File No. 001-12295).
Certificate of Incorporation of Genesis Energy Finance Corporation, dated as of November 27, 2006
(incorporated by reference to Exhibit 3.7 to the Company's Registration Statement on Form S-4 filed on
September 26, 2011, File No. 333-177012).
Bylaws of Genesis Energy Finance Corporation (incorporated by reference to Exhibit 3.8 to the
Company's Registration Statement on Form S-4 filed on September 26, 2011, File No. 333-177012).
Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934
(incorporated by reference to Exhibit 4.1 to the Company's Annual Report on Form 10-K for the year
ended December 31, 2019, File No. 001-12295).
Form of Common Unit Certificate of Genesis Energy, L.P. (incorporated by reference to Exhibit 4.1 to
the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, File No.
001-12295)
Davison Unitholder Rights Agreement dated July 25, 2007 (incorporated by reference to Exhibit 10.4 to
the Company's Current Report on Form 8-K filed on July 31, 2007, File No. 001-12295).
Amendment No. 1 to the Davison Unitholder Rights Agreement dated October 15, 2007 (incorporated
by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed on October 19, 2007,
File No. 001-12295).
Amendment No. 2 to the Davison Unitholder Rights Agreement dated December 28, 2010 (incorporated
by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K filed on January 3, 2011,
File No. 001-12295).
Davison Registration Rights Agreement dated July 25, 2007 (incorporated by reference to Exhibit 10.3
to the Company's Current Report on Form 8-K filed on July 31, 2007, File No. 001-12295).
Amendment No. 1 to the Davison Registration Rights Agreement, dated November 16, 2007
(incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed on
November 16, 2007, File No. 001-12295).
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4.8
4.9
4.10
4.11
4.12
4.13
4.14
4.15
4.16
4.17
4.18
4.19
4.20
4.21
4.22
4.23
Amendment No. 2 to the Davison Registration Rights Agreement, dated December 6, 2007
(incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed on
December 11, 2007, File No. 001-12295).
Amendment No. 3 to the Davison Registration Rights Agreement, dated as of December 28, 2010
(incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed on
January 3, 2011, File No. 001-12295).
Registration Rights Agreement, dated as of December 28, 2010, by and among Genesis Energy, L.P.
and the former unitholders of Genesis Energy, LLC (incorporated by reference to Exhibit 10.1 to the
Company's Current Report on Form 8-K filed on January 3, 2011, File No. 001-12295).
Registration Rights Agreement, dated September 1, 2017, by and among Genesis Energy, L.P., GSO
Rodeo Holdings LP and Rodeo Finance Aggregator LLC (incorporated by reference from Exhibit 4.1 to
the Company’s Current Report on Form 8-K filed on September 7, 2017, File No. 001-12295).
Indenture, dated May 15, 2014, among Genesis Energy, L.P., Genesis Energy Finance Corporation,
certain subsidiary guarantors named therein and U.S. Bank National Association, as trustee
(incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on May
15, 2014, File No. 001-12295).
Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of May 15, 2014, by and among
Genesis Energy, L.P., Genesis Energy Finance Corporation, the subsidiary guarantors named therein
and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to the
Company's Current Report on Form 8-K filed on May 15, 2014, File No. 001-12295).
Second Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of October 15, 2014, by
and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein
and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.35 to the
Company’s Annual Report on Form 10-K for the year ended December 31, 2014, File No. 001-12295).
Third Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of December 17, 2014, by
and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein
and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.36 to the
Company’s Annual Report on Form 10-K for the year ended December 31, 2014, File No. 001-12295).
Fourth Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of January 22, 2015, by and
among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and
U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.37 to Company’s
Annual Report on Form 10-K for the year ended December 31, 2014, File No. 001-12295).
Fifth Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of February 19, 2015, by and
among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and
U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.38 to the Company’s
Annual Report on Form 10-K for the year ended December 31, 2014, File No. 001-12295).
Sixth Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of February 19, 2015, by and
among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and
U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.39 to the Company’s
Annual Report on Form 10-K for the year ended December 31, 2014, File No. 001-12295).
Seventh Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of June 26, 2015, among
Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S.
Bank National Association, as trustee (incorporated by reference to Exhibit 4.6 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, File No. 001-12295).
Eighth Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of July 15, 2015, among
Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S.
Bank National Association, as trustee (incorporated by reference to Exhibit 4.7 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, File No. 001-12295).
Ninth Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of September 22, 2015,
among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and
U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Company's
Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, File No. 001-12295).
Tenth Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of December 11, 2015,
among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and
U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.52 to the Company’s
Annual Report on Form 10-K for the year ended December 31, 2015, File No. 001-12295).
Eleventh Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of March 10, 2016,
among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and
U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Company's
Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, File No. 001-12295).
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4.24
4.25
4.26
4.27
4.28
4.29
4.30
4.31
4.32
4.33
4.34
4.35
4.36
4.37
Twelfth Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of June 29, 2017, among
Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S.
Bank National Association, as trustee (incorporated by reference to Exhibit 4.57 to the Company's
Annual Report on Form 10-K for the year ended December 31, 2017, File No. 001-12295).
Thirteenth Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of November 13, 2017,
among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and
U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.58 to the Company's
Annual Report on Form 10-K for the year ended December 31, 2017, File No. 001-12295).
Fourteenth Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of August 28, 2018,
among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and
U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 of the Company's
Quarterly Report on Form 10-Q for the quarter ended September 30, 2018, File No. 001-12295).
Fifteenth Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of March 22, 2019,
among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and
U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 of the Company's
Quarterly Report on Form 10-Q for the quarter ended March 31, 2019, File No. 001-12295).
Sixteenth Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of June 28, 2021, among
Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and Regions
Bank, as trustee (incorporated by reference to Exhibit 4.2 of the Company’s Quarterly Report on Form
10-Q for the quarter ended June 30, 2021, File no. 001-12295).
Indenture, dated May 21, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the
Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to
Exhibit 4.1 to the Company's Current Report on Form 8-K filed on May 21, 2015, File No. 001-12295).
Supplemental Indenture for the Issuers' 6.000% Senior Notes due 2023, dated May 21, 2015, among
Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S.
Bank National Association, as trustee (including the form of the Notes) (incorporated by reference to
Exhibit 4.2 to the Company's Current Report on Form 8-K filed on May 21, 2015, File No. 001-12295).
Second Supplemental Indenture for 6.000% Senior Notes due 2023, dated as of June 26, 2015, among
Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S.
Bank National Association, as trustee (incorporated by reference to Exhibit 4.4 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, File No. 001-12295).
Third Supplemental Indenture for 6.000% Senior Notes due 2023, dated as of July 15, 2015, among
Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S.
Bank National Association, as trustee (incorporated by reference to Exhibit 4.5 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, File No. 001-12295).
Fourth Supplemental Indenture for 6.75% Senior Notes due 2022, dated as of July 23, 2015, among
Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S.
Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Company's
Current Report on Form 8-K filed on July 28, 2015, File No. 001-12295).
Fifth Supplemental Indenture for 6.000% Senior Notes due 2023 and 6.75% Senior Notes due 2022,
dated as of September 22, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the
Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to
Exhibit 4.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30,
2015, File No. 001-12295).
Sixth Supplemental Indenture for 6.000% Senior Notes due 2023 and 6.75% Senior Notes due 2022,
dated as of December 11, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the
Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to
Exhibit 4.59 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2015,
File No. 001-12295).
Seventh Supplemental Indenture for 6.000% Senior Notes due 2023 and 6.75% Senior Notes due 2022,
dated as of March 10, 2016, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the
Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to
Exhibit 4.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2016,
File No. 001-12295).
Eighth Supplemental Indenture for 6.000% Senior Notes due 2023 and 6.75% Senior Notes due 2022,
dated as of June 29, 2017, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the
Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to
Exhibit 4.67 to the Company's Annual Report on Form 10-K for the year ended December 31, 2017,
File No. 001-12295).
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4.38
4.39
4.40
4.41
4.42
4.43
4.44
4.45
10.1
10.2
10.3
10.4
Eighth Supplemental Indenture for 6.50% Senior Notes due 2025, dated as of August 14, 2017, among
Genesis Energy, L.P., Genesis Energy Finance Corporation, the subsidiary guarantors named therein
and U.S. Bank National Association, as trustee (incorporated by reference from Exhibit 4.2 to the
Company’s Current Report on Form 8-K filed on August 14, 2017, File No. 001-12295).
Tenth Supplemental Indenture for 6.000% Senior Notes due 2023, 6.75% Senior Notes due 2022 and
6.50% Senior Notes due 2025, dated as of November 13, 2017, among Genesis Energy, L.P., Genesis
Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as
trustee (incorporated by reference to Exhibit 4.69 to the Company's Annual Report on Form 10-K for
the year ended December 31, 2017, File No. 001-12295).
Eleventh Supplemental Indenture for 6.250% Senior Notes Due 2026, dated as of December 11, 2017,
among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and
U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 of the Company’s
Current Report on Form 8-K filed on December 11, 2017, File No. 001-12295).
Twelfth Supplemental Indenture for 6.000% Senior Notes due 2023, 6.75% Senior Notes due 2022,
6.50% Senior Notes due 2025, and 6.250% Senior Notes due 2026, dated as of August 28, 2018, among
Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S.
Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 of the Company's
Quarterly Report on Form 10-Q for the quarter ended September 30, 2018, File No. 001-12295).
Thirteenth Supplemental Indenture for 6.000% Senior Notes due 2023, 6.75% Senior Notes due 2022,
6.50% Senior Notes due 2025, and 6.250% Senior Notes due 2026, dated as of March 22, 2019, among
Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S.
Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 of the Company's
Quarterly Report on Form 10-Q for the quarter ended March 31, 2019, File No. 001-12295).
Fourteenth Supplemental Indenture for 7.750% Senior Notes due 2028, dated as of January 16, 2020,
among Genesis Energy, L.P., Genesis Energy Finance Corporation, the subsidiary guarantors named
therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 of the
Company’s Current Report on Form 8-K filed on January 16, 2020, File No. 001-12295).
Fifteenth Supplemental Indenture for 8.0% Senior Notes due 2027, dated as of December 17, 2020,
among Genesis Energy, L.P., Genesis Energy Finance Corporation, the subsidiary guarantors named
therein and the Trustee (incorporated by reference to Exhibit 4.2 of the Company's Current Report on
Form 8-K filed on December 17, 2020, File No. 001-12295).
Sixteenth Supplemental Indenture for 6.50% Senior Notes due 2025, 6.250% Senior Notes due 2026,
7.750% Senior Notes due 2028, and 8.0% Senior Notes due 2027, dated as of June 28, 2021, among
Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and Regions
Bank, as trustee (incorporated by reference to Exhibit 4.3 of the Company’s Quarterly Report on Form
10-Q for the quarter ended June 30, 2021, File no. 001-12295).
Fourth Amended and Restated Credit Agreement, dated as of June 30, 2014, among Genesis Energy,
L.P. as borrower, Wells Fargo Bank, National Association, as administrative agent, Bank of America,
N.A. and Bank of Montreal as co-syndication agents, U.S. Bank National Association as documentation
agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company's Current
Report on Form 8-K filed on July 3, 2014, File No. 001-12295).
First Amendment to Fourth Amended and Restated Credit Agreement, dated August 25, 2014, among
Genesis Energy, L.P. as borrower, Wells Fargo Bank, National Association, as administrative agent,
Bank of America, N.A. and Bank of Montreal as co-syndication agents, U.S. Bank National Association
as documentation agent and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the
Company's Current Report on Form 8-K filed on August 29, 2014, File No. 001-12295).
Second Amendment to Fourth Amended and Restated Credit Agreement and Joinder Agreement, dated
as of July 17, 2015, among Genesis Energy, L.P. as borrower, Wells Fargo Bank, National Association,
as administrative agent and issuing bank, Bank of America, N.A. and Bank of Montreal as co-
syndication agents, U.S. Bank National Association as documentation agent, and the lenders party
thereto (incorporated by reference to Exhibit 10.3 to the Company’s Annual Report on Form 10-K for
the year ended December 31, 2015, File No. 001-12295).
Third Amendment to Fourth Amended and Restated Credit Agreement, dated as of September 17, 2015,
among Genesis Energy, L.P. as borrower, Wells Fargo Bank, National Association, as administrative
agent and issuing bank, Bank of America, N.A. and Bank of Montreal as co-syndication agents, U.S.
Bank National Association as documentation agent, and the lenders party thereto (incorporated by
reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed on September 23, 2015,
File No. 001-12295).
116
Table of Contents
10.5
10.6
10.7
10.8
10.9
10.10
10.11
10.12
10.13
Fourth Amendment to Fourth Amended and Restated Credit Agreement and Joinder Agreement dated
as of April 27, 2016 among Genesis Energy, L.P., as the borrower, Wells Fargo Bank, National
Association, as administrative agent and issuing bank, Bank of America, N.A. and Bank of Montreal, as
co-syndication agents, U.S. Bank National Association, as documentation agent, and the lenders party
thereto. (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed
on May 3, 2016, File No. 001-12295).
Fifth Amendment to Fourth Amended and Restated Credit Agreement and Second Amendment to
Fourth Amended and Restated Guarantee and Collateral Agreement dated as of May 9, 2017 among
Genesis Energy, L.P., as the borrower, Wells Fargo Bank, National Association, as administrative agent
and issuing bank, Bank of America, N.A. and Bank of Montreal, as co-syndication agents, U.S. Bank
National Association, as documentation agent, and the lenders party thereto (incorporated by reference
to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 15, 2017, File No.
001-12295).
Sixth Amendment to Fourth Amended and Restated Credit Agreement, dated July 28, 2017, among
Genesis Energy, L.P., as borrower, Wells Fargo Bank National Association, as administrative agent,
Bank of America, N.A. and Bank of Montreal as co-syndication agents, U.S. Bank National Association
as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the
Company’s Current Report on Form 8-K filed on August 7, 2017, File No. 001-12295).
Seventh Amendment to Fourth Amended and Restated Credit Agreement, dated as of August 28, 2018,
among Genesis Energy, L.P., as the borrower, Wells Fargo Bank, National Association, as
administrative agent and issuing bank, Bank of America, N.A. and Bank of Montreal, as co-syndication
agents, U.S. Bank National Association, as documentation agent, and the lenders party thereto
(incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on
August 31, 2018, File No. 333-177012).
Eighth Amendment to Fourth Amended and Restated Credit Agreement, dated as of October 11, 2018,
among Genesis Energy, L.P., as the borrower, Wells Fargo Bank, National Association, as
administrative agent and issuing bank, Bank of America, N.A. and Bank of Montreal, as co-syndication
agents, U.S. Bank National Association, as documentation agent, and the lenders party thereto
(incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on
October 11, 2018, File No. 001-12295).
Ninth Amendment to Fourth Amended and Restated Credit Agreement, dated as of September 23, 2019,
among Genesis Energy, L.P., as the borrower, Wells Fargo Bank, National Association, as
administrative agent and issuing bank, Bank of America, N.A. and Bank of Montreal, as co-syndication
agents, U.S. Bank National Association, as documentation agent, and the lenders party thereto
(incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on
September 23, 2019, File No. 001-12295).
Tenth Amendment to Fourth Amended and Restated Credit Agreement, dated as of March 25, 2020,
among Genesis Energy, L.P., as the borrower, Wells Fargo Bank, National Association, as
administrative agent and issuing bank, Bank of America, N.A. and Bank of Montreal, as co-syndication
agents, U.S. Bank National Association, as documentation agent, and the lenders party thereto
(incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the
quarter ended March 31, 2020, File No. 001-12295).
Eleventh Amendment to Fourth Amended and Restated Credit Agreement, dated as of July 24, 2020,
among Genesis Energy, L.P., as the borrower, Wells Fargo Bank, National Association, as
administrative agent and issuing bank, Bank of America, N.A. and Bank of Montreal, as co-syndication
agents, U.S. Bank National Association, as documentation agent, and the lenders party thereto
(incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 2020, File No. 001-12295).
Fifth Amended and Restated Credit Agreement, dated as of April 8, 2021, among Genesis Energy, L.P.,
as borrower, Wells Fargo Bank, National Association, as administrative agent, Bank of America, N.A.,
as syndication agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the
Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2021, File No.
001-12295).
* 10.14
10.15
10.16
First Amendment and Consent to Fifth Amended and Restated Credit Agreement, dated as of November
17, 2021, among Genesis Energy, L.P., as borrower, Wells Fargo Bank, National Association, as
administrative agent, Bank of America, N.A., as syndication agent, and the lenders party thereto.
Form of Indemnity Agreement, among Genesis Energy, L.P., Genesis Energy, LLC and each of the
Directors of Genesis Energy, LLC (incorporated by reference to Exhibit 10.1 to the Company’s Current
Report on Form 8-K filed on March 5, 2010, File No. 001-12295).
+ Genesis Energy, L.P. 2010 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the
Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No.
001-12295).
117
Table of Contents
10.17
+ Genesis Energy, LLC 2010 Long-Term Incentive Plan Form of Directors Phantom Unit with DERs
Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-
Q for the quarter ended March 31, 2013, File No. 001-12295).
10.18
+ Genesis Energy, LLC 2010 Long-Term Incentive Plan Form of Executive Phantom Unit with DERs
Award – Officers (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on
Form 10-Q for the quarter ended June 30, 2011, File No. 001-12295).
10.19
+ Genesis Energy, LLC 2010 Long-Term Incentive Plan Form of Employee Phantom Unit with DERs
Agreement (incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-
Q for the quarter ended March 31, 2010, File No. 001-12295).
10.20
10.21
+ Genesis Energy 2018 Long-Term Incentive Plan (incorporated by reference from Exhibit 10.1 to the
Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2018, File No. 001-12295).
+ Form of Award for 2018 LTIP (General) (incorporated by reference from Exhibit 10.2 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June 30, 2018, File No. 001-12295)
10.22
+ Form of Award for 2018 LTIP (Alkali) (incorporated by reference from Exhibit 10.3 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June 30, 2018, File No. 001-12295)
10.23
+ Form of Award for 2018 LTIP (Marine) (incorporated by reference from Exhibit 10.4 to the Company's
10.24
* 21.1
* 22.1
* 23.1
* 23.2
* 31.1
* 31.2
* 32.1
* 32.2
* 99.1
* 95
* 96.1
Quarterly Report on Form 10-Q for the quarter ended June 30, 2018, File No. 001-12295)
Board Observer Agreement, dated September 1, 2017, by and among Genesis Energy, L.P., GSO Rodeo
Holdings LP and Rodeo Finance Aggregator LLC (incorporated by reference from Exhibit 10.1 to the
Company’s Current Report on Form 8-K filed on September 7, 2017, File No. 001-12295).
Subsidiaries of the Registrant.
List of Issuers and Guarantor Subsidiaries.
Consent of Ernst & Young LLP.
Consent of Ernst & Young LLP.
Certification by Chief Executive Officer Pursuant to Rule 13a-14(a) under the Securities Exchange Act
of 1934.
Certification by Chief Financial Officer Pursuant to Rule 13a-14(a) under the Securities Exchange Act
of 1934.
Certification by Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Certification by Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Financial Statements of Poseidon Oil Pipeline Company, LLC for the three years ended December 31,
2021 (audited) pursuant to Rule 3-09 of Regulation S-X (17 CFR 210.3-09)
Mine Safety Disclosure Exhibit
S-K 1300 Technical Report Summary - Trona Properties, Green River, Wyoming, USA
* 101.INS
* 101.SCH
XBRL Instance Document- the instance document does not appear in the Interactive Data File because
its XBRL tags are embedded within the Inline XBRL document.
XBRL Schema Document.
* 101.CAL
XBRL Calculation Linkbase Document.
* 101.LAB
XBRL Label Linkbase Document.
* 101.PRE
XBRL Presentation Linkbase Document.
* 101.DEF
XBRL Definition Linkbase Document.
* 104
Cover Page Interactive Data File (formatted as Inline XBRL)
*
+
Filed herewith
A management contract or compensation plan or arrangement.
118
Table of Contents
Item 16. Form 10-K Summary
Not Applicable
119
Table of Contents
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: February 24, 2022
GENESIS ENERGY, L.P.
(A Delaware Limited Partnership)
By:
GENESIS ENERGY, LLC,
as General Partner
By:
/s/ GRANT E. SIMS
Grant E. Sims
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following
persons in the capacities and on the dates indicated.
NAME
TITLE
DATE
/s/ GRANT E. SIMS
Grant E. Sims
/s/ ROBERT V. DEERE
Robert V. Deere
/s/ KAREN N. PAPE
Karen N. Pape
/s/ CONRAD P. ALBERT
Conrad P. Albert
/s/ JAMES E. DAVISON
James E. Davison
/s/ JAMES E. DAVISON, JR.
James E. Davison, Jr.
/s/ SHARILYN S. GASAWAY
Sharilyn S. Gasaway
/s/ KENNETH M. JASTROW, II
Kenneth M. Jastrow, II
/s/ JACK T. TAYLOR
Jack T. Taylor
*
Genesis Energy, LLC is our general partner.
(OF GENESIS ENERGY, LLC)*
Chairman of the Board, Director and Chief Executive
Officer
(Principal Executive Officer)
Chief Financial Officer,
(Principal Financial Officer)
Senior Vice President and Controller
(Principal Accounting Officer)
Director
Director
Director
Director
Director
Director
February 24, 2022
February 24, 2022
February 24, 2022
February 24, 2022
February 24, 2022
February 24, 2022
February 24, 2022
February 24, 2022
February 24, 2022
120
Table of Contents
Item 8. Financial Statements and Supplementary Data
GENESIS ENERGY, L.P.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULES
Page
Financial Statements of Genesis Energy, L.P.
Report of Independent Registered Public Accounting Firm (PCAOB ID: 42)
Report of Independent Registered Public Accounting Firm on Internal Controls Over Financial
Reporting
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Income
Consolidated Statements of Partners’ Capital
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
1. Organization
2. Summary of Significant Accounting Policies
3. Revenue Recognition
4. Lease Accounting
5. Receivables
6. Inventories
7. Fixed Assets, Mineral Leaseholds and Asset Retirement Obligations
8. Equity Investees
9. Intangible Assets, Goodwill and Other Assets
10. Debt
11. Partners' Capital, Mezzanine Equity and Distributions
12. Net Income Per Common Unit
13. Business Segment Information
14. Transactions with Related Parties
15. Supplemental Cash Flow Information
16. Equity-Based Compensation Plans
17. Major Customers and Credit Risk
18. Derivatives
19. Fair-Value Measurements
20. Employee Benefit Plans
21. Commitments and Contingencies
22. Income Taxes
121
1
3
4
5
6
7
8
9
9
9
14
18
20
20
21
22
24
25
28
33
34
36
38
38
39
39
44
46
48
48
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Genesis Energy, LLC and Unitholders of Genesis Energy, L.P.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Genesis Energy, L.P. (the Partnership) as of December 31, 2021 and 2020,
the related consolidated statements of operations, comprehensive income (loss), partners’ capital and cash flows for each of the three years in
the period ended December 31, 2021, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion,
the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2021 and
2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity
with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the
Partnership’s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control-Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated
February 24, 2022 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the
Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be
independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the
Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits
included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and
performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and
disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by
management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis
for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was
communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the
financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit
matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the
critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Description of the
Matter
Revenue recognition - Estimation of variable consideration
As described in Note 3 to the consolidated financial statements, the Partnership’s Offshore pipeline transportation
segment has certain long-term contracts with customers that include variable consideration that must be estimated at
contract inception and re-assessed at each reporting period. Total consideration for these arrangements is recognized
as revenue over the performance obligation period, and the difference in timing of revenue recognition and billings
results in contract assets and liabilities. As of December 31, 2021, the Partnership has recognized $13.6 million in
current contract assets, and $2.6 million and $19.0 million in current and non-current contract liabilities,
respectively, in the consolidated financial statements.
Auditing the Partnership’s revenue recognition for these contracts is particularly challenging because the estimate of
variable consideration for these contracts involves management’s judgments of volumes that customers are expected
to produce and transport over the contract term. Changes in this assumption or a contract modification could have a
material effect on the amount of variable consideration recognized as revenue.
1
Table of Contents
How We
Addressed the
Matter in Our
Audit
We tested controls that address the risk of material misstatement relating to the estimation of variable
consideration and associated contract assets and liabilities. For example, we tested controls over the
completeness and accuracy of volumes transported and billings during the year and management’s review of
estimated production over the performance obligation period.
To test the Partnership’s estimates of variable consideration, we performed audit procedures that included,
among others, evaluating management’s determination of the performance obligations in each arrangement
and information used to establish or reassess the estimates including contractual pipeline capacity reserved,
historical actual throughput volumes and third party production forecasts. We tested these assumptions by
inspecting contracts, testing completeness and accuracy of production volumes and contract billings, and
evaluating information obtained by management from customers and whether the information is consistent
with publicly available information. We also performed a retrospective analysis of forecasted production
volumes by comparing them to the actual volumes transported, and we performed sensitivity analyses to
evaluate the changes in variable consideration that would result from changes in the Partnership's significant
assumptions discussed herein. We also recalculated the Partnership’s revenue recognized for these
arrangements and the recorded contract assets and liabilities as of and for the year ended December 31, 2021.
/s/ Ernst & Young LLP
We have served as the Partnership's auditor since 2017.
Houston, Texas
February 24, 2022
2
Table of Contents
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Genesis Energy, LLC and Unitholders of Genesis Energy, L.P.
Opinion on Internal Control Over Financial Reporting
We have audited Genesis Energy, L.P.’s internal control over financial reporting as of December 31, 2021, based on criteria established in
Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013
framework) (the COSO criteria). In our opinion, Genesis Energy, L.P. (the Partnership) maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2021, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the
consolidated balance sheets of the Partnership as of December 31, 2021 and 2020, the related consolidated statements of operations,
comprehensive income (loss), partners’ capital and cash flows for each of the three years in the period ended December 31, 2021 and the
related notes, and our report dated February 24, 2022 expressed an unqualified opinion thereon.
Basis for Opinion
The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting included in the accompanying Management’s annual report on internal control over
financial reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our
audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in
accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the
PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists,
testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other
procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting
principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of
records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide
reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally
accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of
management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or
that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young LLP
Houston, Texas
February 24, 2022
3
GENESIS ENERGY, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands, except units)
ASSETS
Table of Contents
CURRENT ASSETS:
Cash and cash equivalents
Restricted cash
Accounts receivable—trade, net
Inventories
Other
Total current assets
FIXED ASSETS, at cost
Less: Accumulated depreciation
Net fixed assets
MINERALS LEASEHOLDS, net of accumulated depletion
EQUITY INVESTEES
INTANGIBLE ASSETS, net of amortization
GOODWILL
RIGHT OF USE ASSETS, net
OTHER ASSETS, net of amortization
TOTAL ASSETS
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable—trade
Accrued liabilities
Total current liabilities
SENIOR SECURED CREDIT FACILITY
SENIOR UNSECURED NOTES, net of debt issuance costs
DEFERRED TAX LIABILITIES
OTHER LONG-TERM LIABILITIES
Total liabilities
MEZZANINE CAPITAL
December 31,
2021
December 31,
2020
$
19,987 $
5,005
400,334
77,958
39,200
542,484
21,282
5,736
392,465
99,877
60,809
580,169
5,464,040
5,173,475
(1,551,855)
(1,322,141)
3,912,185
3,851,334
549,005
294,050
127,063
301,959
140,796
38,259
552,575
319,068
128,742
301,959
153,925
45,847
$
5,905,801 $
5,933,619
$
264,316 $
232,623
496,939
49,000
198,433
184,978
383,411
643,700
2,930,505
2,750,016
14,297
434,925
3,925,666
13,317
393,018
4,183,462
Class A Convertible Preferred Units, 25,336,778 issued and outstanding at December
31, 2021 and 2020
Redeemable noncontrolling interests, 246,394 and 141,249 preferred units issued and
outstanding at December 31, 2021 and 2020, respectively
790,115
790,115
259,568
141,194
COMMITMENTS AND CONTINGENCIES (Note 21)
PARTNERS’ CAPITAL:
Common unitholders, 122,579,218 units issued and outstanding at December 31, 2021
and 2020
Accumulated other comprehensive loss
Noncontrolling interests
Total partners' capital
641,313
829,326
(5,607)
294,746
930,452
(9,365)
(1,113)
818,848
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL
$
5,905,801 $
5,933,619
The accompanying notes are an integral part of these consolidated financial statements.
4
Table of Contents
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
REVENUES:
Offshore pipeline transportation
Sodium minerals and sulfur services
Marine transportation
Onshore facilities and transportation
Total revenues
COSTS AND EXPENSES:
Onshore facilities and transportation product costs
Onshore facilities and transportation operating costs
Marine transportation operating costs
Sodium minerals and sulfur services operating costs
Offshore pipeline transportation operating costs
General and administrative
Depreciation, depletion and amortization
Impairment expense
Loss on sale of assets
Total costs and expenses
OPERATING INCOME (LOSS)
Equity in earnings of equity investees
Interest expense
Other expense, net
Income (loss) from operations before income taxes
Income tax expense
NET INCOME (LOSS)
Net income attributable to noncontrolling interests
Net income attributable to redeemable noncontrolling interests
NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY,
L.P.
Less: Accumulated distributions attributable to Class A Convertible
Preferred Units
NET INCOME (LOSS) AVAILABLE TO COMMON
UNITHOLDERS
BASIC AND DILUTED NET INCOME (LOSS) PER COMMON
UNIT:
Year Ended December 31,
2021
2020
2019
$
278,459 $
237,146 $
318,116
964,632
190,827
691,558
877,769
210,258
499,482
1,105,987
235,645
821,072
2,125,476
1,824,655
2,480,820
583,824
63,113
156,307
795,964
79,641
61,185
309,746
—
—
373,127
70,241
149,557
745,858
76,717
56,920
295,322
280,826
22,045
637,699
77,205
178,032
883,692
58,996
52,687
319,806
—
—
2,049,780
2,070,613
2,208,117
75,696
57,898
(245,958)
64,019
272,703
56,484
(233,724)
(209,779)
(219,440)
(36,232)
(7,269)
(9,026)
(136,362)
(398,987)
100,721
(1,670)
(1,327)
(655)
(138,032)
(400,314)
100,066
(1,637)
(251)
(25,398)
(16,113)
(1,834)
(2,233)
$
(165,067) $
(416,678) $
95,999
(74,736)
(74,736)
(74,467)
$
(239,803) $
(491,414) $
21,532
Basic and Diluted
$
(1.96) $
(4.01) $
0.18
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
Basic and Diluted
`
122,579
122,579
122,579
The accompanying notes are an integral part of these consolidated financial statements.
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GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)
Net income (loss)
Other comprehensive income (loss):
Decrease (increase) in benefit plan liability
Total Comprehensive income (loss)
Comprehensive income attributable to noncontrolling interests
Comprehensive income attributable to redeemable noncontrolling interests
Year Ended December 31,
2021
2020
2019
$ (138,032) $ (400,314) $ 100,066
3,758
(934)
(134,274)
(401,248)
(1,637)
(25,398)
(251)
(16,113)
(9,370)
90,696
(1,834)
(2,233)
Comprehensive income (loss) attributable to Genesis Energy, L.P.
$ (161,309) $ (417,612) $
86,629
The accompanying notes are an integral part of these consolidated financial statements.
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GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(In thousands)
December 31, 2018
Net income
Cash distributions to partners
Cash contributions from noncontrolling interests
Other comprehensive loss
Distributions to preferred unitholders
December 31, 2019
Net income (loss)
Cash distributions to partners
Cash contributions from noncontrolling interests
Other comprehensive loss
Distributions to preferred unitholders
December 31, 2020
Net income (loss)
Cash distributions to partners
Sale of noncontrolling interest in subsidiary
Cash distributions to noncontrolling interests
Cash contributions from noncontrolling interests
Other comprehensive income
Distributions to preferred unitholders
December 31, 2021
Number of
Common
Units
Partners’
Capital
Noncontrolling
Interest
Accumulated
Other
Comprehensive
Loss
Total
122,579
1,690,799
(11,204)
939
1,680,534
—
—
—
—
—
95,999
(269,674)
—
—
(73,804)
1,834
—
5,652
—
—
—
—
—
97,833
(269,674)
5,652
(9,370)
(9,370)
—
(73,804)
122,579
1,443,320
(3,718)
(8,431) 1,431,171
—
—
—
—
—
(416,678)
(122,580)
—
—
(74,736)
251
—
2,354
—
—
—
—
(416,427)
(122,580)
—
(934)
2,354
(934)
—
(74,736)
122,579
829,326
(1,113)
(9,365)
818,848
—
—
—
—
—
—
—
(165,067)
(73,548)
1,637
—
125,338
294,422
—
—
—
(74,736)
(903)
703
—
—
—
—
—
—
—
3,758
(163,430)
(73,548)
419,760
(903)
703
3,758
—
(74,736)
122,579 $ 641,313 $
294,746 $
(5,607) $ 930,452
The accompanying notes are an integral part of these consolidated financial statements.
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GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by
operating activities -
Depreciation, depletion and amortization
Loss on sale of assets
Impairment expense
Year Ended December 31,
2020
2019
2021
$ (138,032) $ (400,314) $ 100,066
309,746
295,322
319,806
—
—
22,045
280,826
—
—
Amortization and write-off of debt issuance costs and premium or discount
13,716
22,610
10,766
Amortization of unearned income and initial direct costs on direct financing
leases
Payments received under previously owned direct financing leases
Equity in earnings of investments in equity investees
Cash distributions of earnings of equity investees
Non-cash effect of long-term incentive compensation plans
Deferred and other tax liabilities
Cancellation of debt income
Unrealized losses on derivative transactions
Other, net
Net changes in components of operating assets and liabilities, net of
acquisitions (See Note 15)
Net cash provided by operating activities
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets
Cash distributions received from equity investees—return of investment
Investments in equity investees
Proceeds from asset sales
Net cash used in investing activities
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility
Repayments on senior secured credit facility
Proceeds from issuance of senior unsecured notes (Note 10)
Net proceeds from issuance of preferred units (Note 11)
Repayment of senior unsecured notes (Note 10)
Debt issuance costs
Contributions from noncontrolling interests
Distributions to noncontrolling interests
Distributions to Class A Convertible Preferred unitholders (Note 11)
Distributions to common unitholders (Note 11)
—
(8,847)
(12,247)
70,000
56,837
20,668
(57,898)
(64,019)
(56,484)
57,080
8,783
980
—
30,700
12,832
63,721
(3,693)
56,081
8,496
512
(27,302)
1,191
19,229
65
—
12,586
(6,418)
30,044
38,627
(71,098)
337,951
296,745
382,287
(301,395) (144,133)
(163,248)
27,026
(352)
604
17,340
—
23,037
21,250
—
1,187
(274,117) (103,756)
(140,811)
776,300
(1,371,000) (1,338,600)
1,023,000
815,100
(825,900)
259,375
93,100
1,500,000
—
—
122,900
(80,859) (1,185,096)
(12,348)
(26,680)
703
(903)
2,354
—
—
—
5,652
—
(74,736)
(74,736)
(43,506)
(73,548) (122,580)
(269,674)
Cash proceeds from the sale of a noncontrolling interest in a subsidiary
418,140
—
—
Other, net
Net cash used in financing activities
Net increase (decrease) in cash and cash equivalents and restricted cash
Cash and cash equivalents and restricted cash at beginning of period
(84)
(38)
(65,860) (222,376)
(29,387)
(2,026)
57
(195,371)
46,105
27,018
56,405
10,300
Cash and cash equivalents and restricted cash at end of period
$ 24,992 $ 27,018 $
56,405
The accompanying notes are an integral part of these consolidated financial statements.
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1. Organization
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We are a growth-oriented master limited partnership founded in Delaware in 1996 and focused on the midstream
segment of the crude oil and natural gas industry as well as the production of natural soda ash. Our operations are primarily
located in the Gulf Coast region of the United States, Wyoming, and in the Gulf of Mexico. We provide an integrated suite of
services to refiners, crude oil and natural gas producers, and industrial and commercial enterprise and have a diverse portfolio
of assets, including pipelines, offshore hub and junction platforms, our trona and trona-based exploring, mining, processing,
producing, marketing, and selling business based on Wyoming (our “Alkali Business”), refinery-related plants, storage tanks
and terminals, railcars, rail unloading facilities, barges and other vessels, and trucks. We are owned 100% by our limited
partners. Genesis Energy, LLC, our general partner, is a wholly-owned subsidiary. Our general partner has sole responsibility
for conducting our business and managing our operations. We conduct our operations and own our operating assets through our
subsidiaries and joint ventures.
We currently manage our businesses through four divisions that constitute our reportable segments:
•
•
•
Offshore pipeline transportation, which includes processing of crude oil and natural gas in the Gulf of Mexico;
Sodium minerals and sulfur services involving trona and trona-based exploring, mining, processing, soda ash
production, marketing and selling activities, as well as processing of high sulfur (or “sour”) gas streams for
refineries to remove the sulfur, and selling the related by-product, sodium hydrosulfide (or “NaHS,” commonly
pronounced “nash”);
Onshore facilities and transportation, which include terminaling, blending, storing, marketing, and transporting
crude oil and petroleum products; and
• Marine transportation to provide waterborne transportation of petroleum products and crude oil throughout North
America
Covid-19 and Market Update
In March 2020, the World Health Organization categorized Covid-19 as a pandemic, and the President of the United
States declared the Covid-19 outbreak a national emergency. Our operations, which fall within the energy, mining and
transportation sectors, are considered critical and essential by the Department of Homeland Security's Cybersecurity and
Infrastructure Security Agency and we have continued to operate our assets during this pandemic.
We have a designated internal management team to provide resources, updates, and support to our entire workforce
during this pandemic, while maintaining a focus to ensure the safety and well-being of our employees, the families of our
employees, and the communities in which our businesses operate. We will continue to act in the best interests of our
employees, stakeholders, customers, partners, and suppliers and make any necessary changes as required by federal, state, or
local authorities as we continue to actively monitor the situation.
Beginning in March 2020, Covid-19 has caused continued volatility in commodity prices due to, among other things,
reduced industrial activity and travel demand, varying worldwide restrictions, and the timing of the re-opening of economies.
Additionally, actions taken by the OPEC and other oil exporting nations beginning in that timeframe caused additional volatility
in the price of oil and gas. We will continue to monitor the market environment and will evaluate whether additional triggering
events would indicate possible impairments of long-lived assets, intangible assets and goodwill. Management’s estimates are
based on numerous assumptions about future operations and market conditions, which we believe to be reasonable but are
inherently uncertain. The uncertainties underlying our assumptions could cause our estimates to differ significantly from actual
results, including with respect to the duration and severity of the Covid-19 pandemic. In the current volatile economic
environment and to the extent conditions further deteriorate, we may identify additional triggering events that may require
future evaluations of the recoverability of the carrying value of our long-lived assets, intangible assets and goodwill, which
could result in impairment charges that could be material to our results of operations.
2. Summary of Significant Accounting Policies
Basis of Consolidation and Presentation
The accompanying financial statements and related notes present our consolidated financial position as of December
31, 2021 and 2020 and our results of operations, statements of comprehensive income (loss), changes in partners’ capital and
cash flows for the years ended December 31, 2021, 2020 and 2019. All intercompany balances and transactions have been
eliminated. The accompanying Consolidated Financial Statements include Genesis Energy, L.P. and its subsidiaries.
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Except per unit amounts, or as noted within the context of each footnote disclosure, the dollar amounts presented in the
tabular data within these footnote disclosures are stated in thousands of dollars.
Joint Ventures
We participate in several joint ventures, including, in our offshore pipeline transportation segment, a 64% interest in
Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”), a 25.7% interest in Neptune Pipeline Company, LLC, a 29% interest in
Odyssey Pipeline L.L.C. (“Odyssey”), and a 26.8% interest in Paloma Pipeline Company (“Paloma”). We account for our
investments in these joint ventures by the equity method of accounting. See Note 8.
Noncontrolling interests
Noncontrolling interests represent any third party or affiliate interest in non-wholly owned entities that we consolidate.
For financial reporting purposes, the assets and liabilities of these entities are consolidated with those of our own, with any third
party or affiliate interest in our Consolidated Balance Sheets amounts shown as noncontrolling interests in equity. See Note 11
for additional discussion regarding our noncontrolling interests.
Use of Estimates
The preparation of our Consolidated Financial Statements requires us to make estimates and assumptions that affect
the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the
Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. We based
these estimates and assumptions on historical experience and other information that we believed to be reasonable under the
circumstances. Significant estimates that we make include: (1) liability and contingency accruals, including the estimates of
future asset retirement obligations, (2) estimated fair value of assets and liabilities acquired and identification of associated
goodwill and intangible assets, (3) estimates of future net cash flows from assets for purposes of determining whether
impairment of those assets has occurred, (4) estimates of variable consideration for revenue recognition, (5) estimated fair value
of derivative instruments, and (6) estimated useful lives of our fixed and intangible assets (including the reserve life of our
mineral leaseholds) for the use in calculating depreciation, depletion, and amortization of long-lived assets and intangible
assets. While we believe these estimates are reasonable, actual results could differ from these estimates. Changes in facts and
circumstances may result in revised estimates.
Cash and Cash Equivalents
Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original
maturities of three months or less. We periodically assess the financial condition of the institutions where these funds are held
and believe that our credit risk is minimal.
Restricted Cash
Our restricted cash balance represents cash held to be used for purposes of our Granger expansion project (the
“Granger Optimization Project”), as well as a minimum working capital balance we are required to maintain at our unrestricted
subsidiary level under contractual agreement and is classified as current on our Consolidated Balance Sheets (see Note 11).
Accounts Receivable
We review our outstanding accounts receivable balances on a regular basis and estimate an allowance for amounts that
we expect will not be fully recovered. An allowance for credit losses is determined based upon historical collectability trends,
recoveries, historical write-offs, and current market data for the Partnership’s customers in order to estimate projected losses.
Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted.
Inventories
Our inventories are valued at the lower of cost and net realizable value. With the exception of our Alkali Business, cost
is determined principally under the average cost method within specific inventory pools.
Within our Alkali Business, the cost of inventories are determined using the FIFO method, except for materials and
supplies which are recorded at average cost, and raw materials which are recorded at standard cost, which approximates actual
cost.
Fixed Assets and Mineral Leaseholds
Property and equipment are carried at cost. Depreciation of property and equipment is provided using the straight-line
method over the respective estimated useful lives of the assets. Asset lives are 5 to 40 years for pipelines and related assets, 20
to 30 years for marine vessels, 3 to 30 years for machinery and equipment, 3 to 7 years for transportation equipment, and 3 to
20 years for buildings and improvements, office equipment, furniture and fixtures and other equipment.
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Interest is capitalized in connection with the construction of major facilities. The capitalized interest is recorded as part
of the asset to which it relates and is amortized over the asset’s estimated useful life.
Maintenance and repair costs are charged to expense as incurred. Costs incurred for major replacements and upgrades
are capitalized and depreciated over the remaining useful life of the asset. Certain volumes of crude oil and refined products are
classified in fixed assets, as they are necessary to ensure efficient and uninterrupted operations of the gathering businesses.
These crude oil and refined products volumes are carried at their weighted average cost.
Long-lived assets are reviewed for impairment. An asset is tested for impairment when events or circumstances
indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds
the sum of the undiscounted cash flows expected to be generated from the use and ultimate disposal of the asset. If the carrying
value is determined to not be recoverable under this method, an impairment charge equal to the amount the carrying value
exceeds the fair value is recognized. Fair value is generally determined from estimated discounted future net cash flows.
Mineral leaseholds are depleted over their useful lives as determined under the units of production method. When it
has been determined that a mineral property can be economically developed as a result of establishing proven and probable
reserves, the costs incurred to develop such property through the commencement of production are capitalized.
Deferred Charges on Marine Transportation Assets
Our marine vessels are required by US Coast Guard regulations to be re-certified after a certain period of time, usually
every five years. The US Coast Guard states that vessels must meet specified “seaworthiness” standards to maintain required
operating certificates. To meet such standards, vessels must undergo regular inspection, monitoring, and maintenance, referred
to as “dry-docking.” Typical dry-docking costs include costs incurred to comply with regulatory and vessel classification
inspection requirements, blasting and steel coating, and steel replacement. We defer and amortize these costs to maintenance
and repair expense over the length of time that the certification is supposed to last.
Asset Retirement Obligations
Some of our assets have contractual or regulatory obligations to perform dismantlement and removal activities, and in
some instances remediation, when the assets are abandoned. In general, our asset retirement obligations (“AROs”) relate to
future costs associated with the disconnecting or removing of our crude oil and natural gas pipelines and platforms, barge
decommissioning, removal of equipment and facilities from leased acreage and land restoration. The estimated fair value of a
liability for an asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using
our credit adjusted risk-free interest rate, and a corresponding amount is capitalized by increasing the carrying amount of the
related long-lived asset. The capitalized cost is depreciated over the useful life of the related asset. An ongoing expense is
recognized for changes in fair value of the liability as a result of the passage of time, which is recorded as accretion expense and
included within operating costs in the Consolidated Statements of Operations. See Note 7.
Lease Accounting
We enter into operating lease contracts for the right to utilize certain transportation equipment, facilities and
equipment, and office space from third parties. For contracts that contain a lease and extend for a period greater than 12 months,
we recognize a right of use asset and a corresponding lease liability on our Consolidated Balance Sheets. The present value of
each lease is based on the future minimum lease payments in accordance with ASC 842 and is determined by discounting these
payments using an incremental borrowing rate. From time to time, we enter into agreements in which we are lessors of our
property or equipment. For operating leases, revenue is recognized upon the satisfaction of the respective performance
obligation. For direct finance leases, we record the gross finance receivable, unearned income and the estimated residual value
of the leased pipelines. Unearned income represents the excess of the gross receivable plus the estimated residual value over the
costs of the pipelines. Unearned income is recognized as financing income using the interest method over the term of the
transaction. The pipeline cost is not included in fixed assets. Refer to Note 4 for additional information.
Intangible and Other Assets
Intangible assets with finite useful lives are amortized over their respective estimated useful lives on a straight-line
basis. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset shall be
amortized over the best estimate of its useful life. At a minimum, we will assess the useful lives and residual values of all
intangible assets on an annual basis to determine if adjustments are required.
We test intangible assets periodically to determine if impairment has occurred. An impairment loss is recognized for
intangibles if the carrying amount of an intangible asset is not recoverable and its carrying amount exceeds its fair value. No
impairment has occurred of intangible assets in any of the periods presented.
Costs incurred in connection with our credit facilities and their related amendments have historically been capitalized
and amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ
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materially from the “effective interest” method of amortization. Certain of our capitalized debt issuance costs related to our
respective issuances of notes are classified as reductions in long-term debt.
Goodwill
Goodwill represents the excess of purchase price over fair value of net assets acquired. We evaluate, and test if
necessary, goodwill for impairment annually at October 1, and more frequently if indicators of impairment are present. During
the evaluation, we may perform a qualitative assessment of relevant events and circumstances to determine the likelihood of
goodwill impairment. If it is deemed more likely than not that the fair value of the reporting unit is less than its carrying
amount, we calculate the fair value of the reporting unit. Otherwise, further testing is not necessary. We may also elect to
exercise our unconditional option to bypass this qualitative assessment, in which case we would also calculate the fair value of
the reporting unit. If the calculated fair value of the reporting unit exceeds its carrying value including associated goodwill
amounts, no impairment charge is required. If the fair value of the reporting unit is less than its carrying value including
associated goodwill amounts, the goodwill of that reporting unit is considered to be impaired and a charge to earnings must be
recorded. The impact to earnings is the excess amount of carrying value over fair value, however the charge is not to exceed the
total amount of goodwill allocated to the reporting unit under evaluation. See Note 9 for further information.
Environmental Liabilities
We provide for the estimated costs of environmental contingencies when liabilities are probable to occur and a
reasonable estimate of the associated costs can be made. Ongoing environmental compliance costs, including maintenance and
monitoring costs, are charged to expense as incurred.
Equity-Based Compensation
The phantom units issued under our 2010 Long-Term Incentive Plan result in the payment of cash to our employees or
directors of our general partner upon exercise or vesting of the related award. The fair value of our phantom units is equal to the
market price of our common units. Our phantom units outstanding at December 31, 2021 include only service-based awards
issued to our directors. See Note 16 for more information.
Revenue Recognition
We recognize revenue across our operating segments upon the satisfaction of their respective performance obligations.
Refer to Note 3 for additional details on what constitutes a performance obligation in each of our businesses.
Cost of Sales and Operating Expenses
Onshore facilities and transportation operating and product costs include the cost to acquire the product and the
associated costs to transport it to our terminal facilities, including storing, or to a customer for sale. Other than the cost of the
products, the most significant costs we incur relate to transportation utilizing our fleet of trucks, railcars, terminals, barges and
other vessels, including personnel costs, fuel and maintenance of our or third-party owned equipment. Additionally, costs to
operate and maintain the integrity of our onshore pipelines are included herein.
When we enter into buy/sell arrangements concurrently or in contemplation of one another with a single counterparty,
we reflect the amounts of revenues and purchases for these transactions on a net basis in our Consolidated Statements of
Operations as onshore facilities and transportation revenues.
Marine operating costs consist primarily of employee and related costs to man the boats, barges, and vessels,
maintenance and supply costs related to general upkeep of the boats, barges, and vessels, and fuel costs which are often
rebillable and passed through to the customer.
The most significant operating costs in our sodium minerals and sulfur services segment consist of the costs to operate
our trona extraction and soda ash processing facilities, NaHS processing plants located at various refineries, caustic soda used
in the process of processing the refiner’s sour gas, and costs to transport the soda ash, other alkali products, NaHS and caustic
soda.
Pipeline operating costs consist primarily of power costs to operate pumping and platform equipment, personnel costs
to operate the pipelines and platforms, insurance costs and costs associated with maintaining the integrity of our pipelines.
Income Taxes
We are a limited partnership, organized as a pass-through entity for federal income tax purposes. As such, we do not
directly pay federal income tax. Our taxable income or loss, which may vary substantially from the net income or net loss we
report in our Consolidated Statements of Operations, is included in the federal income tax returns of each partner.
Some of our corporate subsidiaries pay U.S. federal, state, and foreign income taxes. Deferred income tax assets and
liabilities for certain operations conducted through corporations are recognized for temporary differences between the assets
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and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in
the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance for the amount of any
tax benefit not expected to be realized. Penalties and interest related to income taxes will be included in income tax expense in
the Consolidated Statements of Operations.
Derivative Instruments and Hedging Activities
When we hold inventory positions in crude oil and petroleum products, we use derivative instruments to hedge
exposure to price risk. Derivative transactions, which can include forward contracts and futures positions on the NYMEX, are
recorded in the Consolidated Balance Sheets as assets and liabilities based on the derivative’s fair value. Changes in the fair
value of derivative contracts are recognized currently in earnings unless specific hedge accounting criteria are met. We must
formally designate the derivative as a hedge and document and assess the effectiveness of derivatives associated with
transactions that receive hedge accounting. Accordingly, changes in the fair value of derivatives are included in earnings in the
current period for (i) derivatives accounted for as fair value hedges; (ii) derivatives that do not qualify for hedge accounting and
(iii) the portion of cash flow hedges that is not highly effective in offsetting changes in cash flows of hedged items. Changes in
the fair value of cash flow hedges are deferred in Accumulated Other Comprehensive Income (Loss) (“AOCI”) and reclassified
into earnings when the underlying position affects earnings. As of December 31, 2021, we did not have any cash flow hedges.
In addition, we have determined that certain provisions in our Class A Convertible Preferred Units represent an
embedded derivative which must be bifurcated and recorded at fair value, with changes in fair value in respective periods
recorded in our Consolidated Statements of Operations. See Note 18 for further information on these items.
Fair Value of Current Assets and Current Liabilities
The carrying amount of other current assets and other current liabilities approximates their fair value due to their short-
term nature.
Pension benefits
We sponsor a defined benefit plan for employees of our Alkali Business. The defined benefit plan is accounted for
using actuarial valuations as required by GAAP. We recognize the funded status of the defined pension plan on the balance
sheet and recognize changes in the funded status that arise during the period but are not recognized as components of net
periodic benefit cost within other comprehensive income (loss).
Business Acquisitions
For acquired businesses, we apply the acquisition method and generally recognize the identifiable assets acquired, the
liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the date of acquisition.
Recent and Proposed Accounting Pronouncements
We have adopted guidance under ASC Topic 326, Financial Instruments - Credit Losses (“ASC 326”), as of January 1,
2020. The standard changed the impairment model for most financial assets and certain other instruments. For trade and other
receivables, held-to-maturity debt securities, loans, and other instruments, entities are required to use a new forward-looking
“expected loss” model that generally will result in the earlier recognition of allowances for losses. We have assessed our
receivables for expected losses by considering current and historical information pertaining to our trade accounts and existing
contract assets. Our assessment resulted in an immaterial impact to our consolidated financial statements as of the adoption date
and for the years ended December 31, 2021 and 2020.
During the first quarter of 2020, the SEC amended the financial disclosure requirements for guarantors and issuers of
guaranteed securities registered or being registered in Rule 3-10 of Regulation S-X to go in effect January 4, 2021. The
amendment simplifies the disclosure requirements and permits the amended disclosures to be provided outside the footnotes in
audited annual or unaudited interim consolidated financial statements in all filings. As permitted by the amendment, we have
early adopted the amendment and included the required summarized financial information in Item 7. Management's Discussion
and Analysis of Financial Condition and Results of Operations.
We have adopted guidance under ASC Topic 842, Lease Accounting (“ASC 842”), as of January 1, 2019 utilizing the
modified retrospective method of adoption. Additionally, we elected to implement the practical expedients that pertain to
easements, separation of lease components, and the package of practical expedients, which among other things, allows us to
carry over previous lease conclusions reached under ASC 840. Refer to Note 4 for further details.
In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848), which provides expedients and
exceptions for accounting treatment of contracts which are affected by the anticipated discontinuation of the London InterBank
Offered Rate (“LIBOR”) and other rates resulting from rate reform that are entered into on or before December 31, 2022.
Contract terms that are modified due to the replacement of a reference rate are not required to be remeasured or reassessed
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under relevant accounting standards. The discontinuation of LIBOR is expected to occur in 2023. We are evaluating the
provisions of ASU 2020-04 and have not yet determined the impact on our Consolidated Financial Statements and disclosures
related to our senior secured credit facility due to the timing of the transition to another interest rate benchmark.
3. Revenue Recognition
Revenue from Contracts with Customers
The following table reflects the disaggregation of our revenues by major category for the years ended December 31,
2021, December 31, 2020, and December 31, 2019, respectively:
Fee-based revenues
Product Sales
Refinery Services
Fee-based revenues
Product Sales
Refinery Services
Fee-based revenues
Product Sales
Refinery Services
Year Ended December 31, 2021
Offshore
Pipeline
Transportation
Sodium
Minerals &
Sulfur Services
Marine
Transportation
Onshore
Facilities &
Transportation
Consolidated
$
278,459
$
—
$
190,827 $
86,711
$
555,997
—
—
863,264
101,368
—
—
604,847
1,468,111
—
101,368
$
278,459
$
964,632
$
190,827 $
691,558
$ 2,125,476
Year Ended December 31, 2020
Offshore
Pipeline
Transportation
Sodium
Minerals &
Sulfur Services
Marine
Transportation
Onshore
Facilities &
Transportation
Consolidated
$
237,146
$
—
$
210,258 $
106,092
$
553,496
—
—
789,307
88,462
—
—
393,390
1,182,697
—
88,462
$
237,146
$
877,769
$
210,258 $
499,482
$ 1,824,655
Year Ended December 31, 2019
Offshore
Pipeline
Transportation
Sodium
Minerals &
Sulfur Services
Marine
Transportation
Onshore
Facilities &
Transportation
Consolidated
$
318,116
$
—
$
235,645 $
160,431
$
714,192
—
—
1,023,667
82,320
—
—
660,641
1,684,308
—
82,320
$
318,116
$ 1,105,987
$
235,645 $
821,072
$ 2,480,820
The Company recognizes revenue upon the satisfaction of its performance obligations under its contracts. The timing
of revenue recognition varies for the revenue streams described in more detail below. In general, the timing includes
recognition of revenue over time as services are being performed as well as recognition of revenue at a point in time for
delivery of products.
Fee-based Revenues
We provide a variety of fee-based transportation and logistics services to our customers across several of our
reportable segments as outlined below.
Service contracts generally contain a series of distinct services that are substantially the same and have the same
pattern of transfer to the customer over the contract period, and therefore qualify as a single performance obligation that is
satisfied over time. The customer receives and consumes the benefit of our services simultaneously with the provision of those
services.
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Offshore Pipeline Transportation
Revenue from our offshore pipelines is generally based upon a fixed fee per unit of volume (typically per Mcf of
natural gas or per barrel of crude oil) gathered, transported, or processed for each volume delivered. Fees are based either on
contractual arrangements or tariffs regulated by the FERC. Certain of our contracts include a single performance obligation to
stand ready, on a monthly basis, to provide capacity on our assets. Revenue associated with these fee-based services is
recognized as volumes are delivered over the performance obligation period.
In addition to the offshore pipeline transportation revenue discussed above, we also have certain contracts with
customers in which we earn either demand-type fees or firm capacity reservation fees. These fees are charged to a customer
regardless of the volume the customer actually delivers to the platform or through the pipeline.
In addition to these offshore pipeline transportation revenue streams, we also have certain customer contracts in which
the transportation fee has a tiered pricing structure based on cumulative milestones of throughput on the related pipeline asset
and contract, or on a specified date. The performance obligation for these contracts is to transport, gather or process
commodity volumes for the customer based on firm (stand ready) service or from monthly nominations made by our customers,
which can also be on an interruptible basis. While our transportation rate changes when milestones are achieved for certain
cumulative throughput, our performance obligation does not change throughout the life of the contract. Therefore revenue is
recognized on an average rate basis throughout the life of the contract. We have estimated the total consideration to be received
under the contract beginning at the contract inception date based on the estimated volumes (including certain minimum volumes
we are required to stand ready for), price indexing, estimated production or contracted volumes, and the contract period. We
have constrained the estimates of variable consideration such that it is probable that a significant reversal of previously-
recognized revenue will not occur throughout the life of the contract. These estimates are reassessed at each reporting period as
required. Billings to our customers are reflected at the contract rate. The difference between the consideration received from our
customers from invoicing compared to the revenue recognized creates a contract asset or liability. In circumstances where the
estimated average contract rate is less than the billed current price tier in the contract, we will recognize a contract liability. In
circumstances where the estimated average contract rate is higher than the billed current price tier in the contract, we will
recognize a contract asset.
Onshore Facilities and Transportation
Within our onshore facilities and transportation segment, we provide our customers with pipeline transportation,
terminaling services, and rail unloading services, among others, primarily on a per barrel fee basis.
Revenues from contracts for the transportation of crude oil by our pipelines are based on actual volumes at a published
tariff and some contain minimum throughput provisions which reset within one year. We recognize revenues for transportation
and other services over the performance obligation period, which is the contract term. Revenues for both firm and interruptible
transportation and other services are recognized over time as the product is delivered to the agreed upon delivery point or at the
point of receipt because they specifically relate to our efforts to transfer the distinct services.
Pricing for our services is determined through a variety of mechanisms, including specified contract pricing or
regulated tariff pricing. The consideration we receive under these contracts is variable, as the total volume of the commodity to
be transported is unknown at contract inception. At the end of a day or month (as specified in the contract), both the price and
volume are known (or “fixed”) in order to allow us to accurately calculate the amount of consideration we are entitled to
invoice. The measurement of these services and invoicing occurs on a monthly basis.
Pipeline Loss Allowances
To compensate us for bearing the risk of volumetric losses of crude oil in transit in our pipelines (for our onshore and
offshore pipelines) due to temperature, crude quality, and the inherent difficulties of measurement of liquids in a pipeline, our
tariffs and agreements allow for us to make volumetric deductions for quality and volumetric fluctuations. We refer to these
deductions as pipeline loss allowances (“PLA”). We compare these allowances to the actual volumetric gains and losses of the
pipeline and the net gain or loss is recorded as revenue or a reduction of revenue. As the allowance is related to our pipeline
transportation services, the performance obligation is the obligation to transport and deliver the barrels and is considered a
single obligation.
When net gains occur, we have crude oil inventory. When net losses occur, we reduce any recorded inventory on hand
and record a liability for the purchase of crude oil required to replace the lost volumes. Under ASC 606, we record excess oil as
non-cash consideration in the transaction price on a net basis. The net oil recorded is valued at the lower of cost or net
realizable value using the market price of crude oil during the month the product was transported. The crude oil in inventory
can then be sold at current prevailing market prices, resulting in additional revenue if the sales price exceeds the inventory value
when control transfers to the customer.
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Marine Transportation
Our marine transportation business consists of revenues from the inland and offshore marine transportation of heavy
refined petroleum products, asphalt and crude oil, using our barges or vessels. This revenue is recognized over the passage of
time of individual trips as determined on an individual contract basis. Revenue from these contracts is typically based on a set
day-rate or a set fee per cargo movement. The costs of fuel and certain other operational costs may be directly reimbursed by
the customer, if stipulated in the contract.
Our performance obligation consists of providing transportation services using our vessels for a single day either under
a term or spot based contract. The transaction price is usually fixed per the contract either as a day rate or as a lump sum to be
allocated over the days required to complete the service. Revenue is recognizable as the transportation service utilizing our
vessels occurs, as the customer simultaneously receives and consumes these services as they are provided. If provided in the
contract, certain items such as fuel or operational costs can be rebilled to the customer in the same period in which the costs are
incurred. In the event the timing of a trip to provide our services crosses a reporting period under a lump sum fee contract, the
revenue earned is accrued based on the progress completed in the current period on the related performance obligation as we are
entitled to payment for each day. Customer invoicing occurs at the completion of a trip, or earlier at the customer’s request.
Product Sales
Sodium Minerals and Sulfur Services
Product sales in our sodium minerals and sulfur services segment primarily involve the sales of caustic soda, NaHS,
soda ash and other alkali products. As it relates to revenue recognition, these sales transactions contain a single performance
obligation, which is the delivery of the product to the customer at the agreed upon point of sale. For some transactions, control
of product transfers to the customer at the shipping point, but we are obligated to arrange for shipment of the product as
directed by the customer. Rather than treating these shipping activities as separate performance obligations, our policy is to
account for them as fulfillment costs in accordance with ASC 606.
The transaction price for these product sales are determined by specific contracts, typically at a fixed rate or based on a
market or indexed rate. This pricing is known, or is “fixed,” at the time of revenue recognition. Invoicing and related payment
terms are in accordance with industry standard or contract specification based on final pricing. The entirety of the transaction
price is allocated to the performance obligation, which is delivery of the product at the agreed upon point of sale. As this type of
revenue is earned at a point in time, there is no allocation of transaction price to future performance obligations.
Onshore Facilities and Transportation
Product sales in our onshore facilities and transportation segment primarily involve the sales of crude oil and
petroleum products. These contracts contain a single performance obligation, which is the delivery of the product to the
customer at a specified location. These contracts are settled on a monthly basis for term contracts, or on a spot basis. Invoicing
and related payment terms are in accordance with industry standard or contract specification based on final pricing.
Pricing is designated within the contracts and is either fixed, index-based or formulaic, utilizing an average price for
the month or for a specified range of days, regardless of when delivery occurs. In either case, pricing is known at the time of
invoicing. The entirety of the consideration is allocated to a single performance obligation, which is delivery of the product to a
specified location. As this type of revenue is earned at a point in time, there is no allocation of transaction price to future
performance obligations.
Refinery Services
Our refinery services business primarily provides sulfur extraction services to refiners’ high sulfur (or “sour”) gas
streams that the refineries have generated from crude oil processing operations. Our process applies our proprietary
technology, which uses caustic soda to act as a scrubbing agent at a prescribed temperature and pressure to remove sulfur. The
technology returns a clean (sulfur-free) hydrocarbon stream to the refinery for further processing into refined products, and
simultaneously produces NaHS. Units of NaHS are produced ratably as a gas stream is processed. We obtain control and
ownership of the NaHS immediately upon production, which constitutes the sole consideration that we receive for our sulfur
removal services. We later market this product to third parties as part of our product sales, as described above. As part of some
of our arrangements, we pay a refinery access fee (“RSA fee”) for any benefits received by virtue of our plant’s proximity to
the customer’s refinery. Our RSA fee is recorded as a reduction of revenue.
Providing sulfur removal services is the singular performance obligation in our refinery service agreements. As our
customers simultaneously receive and consume the refinery service benefits, control is transferred and revenue is recognized
over time based on the extent of progress towards completion of the performance obligations. We use units of NaHS produced
during a period to measure progress as the amount we receive corresponds directly with the efforts to provide our services
completed to date. The transaction price for each performance obligation is determined using the fair value of a unit of NaHS
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on the contract inception date for each refinery services agreement. Accordingly, we record the value of NaHS received as non-
cash consideration in inventory until it is subsequently sold to our customers (see Product Sales, above).
Contract Assets and Liabilities
The table below depicts our contract asset and liability balances at December 31, 2021 and December 31, 2020:
Contract Assets
Contract Liabilities
Current Assets-
Other
Other Assets
Accrued Liabilities
Other Long-Term
Liabilities
Balance at December 31, 2020
$
Balance at December 31, 2021
36,500 $
13,563
12,065 $
—
2,988 $
2,619
19,834
19,028
$3.0 million and $3.2 million that were previously classified as a contract liability at the beginning of the period were
recognized as revenue for the years ended December 31, 2021 and 2020, respectively. Additionally, we recognized $4.1 million
of revenue during 2021 as a result of a contract modification related to one of our offshore pipeline transportation contracts.
Transaction Price Allocations to Remaining Performance Obligations
We are required to disclose the amount of our transaction prices that are allocated to unsatisfied performance
obligations as of December 31, 2021. However, ASC 606 provides the following practical expedients and exemptions that we
utilized:
1) Performance obligations that are part of a contract with an expected duration of one year or less;
2) Revenue recognized from the satisfaction of performance obligations where we have a right to consideration in an
amount that corresponds directly with the value provided to customers; and
3) Contracts that contain variable consideration, such as index-based pricing or variable volumes, that is allocated entirely
to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service
that is part of a series.
We apply these practical expedients and exemptions to our revenue streams recognized over time. The majority of our
contracts qualify for one of these expedients or exemptions. After considering these practical expedients and identifying the
remaining contract types that involve revenue recognition over a long-term period and include long term fixed consideration
(adjusted for indexing as required), we determined our allocations of transaction price that relate to unsatisfied performance
obligations. As it relates to our tiered pricing offshore transportation contracts, we provide firm capacity for both fixed and
variable consideration over a long-term period. Therefore, we have allocated the remaining contract value (as estimated and
discussed above) to future periods. In our onshore facilities and transportation segment, we have certain contractual
arrangements in which we receive fixed minimum payments for our obligation to provide minimum capacity on our pipelines
and related assets.
The following chart depicts how we expect to recognize revenues for future periods related to these contracts:
2022
2023
2024
2025
2026
Thereafter
Total
Offshore Pipeline
Transportation
Onshore Facilities and
Transportation
$
69,143
$
4,698
65,645
59,034
62,699
44,691
57,612
—
—
—
—
—
$
358,824
$
4,698
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4. Lease Accounting
Lessee Arrangements
We lease a variety of transportation equipment (including trucks, trailers, and railcars), terminals, land and facilities,
and office space and equipment. Lease terms vary and can range from short term (under 12 months) to long term (greater than
12 months). A majority of our leases contain options to extend the life of the lease at our sole discretion. We considered these
options when determining the lease terms used to derive our right of use asset and associated lease liability. Leases with a term
of less than 12 months are not recorded on our Consolidated Balance Sheets and we recognize lease expense for these leases on
a straight-line basis over the lease term.
Certain lease agreements include lease and non-lease components. We have elected to combine lease and non-lease
components for all of our underlying assets for the purpose of deriving our right of use asset and lease liability. Additionally,
certain lease payments are driven by variable factors, such as plant production or indexing rates. Variable costs are expensed as
incurred and are not included in our determination for our lease liability and right of use asset.
As a lessee, we do not have any finance leases and none of our leases contain material residual value guarantees or
material restrictive covenants. In addition, most of our leases do not provide an implicit rate, and as such, we determined our
incremental borrowing rate based on the information available at the inception of the lease in determining the present value of
lease payments.
Our lease portfolio consists of operating leases within three major categories: Transportation Equipment, Office Space
and Equipment, and Facilities and Equipment. These values are recorded within Right of Use Assets, net on the Consolidated
Balance Sheets. Current and non-current lease liabilities are recorded within Accrued liabilities and Other long-term liabilities,
respectively, on the Consolidated Balance Sheets. Refer to the table below for our lease balances as of December 31, 2021 and
December 31, 2020.
Leases
Assets
Total Right of Use Assets, net
Liabilities
Current
Non-Current
Total Lease Liability
Classification
Financial Statement Caption
December 31,
2021
December 31,
2020
Transportation
Equipment
Office Space &
Equipment
Facilities and
Equipment
Right of Use Assets, net
Right of Use Assets, net
Right of Use Assets, net
$
79,784 $
88,038
5,981
7,489
55,031
58,398
$
140,796 $
153,925
Accrued liabilities
Other long-term liabilities
19,966
121,854
141,820 $
23,348
131,623
154,971
$
Our “Right of Use Assets, net” balance includes our unamortized initial direct costs associated with certain of our
transportation equipment leases. Additionally, it includes our unamortized prepaid rents, our deferred rents, and our previously
classified intangible asset associated with a favorable lease. Our lease liability includes our cease-use provision for railcars no
longer in use.
We recorded total operating lease expense of $18.4 million, $30.2 million, and $27.2 million for the years ended
December 31, 2021, 2020, and 2019, respectively. The total operating lease expense is net of the variable railcar mileage credits
we receive in our Alkali Business of $20.8 million, $18.4 million, and $24.8 million for the years ended December 31, 2021,
2020, and 2019, respectively. The total operating cost includes the amounts associated with our existing lease liabilities, along
with both short term and variable lease costs incurred during the period which are not significant to the operating lease cost
individually, or in the aggregate.
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The following table presents the maturities of our operating lease liabilities as of December 31, 2021 on an
undiscounted cash flow basis reconciled to the present value recorded on our Consolidated Balance Sheets:
Maturity of Lease Liabilities
Transportation
Equipment
Office Space and
Equipment
Facilities and
Equipment
Operating Leases
2022
2023
2024
2025
2026
Thereafter
Total Lease Payments
Less: Interest
Present value of operating lease liabilities
$
$
20,401 $
18,778
17,716
13,983
9,846
14,113
94,837
(15,121)
79,716 $
2,922 $
1,125
995
776
664
432
6,914
(759)
6,155 $
5,604 $
5,529
5,005
5,041
5,092
120,485
146,756
(90,807)
55,949 $
28,927
25,432
23,716
19,800
15,602
135,030
248,507
(106,687)
141,820
The following table presents the weighted average remaining terms and discount rates related to our right of use assets:
Lease Term and Discount Rate
Weighted-average remaining lease term
Weighted-average discount rate
December 31, 2021
December 31, 2020
13.48 years
7.69%
13.10 years
7.68%
The following table provides information regarding the cash paid and right of use assets obtained related to our
operating leases:
Cash Flows Information
Cash paid for amounts included in the measurement of lease liabilities
$
Leased assets obtained in exchange for new operating lease liabilities
December 31, 2021
December 31, 2020
33,145 $
8,296
41,308
8,035
Lessor Arrangements
We have certain contracts discussed below in which we act as a lessor. We also, from time to time, sublease certain of
our transportation and facilities equipment to third parties.
Operating Leases
During the years ended December 31, 2021, 2020, and 2019, we acted as a lessor in our revenue contracts associated
with the M/T American Phoenix, included in our marine transportation segment. During the years ended December 31, 2020,
and 2019, we acted as a lessor in our Free State pipeline system, included in our onshore facilities and transportation segment.
Revenues associated with these contracts were recorded within their respective segment's revenue in the Consolidated
Statements of Operations. Our lease revenues for these arrangements (inclusive of fixed and variable consideration) are
reflected in the table below for the years ended December 31, 2021, 2020, and 2019, respectively:
2021
Year Ended
December 31,
2020
M/T American Phoenix
Free State Pipeline(1)
$
15,031 $
—
24,116
5,234
2019
27,010
6,090
(1) We sold the Free State pipeline to a subsidiary of Denbury Inc. on October 30, 2020. The 2020 revenues presented above reflect operations through October
29, 2020 as that was the last date the asset operated under our ownership.
Direct Finance Lease
We formerly held a direct finance lease of the Northeast Jackson Dome (“NEJD”) Pipeline. Under the terms of the
agreement, we were paid a quarterly payment, which commenced on August 3, 2008. These payments were fixed at
approximately $5.2 million per quarter during the lease term at an interest rate of 10.25%. At the end of the lease term in 2028,
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we would convey all of our interest in the NEJD Pipeline to the lessee for a nominal payment. During the third quarter of 2020,
our customer, a subsidiary of Denbury, Inc., defaulted under the agreement and we exercised a letter of credit we had issued to
us as beneficiary and we collected approximately $41 million in accelerated principal payments during 2020. On October 30,
2020 we executed an agreement with our customer to accelerate the remaining principal payments on the NEJD direct financing
lease. As of December 31, 2020, we had an outstanding receivable (included within “Accounts receivable- trade, net” on the
Consolidated Balance Sheets) of $70.0 million from Denbury for the remaining payments per the agreement, which was fully
collected during 2021. Additionally as part of this agreement, we transferred the ownership of all of our CO2 assets, including
the Free State pipeline system, to Denbury.
5. Receivables
Accounts receivable – trade, net consisted of the following:
Accounts receivable - trade
Allowance for credit losses
Accounts receivable - trade, net
December 31,
2021
2020
$
$
405,159 $
398,723
(4,825)
(6,258)
400,334 $
392,465
The following table presents the activity of our allowance for credit losses for the periods indicated:
Balance at beginning of period
Charges to (recoveries of) costs and expenses, net
Amounts written off
Balance at end of period
6. Inventories
The major components of inventories were as follows:
Petroleum products
Crude oil
Caustic soda
NaHS
Raw materials - Alkali Operations
Work-in-process - Alkali Operations
Finished goods, net - Alkali Operations
Materials and supplies, net - Alkali Operations
Total
2021
December 31,
2020
$
$
6,258 $
(902)
(531)
4,825 $
1,062 $
5,504
(308)
6,258 $
2019
7,393
(5,572)
(759)
1,062
December 31,
2021
2020
$
998 $
11,834
5,690
17,040
7,599
7,496
13,681
13,620
$
77,958 $
5,840
37,661
5,167
9,101
7,120
9,355
13,002
12,631
99,877
Inventories are valued at the lower of cost or net realizable value. The net realizable value of inventories were below
cost by $2.0 million as of December 31, 2021, which triggered a reduction of the value of inventory in our Consolidated
Financial Statements by this amount. We recorded $5.0 million in inventory reduction adjustments as of December 31, 2020.
Materials and supplies include chemicals, maintenance supplies, and spare parts which will be consumed in the mining
of trona ore and production of soda ash processes.
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7. Fixed Assets, Mineral Leaseholds and Asset Retirement Obligations
Fixed Assets
Fixed assets consisted of the following:
Crude oil and natural gas pipelines and related assets
Alkali facilities, machinery, and equipment
Onshore facilities, machinery, and equipment
Transportation equipment
Marine vessels
Land, buildings and improvements
Office equipment, furniture and fixtures
Construction in progress
Other
Fixed assets, at cost
Less: Accumulated depreciation
Net fixed assets
Mineral Leaseholds
December 31,
2021
2020
$
2,839,443 $
2,811,030
670,880
269,245
21,106
1,018,284
227,540
23,965
350,137
43,440
622,598
267,810
19,470
998,553
219,382
22,001
170,740
41,891
5,464,040
5,173,475
(1,551,855)
(1,322,141)
$
3,912,185 $
3,851,334
Our Mineral Leaseholds, relating to our Alkali Business, consist of the following:
Mineral leaseholds
Less: Accumulated depletion
Mineral leaseholds, net
December 31, 2021 December 31, 2020
$
$
566,019 $
566,019
(17,014)
(13,444)
549,005 $
552,575
Depreciation expense was $295.4 million, $276.4 million and $295.6 million for the years ended December 31, 2021,
2020, and 2019, respectively. Depletion expense was $3.6 million, $3.2 million, and $4.7 million for the years ended December
31, 2021, 2020 and 2019, respectively.
Asset Sales and Divestitures
On October 30, 2020, we reached an agreement with a subsidiary of Denbury Inc. to transfer to it the ownership of our
remaining CO2 assets, including the NEJD and Free State pipelines, included within our onshore facilities and transportation
segment. As a part of the agreement, we received 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 $70.0 million was paid in equal installments in
each quarter during 2021. We recorded a loss of $22.0 million, which represents the difference between the proceeds and the
net book value of the assets transferred, and is recorded within “Loss on sale of assets” on the Consolidated Statement of
Operations for the year ended December 31, 2020.
Impairment Expense
During the second quarter of 2020, due to the challenging economic environment from the decline in commodity
prices (including the collapse in the differential of Western Canadian Select to the Gulf Coast) and Covid-19, crude-by-rail
transportation became uneconomic for producers and the demand and outlook for our rail logistics assets declined. Due to these
factors, we identified a triggering event that required us to perform an impairment test. For our recoverability test, we utilized
management's estimates, including current contractual commitments, for our future cash inflows, and our costs and expenses
were determined based on the estimated fixed and variable requirements to operate and maintain the related assets. As our rail
logistics asset groups did not pass the initial recoverability assessment, we subsequently performed a fair value calculation
using a discounted cash flow model under the income approach. As a result of this test, we recognized impairment expense of
$277.5 million as of December 31, 2020 associated with the rail logistics assets in our onshore facilities and transportation
segment, as the carrying value of our assets exceeded the estimated realizable value. The impairment expense included
$272.7 million of net fixed assets and $4.8 million of right of use assets, net on the Consolidated Balance Sheets. The fair value
estimates used in the long-lived asset test were primarily based on level 3 inputs of the fair value hierarchy.
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In addition to this, we recognized impairment expense of $3.3 million during the third quarter of 2020 primarily
associated with the full write-down of a non-core gas platform in our offshore transportation segment due to it not having a
future use for our operations.
Asset Retirement Obligations
We record AROs in connection with legal requirements to perform specified retirement activities under contractual
arrangements and/or governmental regulations. For any AROs acquired, we record AROs based on the fair value measurement
assigned during the preliminary purchase price allocation.
A reconciliation of our liability for asset retirement obligations is as follows:
December 31, 2019
Accretion expense
Revisions in timing and estimated costs of AROs
Settlements
December 31, 2020
Accretion expense
Revisions in timing and estimated costs of AROs
Acquisitions
Settlements
December 31, 2021
$
175,081
9,131
5,792
(13,152)
176,852
10,038
35,735
3,008
(4,727)
$
220,906
At December 31, 2021 and December 31, 2020, $36.3 million and $14.7 million are included as current in “Accrued
liabilities” on our Consolidated Balance Sheets, respectively. The remainder of the ARO liability at each period is included in
“Other long-term liabilities” on our Consolidated Balance Sheets. Revisions in timing and estimated costs during 2021 and
2020 are primarily attributable to the accelerated timing and revised costs associated with the abandonment of certain of our
non-core offshore gas assets in the Gulf of Mexico. Such revisions take into account several factors, including changes to legal
or regulatory requirements, changes in our estimated useful lives of the associated asset, and the timing and method of
abandonment. As there are significant judgements involved in deriving our estimates, actual costs, including the scope of work
once it is approved by the relative regulatory agency or contracted party, may differ from our estimates.
With respect to our AROs, the following table presents our forecast of accretion expense for the periods indicated:
2022
2023
2024
2025
2026
$
$
$
$
$
12,648
10,583
9,767
10,469
8,216
Certain of our unconsolidated affiliates have AROs recorded at December 31, 2021 and 2020 relating to contractual
agreements and regulatory requirements. In addition, certain entities that we consolidate have non-controlling interest owners
that are responsible for their representative share of future costs of the related ARO liability. These amounts are immaterial to
our Consolidated Financial Statements.
8. Equity Investees
We account for our ownership in our joint ventures under the equity method of accounting (see Note 2 for a
description of these investments). The price we pay to acquire an ownership interest in a company may exceed or be less than
the underlying book value of the capital accounts we acquire. At December 31, 2021 and 2020, the unamortized differences in
carrying value totaled $319.9 million and $335.4 million, respectively. We amortize the differences in carrying value as a
change in equity earnings.
The following table presents information included in our Consolidated Financial Statements related to our equity
investees:
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Genesis’ share of operating earnings
Amortization of differences attributable to Genesis' carrying value of equity
investments
Net equity in earnings
Distributions received
Year Ended December 31,
2021
2020
2019
73,389 $
79,510 $
71,975
(15,491)
(15,491)
(15,491)
57,898 $
84,106 $
64,019 $
81,061 $
56,484
77,331
$
$
$
The following tables present the combined balance sheet information for the last two years and statements of
operations data for the last three years for our equity investees (on a 100% basis):
BALANCE SHEET DATA:
Assets
Current assets
Fixed assets, net
Other assets
Total assets
Liabilities and equity
Current liabilities
Other liabilities
Equity
December 31,
2021
2020
$
33,994 $
284,265
21,327
42,565
299,315
25,654
339,586 $
367,534
$
$
15,457 $
237,948
86,181
13,411
248,857
105,266
367,534
Total liabilities and equity
$
339,586 $
STATEMENTS OF OPERATIONS DATA:
Revenues
Operating Income
Net Income
Poseidon's revolving credit facility
Year Ended December 31,
2021
2020
2019
$
$
$
203,835 $
214,687 $
143,506 $
153,640 $
138,783 $
147,560 $
209,674
155,920
139,436
Borrowings under Poseidon’s revolving credit facility, which was amended and restated in March 2019, are primarily
used to fund spending on capital projects. The March 2019 credit facility is non-recourse to Poseidon’s owners and secured by
its assets. The March 2019 credit facility contains customary covenants such as restrictions on debt levels, liens, guarantees,
mergers, sale of assets and distributions to owners. A breach of any of these covenants could result in acceleration of the
maturity date of Poseidon’s debt. Poseidon was in compliance with the terms of its credit agreement for all periods presented in
these Consolidated Financial Statements.
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9. Intangible Assets, Goodwill and Other Assets
Intangible Assets
The following table reflects the components of intangible assets being amortized at December 31, 2021 and 2020:
December 31, 2021
December 31, 2020
Marine contract intangibles
Offshore pipeline contract intangibles
Other
Total
Weighted
Amortization
Period in Years
Gross
Carrying
Amount
Accumulated
Amortization
Carrying
Value
Gross
Carrying
Amount
Accumulated
Amortization
Carrying
Value
20
19
9
$
800 $
607 $
193 $
800 $
571 $
229
158,101
37,933
53,394
104,707
158,101
45,073
113,028
15,770
22,163
29,244
13,759
15,485
$ 196,834 $ 69,771 $ 127,063 $ 188,145 $ 59,403 $ 128,742
The offshore pipeline contract intangibles relate to customer contracts surrounding certain transportation agreements
with producers in the Lucius production area in Southeast Keathley Canyon, which support our SEKCO pipeline.
We are recording amortization of our intangible assets based on the period over which the asset is expected to
contribute to our future cash flows. All of our current intangible assets are being amortized on a straight-line basis.
Amortization expense on intangible assets was $10.3 million, $15.5 million and $18.7 million for the years ended December 31,
2021, 2020 and 2019, respectively. The decline in amortization expense during 2021 was primarily attributable to our contract
intangible associated with the M/T American Phoenix becoming fully amortized at September 30, 2020.
The following table reflects our estimated amortization expense for each of the five subsequent fiscal years:
2022
2023
2024
2025
2026
Marine contract intangibles
$
35 $
34 $
33 $
32 $
8,321
3,414
8,321
3,147
8,321
2,783
8,321
2,560
$
11,770 $
11,502 $
11,137 $
10,913 $
10,612
30
8,321
2,261
Offshore pipeline contract intangibles
Other
Total
Goodwill
The carrying amount of goodwill in our sodium minerals and sulfur services segment was $301.9 million at December
31, 2021 and 2020. We have not recognized any impairment losses related to goodwill for any of the periods presented.
Other Assets
Other assets consisted of the following:
Deferred marine charges, net (1)
Long-term contract assets (2)
Unamortized debt issuance costs on Revolving Loan
Other deferred costs
Other assets, net of amortization
December 31,
2021
2020
$
19,930 $
—
4,736
13,593
20,714
12,065
5,842
7,226
$
38,259 $
45,847
(1) See discussion of deferred charges on marine transportation assets in the Summary of Accounting Policies (Note 2).
(2) See Revenue Recognition (Note 3) for discussion on the circumstances that result in the recognition of contract assets.
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10. Debt
At December 31, 2021 and 2020, our obligations under debt arrangements consisted of the following:
December 31, 2021
December 31, 2020
Unamortized
Premium and
Debt
Issuance
Costs
Principal
Net Value
Principal
Unamortized
Debt
Issuance
Costs
Net Value
Senior secured credit facility-Revolving Loan(1) $ 49,000 $
6.000% senior unsecured notes due 2023
—
— $ 49,000 $ 643,700 $
— $ 643,700
—
—
80,859
504
80,355
5.625% senior unsecured notes due 2024
6.500% senior unsecured notes due 2025
6.250% senior unsecured notes due 2026
8.000% senior unsecured notes due 2027
7.750% senior unsecured notes due 2028
341,135
534,834
359,799
1,000,000
720,975
2,106
339,029
341,135
2,963
338,172
4,452
530,382
534,834
5,639
529,195
3,410
356,389
359,799
4,189
355,610
6,592
993,408
750,000
13,022
736,978
9,678
711,297
720,975
11,269
709,706
Total long-term debt
$ 3,005,743 $ 26,238 $ 2,979,505 $ 3,431,302 $ 37,586 $ 3,393,716
(1) Unamortized debt issuance costs associated with our senior secured credit facility Revolving Loan, as defined below (included in Other
Assets, net of amortization on the Consolidated Balance Sheets) were $4.7 million and $5.8 million as of December 31, 2021 and
December 31, 2020, respectively.
Senior Secured Credit Facility
On April 8, 2021, we entered into the Fifth Amended and Restated Credit Agreement (our “new credit agreement”) to
replace our Fourth Amended and Restated Credit Agreement. Our new credit agreement provides for a $950 million senior
secured credit facility, comprised of a revolving loan facility with a borrowing capacity of $650 million (the “Revolving Loan”)
and a term loan facility of $300 million (the “Term Loan”). The senior secured credit facility matures on March 15, 2024,
subject to extension at our request for one additional year on up to two occasions and subject to certain conditions.
The key terms for rates under our senior secured credit facility, which are dependent on our leverage ratio (as defined
in the credit agreement), are as follows:
•
•
•
Revolving Loan: The interest rate on borrowings may be based on an alternate base rate or a Eurodollar rate, at our
option. The alternate base rate is equal to the sum of (a) the greatest of (i) the prime rate in effect on such day, (ii) the
federal funds effective rate in effect on such day plus 0.5% and (iii) the LIBOR rate or a one-month maturity on such
day plus 1% and (b) the applicable margin. The Eurodollar rate is equal to the sum of (a) the LIBOR rate for the
applicable interest period multiplied by the statutory reserve rate and (b) the applicable margin. The applicable margin
varies from 2.25% to 3.75% on Eurodollar borrowings and from 1.25% to 2.75% on alternate base rate borrowings,
depending on our leverage ratio. Our leverage ratio is recalculated quarterly and in connection with each material
acquisition. At December 31, 2021, the applicable margins on our borrowings were 2.75% for alternate base rate
borrowings and 3.75% for Eurodollar rate borrowings based on our leverage ratio.
Term Loan: The interest rate on borrowings may be based on an alternate base rate or a Eurodollar rate, at our option.
The alternate base rate and the Eurodollar rates for our Term Loan are calculated consistent with our Revolving Loan
discussed above, and the applicable margin is fixed at 3.75% on Eurodollar borrowings and 2.75% on alternate base
rate borrowings for the Term Loan.
Letter of credit fees range from 2.25% to 3.75% based on our leverage ratio as computed under the senior secured
credit facility. The rate can fluctuate quarterly. At December 31, 2021, our letter of credit rate was 3.75%.
• We pay a commitment fee on the unused portion of the Revolving Loan. The commitment fee on the unused
committed amount will range from 0.30% to 0.50% per annum depending on our leverage ratio. At December 31,
2021, our commitment fee rate on the unused committed amount was 0.50%.
• We have the ability to increase the aggregate size of the Revolving Loan by an additional $200 million subject to
lender consent and certain other customary conditions.
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At December 31, 2021, we had $49.0 million borrowed under our Revolving Loan, with $9.7 million of the borrowed
amount designated as a loan under the inventory sublimit. Our credit agreement allows up to $100 million of the capacity to be
used for letters of credit, of which $1.3 million was outstanding at December 31, 2021. Due to the revolving nature of loans
under our Revolving Loan, additional borrowings and periodic repayments and re-borrowings may be made until the maturity
date of March 15, 2024. The total amount available for borrowings under our senior secured credit facility at December 31,
2021 was $599.7 million, subject to compliance with our covenants. Our senior secured credit facility does not include a
“borrowing base” limitation except with respect to our inventory loans.
On November 17, 2021, we closed on the sale of a 36% minority equity interest in CHOPS for gross proceeds of
approximately $418 million. Proceeds from the sale, net of fees and expenses, were used to repay the full $300 million
outstanding under the Term Loan. We incurred a loss of approximately $2.3 million associated with the early extinguishment of
the Term Loan relating to the write-off of the related unamortized debt issuance costs, which is recorded as “Other expense,
net” in our Consolidated Statements of Operations for the year ended December 31, 2021.
Senior Unsecured Notes
On May 15, 2014, we issued $350 million in aggregate principal amount of 5.625% senior unsecured notes due June
15, 2024 (the “2024 Notes”). The 2024 Notes were sold at face value. Interest payments are due on June 15 and December 15
of each year with the initial interest payment due December 15, 2014. The 2024 Notes mature on June 15, 2024. The net
proceeds were used to repay borrowings under our senior secured credit facility and for general partnership purposes.
On May 21, 2015, we issued $400 million in aggregate principal amount of 6.00% senior unsecured notes due May 15,
2023 (the “2023 Notes”). Interest payments are due on May 15 and November 15 of each year with the initial interest payment
due November 15, 2015. The 2023 Notes mature on May 15, 2023. We used a portion of the proceeds from those notes to
effectively redeem all of our outstanding $350 million, 7.875% senior unsecured notes due 2018, using a combination of public
tender offer and our redemption rights relating to those notes. On December 17, 2020, $308.8 million of these notes were
validly tendered and repaid upon the issuance of our $750 million unsecured notes due in 2027 (the “2027 Notes”), as discussed
below. We incurred a loss of approximately $8.2 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 expense, net” in our
Consolidated Statement of Operations for the year ended December 31, 2020. On January 19, 2021 we redeemed the remaining
$80.9 million of our 2023 Notes in accordance with the terms and conditions of the indenture governing the 2023 Notes. We
incurred a loss of approximately $1.6 million relating to the extinguishment of our remaining 2023 senior unsecured notes,
inclusive of the redemption fee and the write-off of the related unamortized debt issuance costs, which is recorded in “Other
expense, net” in our Consolidated Statement of Operations for the year ended December 31, 2021.
On July 23, 2015, we issued $750 million in aggregate principal amount of 6.75% senior unsecured notes due
August 1, 2022 (the “2022 Notes”). Interest payments are due on February 1 and August 1 of each year with the initial interest
payment due February 1, 2016. The 2022 Notes mature on August 1, 2022. That issuance generated net proceeds of $728.6
million net of issuance discount and underwriting fees. The net proceeds were used to fund a portion of the purchase price for
our Enterprise acquisition. On January 16, 2020, $554.8 million of these notes were validly tendered and repaid upon the
issuance of our $750 million unsecured notes due in 2028 (the “2028 Notes”), as discussed below. On February 16, 2020, the
remaining $222.1 million of the remaining 2022 Notes were redeemed. 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 in “Other expense, net” in our Consolidated Statements of Operations for
the year ended December 31, 2020.
On August 14, 2017, we issued $550 million in aggregate principal amount of 6.50% senior unsecured notes due
October 1, 2025 (the “2025 Notes”). Interest payments are due April 1 and October 1 of each year with the initial interest
payment due April 1, 2018. That issuance generated net proceeds of $540.1 million, net of issuance costs incurred. The 2025
Notes mature on October 1, 2025. The net proceeds were used to fund a portion of the purchase price for our acquisition of our
Alkali Business.
On December 11, 2017, we issued $450 million in aggregate principal amount of 6.25% senior unsecured notes due
May 15, 2026 (the “2026 Notes”). Interest payments are due May 15 and November 15 of each year with the initial interest
payment due May 15, 2018. That issuance generated net proceeds of $441.8 million, net of issuance costs incurred. We used
$204.8 million of the net proceeds to redeem the portion of the 5.75% senior unsecured notes due February 15, 2021 (the “2021
Notes”) that were validly tendered and the remaining net proceeds to repay a portion of the borrowings outstanding under our
senior secured credit facility.
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On January 16, 2020, we issued $750 million in aggregate principal amount of our 7.75% 2028 Notes (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 $736.7 million net of issuance costs incurred. The 2028 Notes mature on
February 1, 2028. We used $554.8 million of the net proceeds to redeem the portion of the 6.75% 2022 Notes (including
principal, accrued interest and tender premium) that were validly tendered, and the remaining net proceeds were used to repay a
portion of the borrowings outstanding under our senior secured credit facility.
On December 17, 2020, we issued $750 million in aggregate principal amount of our 8.00% 2027 Notes due on
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. We used $316.5 million of the net proceeds to repay the portion of the 6.00% 2023 Notes (including principal,
accrued interest and tender premium) that were validly tendered, and the remaining proceeds at the time were used to repay a
portion of the borrowings outstanding under our senior secured credit facility.
On April 22, 2021, we completed our offering of an additional $250 million in aggregate principal amount of the 2027
Notes. The additional $250 million of notes have identical terms as (other than with respect to the issue price) and constitute
part of the same series of the 2027 Notes. The $250 million of the 2027 Notes were issued at a premium of 103.75% plus
accrued interest from December 17, 2020. We used the net proceeds from the offering for general partnership purposes,
including repaying a portion of the revolving borrowings outstanding under our senior secured credit facility.
We have the right to redeem each of our series of notes beginning on specified dates as summarized below, at a
premium to the face amount of such notes that varies based on the time remaining to maturity on such notes. Additionally, we
may redeem up to 35% of the principal amount of each of our series of notes with the proceeds from an equity offering of our
common units during certain periods. A summary of the applicable redemption periods is provided in the table below:
Redemption right beginning on
Redemption of up to 35% of the
principal amount of notes with
the proceeds of an equity
offering permitted prior to
2024 Notes
June 15,
2019
2025 Notes
October 1,
2020
2026 Notes
February 15,
2021
2027 Notes
January 15,
2024
2028 Notes
February 1,
2023
June 15,
2019
October 1,
2020
February 15,
2021
January 15,
2024
February 1,
2023
.
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 expense, net” in our
Consolidated Statement of Operations for the year ended December 31, 2020.
Guarantees of our 2024, 2025, 2026, 2027 and 2028 Notes will be released under certain circumstances, including (i)
in connection with any sale or other disposition of (a) all or substantially all of the properties or assets of a guarantor (including
by way of merger or consolidation) or (b) all of the capital stock of such guarantor, in each case, to a person that is not a
restricted subsidiary of the Partnership (ii) if the Partnership designates any restricted subsidiary that is a guarantor as an
unrestricted subsidiary, (iii) upon legal defeasance, covenant defeasance or satisfaction and discharge of the applicable
indenture, (iv) upon the liquidation or dissolution of such guarantor, or (v) at such time as such guarantor ceases to guarantee
any other indebtedness of either of the issuers and any other guarantor.
Our $3.0 billion aggregate principal amount of senior unsecured notes co-issued by Genesis Energy, L.P. and Genesis
Energy Finance Corporation are fully and unconditionally guaranteed jointly and severally by all of Genesis Energy, L.P.'s
current and future 100% owned domestic subsidiaries (the “Guarantor Subsidiaries”), except the subsidiaries that hold our
Alkali Business and certain other subsidiaries. The non-guarantor subsidiaries are owned by Genesis Crude Oil, L.P., a
Guarantor Subsidiary. The Guarantor Subsidiaries largely own the assets that we use to operate our business other than our
Alkali Business. As a general rule, the assets and credit of our unrestricted subsidiaries are not available to satisfy the debts of
Genesis Energy, L.P., Genesis Energy Finance Corporation or the Guarantor Subsidiaries, and the liabilities of our unrestricted
subsidiaries do not constitute obligations of Genesis Energy, L.P., Genesis Energy Finance Corporation or the Guarantor
Subsidiaries except, in the case of Genesis Alkali Holdings Company, LLC (“Alkali Holdings”) and Genesis Energy, L.P., to
the extent agreed to in the services agreement between Genesis Energy, L.P. and Alkali Holdings dated as of September 23,
2019 (the “Services Agreement”).
Covenants and Compliance
Our senior secured credit facility contains customary covenants (affirmative, negative and financial) that could limit
the manner in which we may conduct our business. As defined in our new credit agreement, we are required to meet three
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primary financial metrics—a maximum consolidated leverage ratio, a maximum consolidated senior secured leverage ratio and
a minimum consolidated interest coverage ratio. Our credit agreement provides for the temporary inclusion of certain pro forma
adjustments to the calculations of the required ratios following material transactions. In general, our consolidated leverage ratio
calculation compares our consolidated funded debt (including outstanding notes we have issued) to our Adjusted Consolidated
EBITDA (as defined and adjusted in accordance with the senior secured credit facility). Our consolidated senior secured
leverage ratio calculation compares our consolidated senior secured funded debt (including outstanding borrowings on the
senior secured credit facility) to our Adjusted Consolidated EBITDA (as defined and adjusted in accordance with the senior
secured credit facility), and our minimum consolidated interest coverage ratio compares our Adjusted Consolidated EBITDA
(as defined and adjusted in accordance with the senior secured credit facility) to our Consolidated interest expense (as defined
and adjusted in accordance with the senior secured credit facility). Under our new credit agreement, the permitted maximum
consolidated leverage ratio is 5.75x through March 31, 2022, and then 5.50x thereafter. The permitted maximum consolidated
senior secured leverage ratio is 2.50x, and the minimum consolidated interest coverage ratio is 2.50x for the full term of the
agreement.
In addition, our credit agreement and the indentures governing the senior notes contain cross-default provisions. Our
credit documents prohibit distributions on, or purchases or redemptions of, units if any default or event of default is continuing.
In addition, those agreements contain various covenants limiting our ability to, among other things:
•
•
•
•
incur indebtedness if certain financial ratios are not maintained;
grant liens;
engage in sale-leaseback transactions; and
sell substantially all of our assets or enter into a merger or consolidation.
A default under our credit documents would permit the lenders thereunder to accelerate the maturity of the outstanding
debt. As long as we are in compliance with our senior secured credit facility, our ability to make distributions of “available
cash” is not restricted. As of December 31, 2021, we were in compliance with the financial covenants contained in our senior
secured credit facility and indentures.
11. Partners’ Capital, Mezzanine Equity and Distributions
At December 31, 2021, our outstanding equity consisted of 122,539,221 Class A common units and 39,997 Class B
common units. The Class A units are traditional common units in us. The Class B units are identical to the Class A units and,
accordingly, have voting and distribution rights equivalent to those of the Class A units, and, in addition, the Class B units have
the right to elect all of our board of directors and are convertible into Class A units under certain circumstances, subject to
certain exceptions. At December 31, 2021, we had 25,336,778 Class A Convertible Preferred Units outstanding, which are
discussed below in further detail.
Distributions
Generally, we will distribute 100% of our available cash (as defined by our partnership agreement) within 45 days
after the end of each quarter to common unitholders of record. Available cash generally means, for each fiscal quarter, all cash
on hand at the end of the quarter:
•
•
less the amount of cash reserves that our general partner determines in its reasonable discretion is necessary or
appropriate to:
•
•
•
provide for the proper conduct of our business;
comply with applicable law, any of our debt instruments, or other agreements; or
provide funds for distributions to our common and preferred unitholders for any one or more of the next four
quarters;
plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital
borrowings. Working capital borrowings are generally borrowings that are made under our senior secured credit
facility and in all cases are used solely for working capital purposes or to pay distributions to partners.
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We paid the following cash distributions to common unitholders:
Distribution For
2019
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
2020
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
2021
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
Date Paid
Per Unit Amount
Total Amount
May 15, 2019 $
August 14, 2019 $
November 14, 2019 $
February 14, 2020 $
May 15, 2020 $
August 14, 2020 $
November 13, 2020 $
February 12, 2021 $
May 14, 2021 $
August 13, 2021 $
November 12, 2021 $
February 14, 2022 $
0.5500 $
0.5500 $
0.5500 $
0.5500 $
0.1500 $
0.1500 $
0.1500 $
0.1500 $
0.1500 $
0.1500 $
0.1500 $
0.1500 $
67,419
67,419
67,419
67,419
18,387
18,387
18,387
18,387
18,387
18,387
18,387
18,387
Equity Issuances and Contributions
Our partnership agreement authorizes our general partner to cause us to issue additional limited partner interests and
other equity securities, the proceeds from which could be used to provide additional funds for acquisitions or other needs. We
did not issue any common units during the periods presented.
Class A Convertible Preferred Units
On September 1, 2017, we sold $750 million of Class A Convertible Preferred Units (our “Class A Convertible
Preferred Units”) in a private placement, comprised of 22,249,494 units for a cash purchase price per unit of $33.71 (subject to
certain adjustments, the “Issue Price”) to two initial purchasers. Our general partner executed an amendment to our partnership
agreement in connection therewith, which, among other things, authorized and established the rights and preferences of our
Class A Convertible Preferred Units. Our Class A Convertible Preferred Units rank senior to all of our currently outstanding
classes or series of limited partner interests with respect to distribution and/or liquidation rights. Holders of our Class A
Convertible Preferred Units vote on an as-converted basis with holders of our common units and have certain class voting
rights, including with respect to any amendment to the partnership agreement that would adversely affect the rights, preferences
or privileges, or otherwise modify the terms, of those Class A Convertible Preferred Units.
Each of our Class A Convertible Preferred Units accumulate quarterly distribution amounts in arrears at an annual rate
of 8.75% (or $2.9496), yielding a quarterly rate of 2.1875% (or $0.7374), subject to certain adjustments. We elected to pay all
distributions from inception through March 1, 2019 with additional Class A Convertible Preferred Units. For the quarter ended
March 31, 2019, we paid a portion of our distribution in cash, and a portion in Class A Convertible Preferred Units. For each
quarter ending after March 1, 2019, we paid all distribution amounts in respect of our Class A Convertible Preferred Units in
cash.
From time to time after September 1, 2020, we will have the right to cause the conversion of all or a portion of
outstanding Class A Convertible Preferred Units into our common units, subject to certain conditions; provided, however, that
we will not be permitted to convert more than 7,416,498 of our Class A Convertible Preferred Units in any consecutive twelve-
month period. At any time after September 1, 2020, if we have fewer than 592,768 of our Class A Convertible Preferred Units
outstanding, we will have the right to convert each outstanding Class A Convertible Preferred Unit into our common units at a
conversion rate equal to the greater of (i) the then-applicable conversion rate and (ii) the quotient of (a) the Issue Price and (b)
95% of the volume-weighted average price of our common units for the 30-trading day period ending prior to the date that we
notify the holders of our outstanding Class A Convertible Preferred Units of such conversion.
Upon certain events involving certain changes of control in which more than 90% of the consideration payable to the
holders of our common units is payable in cash, our Class A Convertible Preferred Units will automatically convert into
common units at a conversion ratio equal to the greater of (a) the then applicable conversion rate and (b) the quotient of (i) the
product of (A) the sum of (1) the Issue Price and (2) any accrued and accumulated but unpaid distributions on our Class A
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Convertible Preferred Units, and (B) a premium factor (ranging from 115% to 101% depending on when such transaction
occurs) plus a prorated portion of unpaid partial distributions, and (ii) the volume weighted average price of the common units
for the 30 trading days prior to the execution of definitive documentation relating to such change of control.
In connection with other change of control events that do not meet the 90% cash consideration threshold described
above, each holder of our Class A Convertible Preferred Units may elect to (a) convert all of its Class A Convertible Preferred
Units into our common units at the then applicable conversion rate, (b) if we are not the surviving entity (or if we are the
surviving entity, but our common units will cease to be listed), require us to use commercially reasonable efforts to cause the
surviving entity in any such transaction to issue a substantially equivalent security (or if we are unable to cause such
substantially equivalent securities to be issued, to convert its Class A Convertible Preferred Units into common units in
accordance with clause (a) above or exchanged in accordance with clause (d) below or convert at a specified conversion rate),
(c) if we are the surviving entity, continue to hold our Class A Convertible Preferred Units or (d) require us to exchange our
Class A Convertible Preferred Units for cash or, if we so elect, our common units valued at 95% of the volume-weighted
average price of our common units for the 30 consecutive trading days ending on the fifth trading day immediately preceding
the closing date of such change of control, at a price per unit equal to the sum of (i) the product of (x) 101% and (y) the Issue
Price plus (ii) accrued and accumulated but unpaid distributions and (iii) a prorated portion of unpaid partial distributions.
For a period of 30 days following (i) September 1, 2022 and (ii) each subsequent anniversary thereof, the holders of
our Class A Convertible Preferred Units may make a one-time election to reset the quarterly distribution amount (a “Rate Reset
Election”) to a cash amount per preferred unit equal to the amount that would be payable per quarter if a preferred unit accrued
interest on the Issue Price at an annualized rate equal to three-month LIBOR plus 750 basis points; provided, however, that such
reset rate shall be equal to 10.75% if (i) such alternative rate is higher than the LIBOR-based rate and (ii) the then market price
for our common units is then less than 110% of the Issue Price. To become effective, the Rate Reset Election requires approval
of holders of at least a majority of our then outstanding Class A Convertible Preferred Units and such majority must include
each of our initial purchasers (or any affiliate to whom they have transferred their Class A Convertible Preferred Units) if such
initial purchaser (including its affiliates) holds at least 25% of the then outstanding Class A Convertible Preferred Units.
Upon the occurrence of a Rate Reset Election, we may redeem our Class A Convertible Preferred Units for cash, in
whole or in part (subject to certain minimum value limitations) for an amount per preferred unit equal to such preferred unit’s
liquidation value (equal to the Issue Price plus any accrued and accumulated but unpaid distributions, plus a prorated portion of
certain unpaid partial distributions in respect of the immediately preceding quarter and the current quarter) multiplied by (i)
110%, prior to September 1, 2024, and (ii) 105% thereafter. Each holder of our Class A Convertible Preferred Units may elect
to convert all or any portion of its Class A Convertible Preferred Units into common units initially on a one-for-one basis
(subject to customary adjustments and an adjustment for accrued and accumulated but unpaid distributions and limitations) at
any time after September 1, 2019 (or earlier upon a change of control, liquidation, dissolution or winding up), provided that any
conversion is for at least $50 million or such lesser amount if such conversion relates to all of a holder’s remaining Class A
Convertible Preferred Units or has otherwise been approved by us.
If we fail to pay in full any preferred unit distribution amount after March 1, 2019 in respect of any two quarters,
whether or not consecutive, then until we pay such distributions in full, we will not be permitted to (a) declare or make any
distributions (subject to a limited exceptions for pro rata distributions on our Class A Convertible Preferred Units and parity
securities), redemptions or repurchases of any of our limited partner interests that rank junior to or pari passu with our Class A
Convertible Preferred Units with respect to rights upon distribution and/or liquidation (including our common units), or
(b) issue any such junior or parity securities. If we fail to pay in full any preferred unit distribution after March 1, 2019 in
respect of any two quarters, whether or not consecutive, then the preferred unit distribution amount will be reset to a cash
amount per preferred unit equal to the amount that would be payable per quarter if a preferred unit accrued interest on the Issue
Price at an annualized rate equal to the then-current annualized distribution rate plus 200 basis points until such default is cured.
In addition to their right to veto a Rate Reset Election under certain circumstances, we have granted each initial
purchaser (including its applicable affiliate transferees) certain rights, including (i) the right to appoint an observer, who shall
have the right to attend our board meetings for so long as an initial purchaser (including its affiliates) owns at least $200 million
of our Class A Convertible Preferred Units; (ii) the right to purchase up to 50% of any parity securities on substantially the
same terms offered to other purchasers for so long as an initial purchaser (including its affiliates) owns at least 11,124,747 of
our Class A Convertible Preferred Units, and (iii) the right to appoint two directors to our general partner’s board of directors if
(and so long as) we fail to pay in full any three quarterly distribution amounts, whether or not consecutive, attributable to any
quarter ending after March 1, 2019.
The Rate Reset Election of these Class A Convertible Preferred Units represents an embedded derivative that must be
bifurcated from the related host contract and recorded at fair value on our Consolidated Balance Sheets. See further information
in Note 18. The Class A Convertible Preferred Units themselves are classified as mezzanine capital on our Consolidated
Balance Sheets.
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Accounting for the Class A Convertible Preferred Units
Our Class A Convertible Preferred Units are considered redeemable securities under GAAP due to the existence of
redemption provisions upon a deemed liquidation event which is outside of our control. Therefore, we present them as
temporary equity in the mezzanine section of the Consolidated Balance Sheets. The Class A Convertible Preferred Units have
been recorded at their issuance date fair value, net of issuance costs. Because our Class A Convertible Preferred Units are not
currently redeemable and we do not have plans or expect any events which constitute a change of control in our partnership
agreement, we present our Class A Convertible Preferred Units at their initial carrying amount. However, we would be
required to adjust that carrying amount if it becomes probable that we would be required to redeem our Class A Convertible
Preferred Units.
Preferred unit distributions are recognized on the date in which they are declared. paid-in-kind distributions were
declared and issued as follows:
Distribution Declared
2019
January 2019
April 2019
Date Issued
Number of Units
Total Amount
February 14, 2019
May 15, 2019
534,576 $
364,180 $
18,021
12,277
We paid the following cash distributions to our Class A Convertible Preferred unitholders:
Distribution For
2019
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
2020
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
2021
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
Date Paid
Per Unit
Amount
Total
Amount
May 15, 2019 $
August 14, 2019 $
November 14, 2019 $
February 14, 2020 $
May 15, 2020 $
August 14, 2020 $
November 13, 2020 $
February 12, 2021 $
May 14, 2021 $
August 13, 2021 $
November 12, 2021 $
February 14, 2022 $
0.2458 $
0.7374 $
0.7374 $
0.7374 $
0.7374 $
0.7374 $
0.7374 $
0.7374 $
0.7374 $
0.7374 $
0.7374 $
0.7374 $
6,138
18,684
18,684
18,684
18,684
18,684
18,684
18,684
18,684
18,684
18,684
18,684
There were 25,336,778 Class A Convertible Preferred Units outstanding as of December 31, 2021. All quarterly
distributions subsequent to the first quarter of 2019 have been paid in cash and as such there have been no changes to the
number of Class A Convertible Preferred Units outstanding since May 15, 2019.
Net income (loss) attributable to Genesis Energy, L.P. is reduced by Class A Convertible Preferred Unit distributions
that accumulated during the period. Net income (loss) attributable to Genesis Energy, L.P. was reduced by $74.7 million,
$74.7 million, and $74.5 million for the years ended December 31, 2021, 2020 and 2019, respectively, as a result of
distributions that accumulated during the period.
Redeemable Noncontrolling Interests
On September 23, 2019, we, through a subsidiary, Genesis Alkali Holdings Company, LLC (“Alkali Holdings”), the
entity that holds our trona and trona-based exploring, mining, processing, producing, marketing, and selling business, including
its Granger facility near Green River, Wyoming, entered into an amended and restated Limited Liability Company Agreement
of Alkali Holdings (the “LLC Agreement”) and a Securities Purchase Agreement (the “Securities Purchase Agreement”)
whereby certain investment fund entities affiliated with Blackstone Alternative Credit Advisors LP, formerly known as “GSO
Capital Partners LP” (collectively, “BXC”) purchased $55,000,000 of preferred units (or 55,000 preferred units) and committed
to purchase, during a three-year commitment period, up to a total of $350,000,000 of preferred units (or 350,000 preferred
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units) in Alkali Holdings. Alkali Holdings will use the net proceeds from the preferred units to fund a portion of the anticipated
cost of the Granger Optimization Project. On April 14, 2020, we entered into an amendment to our agreements with BXC to,
among other things, extend the construction timeline of the Granger Optimization Project by one year, which we currently
anticipate completing in the second half of 2023. In consideration for the amendment, we issued 1,750 Alkali Holdings
preferred units to BXC, which was accounted for as issuance costs. As part of the amendment, the commitment period was
increased to four years, and the total commitment of BXC was increased to, subject to compliance with the covenants contained
in the agreements with BXC, up to $351,750,000 preferred units (or 351,750 preferred units) in Alkali Holdings. As of
December 31, 2021, there are 246,394 Alkali Holdings preferred units outstanding.
BXC has the right to a quarterly distribution equal to 10% per annum on the liquidation preference of each preferred
unit. The liquidation preference is defined as one thousand dollars per preferred unit, plus any accrued and unpaid distributions
(including as a result of any distributions paid-in-kind). Distributions are payable quarterly within 45 days after the end of the
fiscal quarter. Distributions may be paid in-kind in lieu of cash distributions during the first 48 months following the September
23, 2019 initial closing date. Subsequent to the PIK period, all distributions must be paid in cash. In addition to the quarterly
distributions paid to BXC, Alkali Holdings will distribute all of its distributable cash to the Partnership each quarter, which is
equal to all cash and cash equivalents in the operating accounts of Alkali Holdings less cash reserves and a minimum $5 million
cash balance to be maintained for working capital needs.
From time to time after we have drawn at least 251,750,000, we have the option to redeem the outstanding preferred
units in whole for cash at a price equal to the initial $1,000 per preferred unit purchase price, plus no less than the greater of a
predetermined fixed internal rate of return amount or a multiple of invested capital metric, net of cash distributions paid to date
(“Base Preferred Return”). Additionally, if all outstanding preferred units are being redeemed, we have not drawn at least
251,750,000, and BXC is not a “defaulting member” under the LLC Agreement, the Sponsor has the right to a make-whole
amount on the number of undrawn preferred units.
BXC is obligated to purchase a minimum of 251,750,000 of preferred units unless certain customary closing
conditions are not satisfied, including the existence of a triggering event or a material uncured breach of the Securities Purchase
Agreement by Alkali Holdings. A triggering event would occur if Alkali Holdings fails to pay cash distributions subsequent to
the paid-in-kind period, fails to redeem preferred units when required to by a change of control event, or if any preferred units
remain outstanding on the six and a half year anniversary date, amongst other events. The preferred units must be redeemed, in
whole or in part, following certain change of control events, fundamental changes, or the liquidation, winding up, or dissolution
of Alkali Holdings and, as applicable, the Partnership. If such an event were to occur, the preferred units would rank senior to
Alkali Holdings common units and any class or series of equity of Alkali Holdings established after the issuance of the
preferred units.
At any time following the six and a half year anniversary of the Securities Purchase Agreement, or following the
occurrence of certain triggering events, if the preferred units issued and outstanding have not been redeemed in full for cash,
BXC has the right to gain control of the board of Alkali Holdings and effectuate a monetization event using its reasonable good
faith efforts to maximize the consideration received to the holders of our common units, including the sale of Alkali Holdings
(including all of its equity or assets and all of its equity in its subsidiaries), the proceeds of which would first be used to redeem
the preferred units at the Base Preferred Return prior to any distribution to us.
Pursuant to the LLC Agreement, the Board of Managers (the “Board”) for Alkali Holdings will consist of 5 managers,
including 3 designated by the Partnership, 1 designated by BXC, and 1 independent manager. The independent manager is
entitled to only attend Board meetings if the Board is required to vote on matters related to a bankruptcy of Alkali Holdings,
and is permitted to only vote on such matters.
See Item 7 for additional information regarding our non-Guarantor subsidiaries.
Accounting for Redeemable Noncontrolling Interests
Classification
The preferred units issued and outstanding are accounted for as a redeemable noncontrolling interest in the mezzanine
section on our Consolidated Balance Sheets due to the redemption features for a change of control.
Initial and Subsequent Measurement
We recorded the preferred units at their issuance date fair value, net of issuance costs. The fair value as of
December 31, 2021 represents the carrying amount based on the issued and outstanding preferred units most probable
redemption event on the six and a half year anniversary of the closing, which is the predetermined internal rate of return
measure accreted using the effective interest method to the redemption value as of the reporting date. Net Loss Attributable to
Genesis Energy, L.P. for the year ended December 31, 2021 includes $25.4 million of adjustments, of which $21.3 million was
allocated to the distribution paid in-kind on the outstanding preferred units and $4.1 million was attributable to redemption
accretion value adjustments. Net Loss Attributable to Genesis Energy, L.P. for the year ended December 31, 2020 includes
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$16.1 million of adjustments, of which $13.8 million was allocated to the distribution paid in-kind on the outstanding preferred
units and $2.3 million was attributable to redemption accretion value adjustments. Net Income Attributable to Genesis Energy,
L.P. for the year ended December 31, 2019 includes approximately $2.3 million of adjustments, of which $1.8 million was
allocated to the distribution paid in-kind on the outstanding preferred units and $0.5 million was attributable to redemption
accretion value adjustments. We elected to pay distributions for the periods ended December 31, 2021, December 31, 2020 and
December 31, 2019 in-kind to our Alkali Holdings preferred unitholders. The unitholders liquidation preference is increased by
new issuances and PIK distributions and is reduced by tax distributions paid to the unitholders, which are required to be paid by
us to fulfill the income tax liabilities of each holder of Alkali Holdings preferred units. As of December 31, 2021, there are
246,394 Alkali Holdings preferred units outstanding.
As of the reporting date, there are no triggering, change of control, early redemption or monetization events that are
probable that would require us to revalue the preferred units.
If the preferred units were redeemed on the reporting date of December 31, 2021, the redemption amount would be
equal to $289.9 million, which would be the multiple of invested capital metric applied to the preferred units outstanding plus
the make-whole amount on the undrawn minimum preferred units.
The following table shows the change in our redeemable noncontrolling interests from initial measurement at
September 23, 2019 to December 31, 2021:
Issuance of Preferred Units
Issuance costs
Balance as of September 23, 2019
Issuance of preferred units, net of issuance costs
Distribution paid-in-kind
Redemption accretion
Balance as of December 31, 2019
Issuance of preferred units, net of issuance costs(1)
Distribution paid-in-kind
Redemption accretion
Tax distributions
Balance as of December 31, 2020
Issuance of preferred units, net of issuance costs(1)
Distribution paid-in-kind
Redemption accretion
Tax distributions
Balance as of December 31, 2021
$
$
$
$
$
55,000
(5,600)
49,400
73,500
1,750
483
125,133
9,311
13,811
2,302
(9,363)
141,194
103,042
21,291
4,107
(10,066)
259,568
(1) We issued 10,145 and 9,499 Alkali Holdings preferred units to BXC to satisfy the company's obligation to pay tax
distributions during 2021 and 2020, respectively.
Noncontrolling Interests
On November 17, 2021, we, through a subsidiary, sold 36% of the membership interests in CHOPS for proceeds of
approximately $418 million. We retained 64% of the membership interests in CHOPS and remain the operator of the CHOPS
pipeline and associated assets. We also own an 80% membership interest in Independence Hub, LLC, which owns an offshore
hub platform. For financial reporting purposes, the assets and liabilities of these entities are consolidated with those of our own,
with any third party or affiliate interest in our Consolidated Balance Sheets amounts shown as noncontrolling interests in
equity.
12. Net Income (Loss) Per Common Unit
Basic net income (loss) per common unit is computed by dividing Net Income (Loss) Attributable to Genesis Energy,
L.P., after considering income attributable to our Class A preferred unitholders, by the weighted average number of common
units outstanding.
The dilutive effect of the Class A Convertible Preferred Units is calculated using the if-converted method. Under the
if-converted method, the Class A Convertible Preferred Units are assumed to be converted at the beginning of the period
(beginning with their respective issuance date), and the resulting common units are included in the denominator of the diluted
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net income per common unit calculation for the period being presented. Distributions declared in the period and undeclared
distributions that accumulated during the period are added back to the numerator for purposes of the if-converted calculation.
For the years ended December 31, 2021, 2020, and 2019, the effect of the assumed conversion of our Class A Convertible
Preferred Units was anti-dilutive and was not included in the computation of diluted earnings per unit.
The following table reconciles Net income (loss) and weighted average units used in computing basic and diluted Net
income (loss) per common unit (in thousands, except per unit amounts):
Net income (loss) attributable to Genesis Energy L.P.
Less: Accumulated distributions attributable to Class A Convertible
Preferred Units
Year Ended
December 31,
2021
2020
2019
$ (165,067) $ (416,678) $
95,999
(74,736)
(74,736)
(74,467)
Net income (loss) available to common unitholders
$ (239,803) $ (491,414) $
21,532
Weighted average outstanding units
122,579
122,579
122,579
Basic and diluted net income (loss) per common unit
$
(1.96) $
(4.01) $
0.18
13. Business Segment Information
•
•
•
We currently manage our businesses through four divisions that constitute our reportable segments:
Offshore pipeline transportation – offshore transportation of crude oil and natural gas in the Gulf of Mexico;
Sodium minerals and sulfur services – trona and trona-based exploring, mining, processing, producing, marketing and
selling activities, as well as processing of high sulfur (or “sour”) gas streams for refineries to remove the sulfur, and
selling the related by-product, NaHS;
Onshore facilities and transportation – terminaling, blending, storing, marketing, and transporting crude oil, and
petroleum products (primarily fuel oil, asphalt, and other heavy refined products); and
• Marine transportation – marine transportation to provide waterborne transportation of petroleum products and crude oil
throughout North America.
Substantially all of our revenues are derived from, and substantially all of our assets are located in, the United States.
We define Segment Margin as revenues less product costs, operating expenses (excluding non-cash charges, such as
depreciation, depletion, and amortization), segment general and administrative expenses, net of the effects of our noncontrolling
interests, plus our equity in distributable cash generated by our equity investees. In addition, our Segment Margin definition
excludes the non-cash effects of our long-term incentive compensation plan and includes the non-income portion of payments
received under direct financing leases or from our unrestricted subsidiaries under our credit agreement.
Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of
measures including Segment Margin, segment volumes, where relevant, and capital investment.
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Segment information for each year presented below is as follows:
Year Ended December 31, 2021
Segment Margin(1)
Capital expenditures(2)
Revenues:
External customers
Intersegment(3)
Total revenues of reportable segments $
Year Ended December 31, 2020
Segment Margin(1)
Capital expenditures(2)
Revenues:
$
$
Offshore
Pipeline
Transportation
Sodium
Minerals &
Sulfur Services
Onshore
Facilities &
Transportation
Marine
Transportation
Total
$
$
317,560 $ 166,773 $
98,824 $
34,572 $ 617,729
50,546 $ 227,118 $
4,609 $
34,456 $ 316,729
$
278,459 $ 973,354 $ 685,652 $ 188,011 $ 2,125,476
—
(8,722)
5,906
2,816 $
—
278,459 $ 964,632 $ 691,558 $ 190,827 $ 2,125,476
270,078 $ 130,083 $ 147,254 $
60,058 $ 607,473
13,323 $
95,511 $
4,133 $
31,357 $ 144,324
External customers
Intersegment(3)
Total revenues of reportable segments $
Year Ended December 31, 2019
Segment Margin(1)
Capital expenditures(2)
Revenues:
$
$
$
237,123 $ 886,078 $ 500,420 $ 201,034 $ 1,824,655
23
(8,309)
(938)
9,224 $
—
237,146 $ 877,769 $ 499,482 $ 210,258 $ 1,824,655
320,023 $ 223,908 $ 111,412 $
57,919 $ 713,262
17,809 $ 107,837 $
6,576 $
40,820 $ 173,042
External customers
Intersegment(3)
$
318,116 $ 1,113,623 $ 824,148 $ 224,933 $ 2,480,820
—
(7,636)
(3,076)
10,712 $
—
Total revenues of reportable segments $
318,116 $ 1,105,987 $ 821,072 $ 235,645 $ 2,480,820
Total assets by reportable segment were as follows:
Offshore pipeline transportation
Sodium minerals and sulfur services
Onshore facilities and transportation
Marine transportation
Other assets
Total consolidated assets
December 31,
2021
December 31,
2020
December 31,
2019
$ 2,103,140 $ 2,187,083 $ 2,306,946
2,132,588
1,962,146
2,019,905
923,064
703,030
1,035,662
711,058
1,457,190
772,383
43,979
41,217
$ 5,905,801 $ 5,933,619 $ 6,597,641
37,670
(1) A reconciliation of Net income (loss) attributable to Genesis Energy, L.P. to total Segment Margin to for each year is presented
below.
(2) Capital expenditures include maintenance and growth capital expenditures, such as fixed asset additions (including enhancements to
existing facilities and construction of growth projects) as well as contributions to equity investees, if any.
(3)
Intersegment sales were conducted under terms that we believe were no more or less favorable than then-existing market conditions.
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Reconciliation of Net income (loss) attributable to Genesis Energy, L.P. to total Segment Margin:
Net income (loss) attributable to Genesis Energy, L.P.
Corporate general and administrative expenses
Depreciation, depletion, amortization and accretion
Interest expense
Adjustment to exclude distributable cash generated by equity investees not
included in income and include equity in investees net income(1)
Non-cash items not included in Segment Margin(2)
Distributions from unrestricted subsidiaries not included in income(3)
Cancellation of debt income (Note 10)
Loss on extinguishment of debt (Note 10)
Differences in timing of cash receipts for certain contractual arrangements(4)
Loss on sales of assets (Note 7)
Non-cash provision for leased items no longer in use
Income tax expense
Redeemable noncontrolling interest redemption value adjustments(5)
Impairment expense (Note 7)
Total Segment Margin
Year Ended
December 31,
2021
2020
$ (165,067) $ (416,678) $
61,287
315,896
233,724
51,457
302,602
209,779
26,207
30,907
70,000
—
1,627
15,482
—
17,042
5,847
70,490
(27,302)
31,730
40,848
22,045
2019
95,999
52,755
308,115
219,440
20,847
14,642
8,421
—
—
(8,478)
—
598
1,670
25,398
—
(1,367)
655
2,233
—
$ 617,729 $ 607,473 $ 713,262
1,347
1,327
16,113
280,826
(1)
Includes distributions attributable to the period and received during or promptly following such period.
(2)
Includes an unrealized loss of $30.8 million, $0.9 million and $9.0 million from the valuation of the embedded derivative
associated with our Class A Convertible Preferred Units in 2021, 2020 and 2019, respectively.
(3) 2021 includes $70.0 million in cash receipts associated with principal repayments on our previously owned NEJD pipeline not
included in income. 2020 includes cash payments received from our NEJD pipeline of $48.0 million not included in income and
distributions from our Free State pipeline of $22.5 million not included in income, both of which are defined as unrestricted
subsidiaries under our senior secured credit agreement. 2019 includes cash payments received from our NEJD pipeline of $8.4
million not included in income.
(4)
Includes the difference in timing of cash receipts from customers during the period and the revenue we recognize in accordance
with GAAP on our related contracts.
(5)
Includes distributions paid-in-kind attributable to the period and accretion on the redemption feature.
14. Transactions with Related Parties
Transactions with related parties were as follows:
Year Ended December 31,
2021
2020
2019
Revenues:
Revenues from services and fees to Poseidon Oil Pipeline Company, LLC(1)
Revenues from product sales to ANSAC
13,846
12,902
12,669
280,935
236,408
367,133
Expenses:
Amounts paid to our CEO in connection with the use of his aircraft
Charges for products purchased from Poseidon Oil Pipeline Company, LLC(1)
Charges for services from ANSAC
$
660 $
660 $
965
1,213
960
2,460
660
975
4,446
(1) We own a 64% interest in Poseidon Oil Pipeline Company, LLC.
Our CEO, Mr. Sims, owns an aircraft which is used by us for business purposes in the course of operations. We pay
Mr. Sims a fixed monthly fee and reimburse the aircraft management company for costs related to our usage of the aircraft,
including fuel and the actual out-of-pocket costs. Based on current market rates for chartering of private aircraft under long-
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term, priority arrangements with industry recognized chartering companies, we believe that the terms of this arrangement are no
worse than what we could have expected to obtain in an arms-length transaction.
Transactions with Unconsolidated Affiliates
Poseidon
We provide management, administrative and pipeline operator services to Poseidon under an Operation and
Management Agreement. Currently, that agreement automatically renews annually unless terminated by either party (as defined
in the agreement). Our revenues for the years ended December 31, 2021, 2020 and 2019 reflect $9.4 million, $9.2 million and
$8.9 million, respectively, of fees we earned through the provision of services under that agreement. At December 31, 2021,
and 2020, Poseidon Oil Pipeline Company, LLC owed us $2.4 million and $2.6 million, respectively, for services rendered.
ANSAC
We (through a subsidiary of our Alkali Business) are a member of the American Natural Soda Ash Corp. (“ANSAC”),
an organization whose purpose is promoting and increasing the use and sale of natural soda ash and other refined or processed
sodium products produced in the U.S. and consumed in specified countries outside of the U.S. Members sell products to
ANSAC to satisfy ANSAC’s sales commitments to its customers. ANSAC passes its costs through to its members using a pro
rata calculation based on sales. Those costs include sales and marketing, employees, office supplies, professional fees, travel,
rent, and certain other costs. Those transactions do not necessarily represent arm's length transactions and may not represent all
costs we would otherwise incur if we operated the Alkali Business on a stand-alone basis. We also benefit from favorable
shipping rates for our direct exports when using ANSAC to arrange for ocean transport.
ANSAC is considered a variable interest entity (VIE) as we do experience certain risks and rewards from our
relationship with them. As we do not exercise control over ANSAC and are not considered its primary beneficiary, we do not
consolidate ANSAC. The ANSAC membership agreement provides that in the event an ANSAC member exits or the ANSAC
cooperative is dissolved, the exiting members are obligated for their respective portion of the residual net assets or deficit of the
cooperative. As of December 31, 2021, such amount is not material to us.
Net sales to ANSAC were $280.9 million, $236.4 million and $367.1 million for the years ended December 31, 2021,
2020 and 2019, respectively. The costs charged to us by ANSAC, included in operating costs, were $1.2 million, $2.5 million
and $4.4 million for the years ended December 31, 2021, 2020 and 2019, respectively.
As of December 31, 2021 and 2020, our receivables from and payables to ANSAC were:
Receivables:
ANSAC
Payables:
ANSAC
December 31,
2021
2020
$
$
64,799 $
43,400
116 $
470
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15. Supplemental Cash Flow Information
The following table provides information regarding the net changes in components of operating assets and liabilities:
(Increase) decrease in:
Accounts receivable
Inventories
Deferred charges
Other current assets
Increase (decrease) in:
Accounts payable
Accrued liabilities
Net changes in components of operating assets and liabilities
Year Ended December 31,
2021
2020
2019
$
$
(75,165) $
20,370
27,390
(1,190)
88,116 $
(34,740)
24,590
1,188
(80,126)
7,659
4,093
(4,874)
44,119
14,520
30,044 $
(9,742)
(30,785)
38,627 $
81,915
(79,765)
(71,098)
Payments of interest and commitment fees were $202.0 million, $200.6 million and $212.4 million during the years
ended December 31, 2021, 2020 and 2019, respectively. We capitalized interest of $4.4 million, $1.9 million and $3.7 million
during the years ended December 31, 2021, 2020 and 2019, respectively.
During the years ended December 31, 2021, 2020 and 2019, we paid taxes of $0.7 million, $0.8 million and $0.8
million, respectively.
At December 31, 2021, 2020 and 2019, we had incurred liabilities for fixed and intangible asset additions totaling
$51.7 million, $29.1 million and $22.6 million, respectively, which had not been paid at the end of the year. Therefore, these
amounts were not included in the caption “Payments to acquire fixed and intangible assets” under Cash Flows from Investing
Activities in the Consolidated Statements of Cash Flows. The increase in this amount is principally due to the increase in capital
expenditures associated with our Granger Optimization Project (Note11).
16. Equity-Based Compensation Plans
2010 Long Term Incentive Plan
In 2010, we adopted the 2010 Long-Term Incentive Plan (the “2010 Plan”). The 2010 Plan provides for the awards of
phantom units and distribution equivalent rights to members of our board of directors and employees who provide services to
us. Phantom units are notional units representing unfunded and unsecured promises to pay to the participant a specified amount
of cash based on the market value of our common units should specified vesting requirements be met. Distribution equivalent
rights (“DERs”) are tandem rights to receive on a quarterly basis a cash amount per phantom unit equal to the amount of cash
distributions paid per common unit. The 2010 Plan is administered by the Governance, Compensation and Business
Development Committee (the “G&C Committee”) of our board of directors. The G&C Committee (at its discretion) designates
participants in the 2010 Plan, determines the types of awards to grant to participants, determines the number of units to be
covered by any award, and determines the conditions and terms of any award including vesting, settlement and forfeiture
conditions.
The compensation cost associated with the phantom units is re-measured each reporting period based on the market
value of our common units, and is recognized over the vesting period. The liability recorded for the estimated amount to be paid
to the participants under the 2010 Plan is adjusted to recognize changes in the estimated compensation cost and vesting.
During 2021, we granted 71,340 phantom units with tandem DERs at a weighted average grant fair value of $8.83 per
unit. During 2020, we granted 107,572 phantom units with tandem DERs at a weighted average grant date fair value of $5.86
per unit. During 2019, we granted 29,606 phantom units with tandem DERs at a weighted average grant date fair value of
$21.28 per unit. The phantom units granted for 2019, 2020, and 2021 were made only to directors. Awards to management and
other key employees during 2019 and 2021 were made under the 2018 LTIP plan, and were not equity-based awards.
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A summary of our phantom unit activity for our service-based awards to our directors is set forth below:
Unvested at December 31, 2020
Granted
Settled
Unvested at December 31, 2021
Number of
Phantom
Units
Service-Based Awards
Average
Grant
Date Fair
Value
Total
Value
(in thousands)
165,662 $
71,340 $
(28,484) $
208,518 $
11.19 $
8.83
9.05
10.67 $
1,853
630
(258)
2,225
We recorded compensation expense of $1.4 million, a credit to compensation expense of $1.0 million and
compensation expense of $1.8 million for the years ended December 31, 2021, 2020 and 2019, respectively. Our liability for
these awards totaled $2.2 million and $1.1 million at December 31, 2021 and 2020, respectively, and is included within
“Accrued liabilities” on the Consolidated Balance Sheets.
Equity-Based Compensation Plan Expense
Equity-based compensation expense (credit) during the three years ended December 31, 2021 was as follows:
Consolidated Statements of Operations
Onshore facilities and transportation operating costs
Marine transportation operating costs
Sodium minerals and sulfur services operating costs
Offshore pipeline operating costs
General and administrative expenses
Total
Expense (Credit) Related to Equity-
Based Compensation Plans
2021
2020
2019
$ — $ (209) $ 250
—
—
—
1,416
(51)
(115)
(277)
173
140
269
(333) 1,087
$ 1,416 $ (985) $ 1,919
17. Major Customers and Credit Risk
Due to the nature of our onshore facilities and transportation operations, a disproportionate percentage of our trade
receivables constitute obligations of refiners, large crude oil producers and integrated oil companies. This industry
concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our
customers could be affected by similar changes in economic, industry or other conditions. However, we believe that the credit
risk posed by this industry concentration is offset by the creditworthiness of our customer base. Our portfolio of accounts
receivable is comprised in large part of accounts owed by integrated and large independent energy companies with stable
payment histories. The credit risk related to contracts which are traded on the NYMEX is limited due to daily margin
requirements and other NYMEX requirements.
We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits,
collateral requirements and rights of offset. Letters of credit, prepayments and guarantees are also utilized to limit credit risk to
ensure that our established credit criteria are met.
In 2021, 2020 and 2019 our largest customer was ANSAC, which accounted for 13%, 13% and 15% of total
consolidated revenues, respectively. As discussed in Note 14, we are a member of ANSAC, an organization whose purpose is
promoting and increasing the use and sale of natural soda ash and other refined or processed sodium products produced in the
U.S. and consumed in specified countries outside of the U.S. Members sell products to ANSAC to satisfy ANSAC’s sales
commitments to its customers. Given this relationship, a large portion of our soda ash production is sold to ANSAC. As such,
a disproportionate amount of our trade receivables and sales in our sodium minerals and sulfur services segment are related to
ANSAC.
18. Derivatives
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Commodity Derivatives
We have exposure to commodity price changes related to our inventory and purchase commitments. We utilize
derivative instruments (primarily futures and options contracts traded on the NYMEX) to hedge our exposure to commodity
prices, primarily of crude oil, fuel oil, natural gas and petroleum products. Our decision as to whether to designate derivative
instruments as fair value hedges for accounting purposes relates to our expectations of the length of time we expect to have the
commodity price exposure and our expectations as to whether the derivative contract will qualify as highly effective under
accounting guidance in limiting our exposure to commodity price risk. Most of the petroleum products, including fuel oil that
we supply, cannot be hedged with a high degree of effectiveness with derivative contracts available on the NYMEX; therefore,
we do not designate derivative contracts utilized to limit our price risk related to petroleum products as hedges for accounting
purposes. Typically we utilize crude oil and other petroleum products futures and option contracts to limit our exposure to the
effect of fluctuations in petroleum products prices on the future sale of our inventory or commitments to purchase petroleum
products, and we recognize any changes in fair value of the derivative contracts as increases or decreases in our cost of
sales. The recognition of changes in fair value of the derivative contracts not designated as hedges for accounting purposes can
occur in reporting periods that do not coincide with the recognition of gain or loss on the actual transaction being
hedged. Therefore we will, on occasion, report gains or losses in one period that will be partially offset by gains or losses in a
future period when the hedged transaction is completed.
We have designated certain crude oil futures contracts as hedges of crude oil inventory due to our expectation that
these contracts will be highly effective in hedging our exposure to fluctuations in crude oil prices during the period that we
expect to hold that inventory. We account for these derivative instruments as fair value hedges under the accounting guidance.
Changes in the fair value of these derivative instruments designated as fair value hedges are used to offset related changes in the
fair value of the hedged crude oil inventory. Any hedge ineffectiveness in these fair value hedges and any amounts excluded
from effectiveness testing are recorded as a gain or loss within “Onshore facilities and transportation costs - product costs” in
the Consolidated Statements of Operations.
In accordance with NYMEX requirements, we fund the margin associated with our loss positions on commodity
derivative contracts traded on the NYMEX. The amount of the margin is adjusted daily based on the fair value of the
commodity derivative contracts. Margin requirements are intended to mitigate a party’s exposure to market volatility and
counterparty credit risk. We offset fair value amounts recorded for our NYMEX derivative contracts against margin funding as
required by the NYMEX in “Current Assets - Other” in our Consolidated Balance Sheets.
Additionally, we utilize swap arrangements. Our Alkali Business relies on natural gas to generate heat and electricity
for operations. We use a combination of commodity price swap contracts, future purchase contracts and option contracts to
manage our exposure to fluctuations in natural gas prices. The swap contracts fix the basis differential between NYMEX Henry
Hub and NW Rocky Mountain posted prices. We do not designate these contracts as hedges for accounting purposes. We
recognize any changes in fair value of natural gas derivative contracts as increases or decreases within “Sodium minerals and
sulfur services operating costs” in the Consolidated Statements of Operations.
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At December 31, 2021, we had the following outstanding commodity derivative commodity contracts that were
entered into to economically hedge inventory, fixed price purchase commitments or forecasted purchases.
Designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 Bbls)
Weighted average contract price per Bbl
Not qualifying or not designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 Bbls)
Weighted average contract price per Bbl
Natural gas swaps:
Contract volumes (10,000 MMBtu)
Weighted average price differential per MMBtu
Natural gas futures:
Contract volumes (10,000 MMBtu)
Weighted average contract price per MMBtu
Petroleum products (#6 fuel oil) futures:
Contract volumes (1,000 Bbls)
Weighted average contract price per Bbl
Natural gas options
Contract volumes (10,000 MMBtu)
Weighted average premium received/paid
Crude oil options:
Contract volumes (1,000 Bbls)
Weighted average premium received/paid
Sell (Short)
Contracts
Buy (Long)
Contracts
37
71.14
—
—
162
72.54 $
61
75.52
456
0.02
94
3.99 $
15
64.40 $
35
0.21 $
11
2.50 $
—
—
519
4.01
—
—
15
0.06
3
1.76
$
$
$
$
$
$
$
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Financial Statement Impacts
The following table summarizes the accounting treatment and classification of our derivative instruments on our
Consolidated Financial Statements.
Derivative Instrument
Hedged Risk
Designated as hedges under accounting guidance:
Crude oil futures contracts
(fair value hedge)
Volatility in crude oil
prices - effect on market
value of inventory
Impact of Unrealized Gains and Losses
Consolidated
Balance Sheets
Consolidated
Statements of Operations
Derivative is recorded in
“Current Assets -
Other” (offset against margin
deposits) and offsetting
change in fair value of
inventory is recorded
in Inventories
Excess, if any, over effective
portion of hedge is recorded in
“Onshore facilities and
transportation costs - product
costs”
Effective portion is offset in cost
of sales against change in value
of inventory being hedged
Entire amount of change in fair
value of derivative is recorded in
“Onshore facilities and
transportation costs - product
costs” and “Sodium minerals
and sulfur services operating
costs”
Entire amount of change in fair
value of derivative is recorded in
“Other expense, net”
Not qualifying or not designated as hedges under accounting guidance:
Commodity hedges
consisting of crude oil,
heating oil, fuel oil,
petroleum products and
natural gas futures, forward
contracts, swaps and put
and call options
Preferred Distribution Rate
Reset Election
Volatility in crude oil,
natural gas and petroleum
products prices - effect on
market value of inventory,
fixed price purchase
commitments or forecasted
purchases
This instrument is not
related to a risk, but is
rather part of a host
contract with the issuance
of our Class A Convertible
Preferred Units
Derivative is recorded in
“Current Assets -
Other” (offset against margin
deposits) or Accrued liabilities
Derivative is recorded in
“Other long-term liabilities”
Unrealized gains are subtracted from net income and unrealized losses are added to net income in determining cash
flows from operating activities. To the extent that we have fair value hedges outstanding, the offsetting change recorded in the
fair value of inventory is also eliminated from net income in determining cash flows from operating activities. Changes in
margin deposits necessary to fund unrealized losses also affect cash flows from operating activities.
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The following tables reflect the estimated fair value position of our derivatives at December 31, 2021 and 2020:
Fair Value of Derivative Assets and Liabilities
Asset Derivatives:
Natural Gas Swap (undesignated hedge)
Commodity derivatives—futures and put and call options
(undesignated hedges):
Gross amount of recognized assets
Gross amount offset in the Consolidated Balance Sheets
Net amount of assets presented in the Consolidated Balance
Sheets
Commodity derivatives—futures (designated hedges):
Gross amount of recognized assets
Gross amount offset in the Consolidated Balance Sheets
Net amount of assets presented in the Consolidated Balance
Sheets
Liability Derivatives:
Preferred Distribution Rate Reset Election(2)
Natural Gas Swap (undesignated hedge)
Commodity derivatives—futures and put and call options
(undesignated hedges):
Gross amount of recognized liabilities
Gross amount offset in the Consolidated Balance Sheets
Consolidated
Balance Sheets
Location
Current Assets -
Other
Fair Value
December 31, 2021
December 31, 2020
1,867
616
Current Assets -
Other
$
Current Assets -
Other
Current Assets -
Other
Current Assets -
Other
$
$
$
310
$
(310)
—
49
(49)
$
$
732
(732)
—
1,022
(1,022)
—
$
—
Other Long-Term
Liabilities(2)
$
(83,210)
$
(52,372)
Current
Liabilities -
Accrued
Liabilities
(608)
—
Current Assets -
Other(1)
$
Current Assets -
Other(1)
(2,380)
$
(2,114)
2,380
2,114
Net amount of liabilities presented in the Consolidated Balance
Sheets
Commodity derivatives—futures (designated hedges):
Gross amount of recognized liabilities
Gross amount offset in the Consolidated Balance Sheets
Net amount of liabilities presented in the Consolidated Balance
Sheets
Current Assets -
Other(1)
Current Assets -
Other(1)
$
$
$
—
$
—
(209)
$
(3,345)
209
3,073
—
$
(272)
(1) These derivative liabilities have been funded with margin deposits recorded in our Consolidated Balance Sheets under “Current
Assets - Other.”
(2) Refer to Note 11 and Note 19 for additional discussion surrounding the Preferred Distribution Rate Reset Election derivative.
Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master
netting arrangement exists. Accordingly, we also offset derivative assets and liabilities with our cash margin balance. Our
exchange-traded derivatives are transacted through brokerage accounts and are subject to margin requirements as established by
the respective exchange. On a daily basis, our account equity (consisting of the sum of our cash margin balance and the fair
value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation
margin. As of December 31, 2021, we had a net broker receivable of approximately $2.9 million (consisting of initial margin
of $2.1 million increased by $0.8 million of variation margin). As of December 31, 2020, we had a net broker receivable of
approximately $3.4 million (consisting of initial margin of $3.3 million increased by $0.1 million of variation margin). At
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December 31, 2021 and December 31, 2020, none of our outstanding derivatives contained credit-risk related contingent
features that would result in a material adverse impact to us upon any change in our credit ratings.
Preferred Distribution Rate Reset Election
A derivative feature embedded in a contract that does not meet the definition of a derivative in its entirety must be
bifurcated and accounted for separately if the economic characteristics and risks of the embedded derivative are not clearly and
closely related to those of the host contract. For a period of 30 days following (i) September 1, 2022 and (ii) each subsequent
anniversary thereof, the holders of our Class A Convertible Preferred Units may make a Rate Reset Election to a cash amount
per preferred unit equal to the amount that would be payable per quarter if a preferred unit accrued interest on the Issue Price at
an annualized rate equal to three-month LIBOR plus 750 basis points; provided, however, that such reset rate shall be equal to
10.75% if (i) such alternative rate is higher than the LIBOR-based rate and (ii) the then market price for our common units is
then less than 110% of the Issue Price. The Rate Reset Election of the Class A Convertible Preferred Units represents an
embedded derivative that must be bifurcated from the related host contract and recorded at fair value on our Consolidated
Balance Sheets. Corresponding changes in fair value are recognized in “Other expense, net” in our Consolidated Statements of
Operations. At December 31, 2021, the fair value of this embedded derivative was a liability of $83.2 million. See Note 11 for
additional information regarding our Class A Convertible Preferred Units and the Rate Reset Election.
Effect on Operating Results
Commodity derivatives—futures and
options:
Contracts designated as hedges under
accounting guidance
Contracts not considered hedges under
accounting guidance
Total commodity derivatives
Natural gas swaps
Amount of Gain (Loss) Recognized in Income
Year Ended
December 31,
Consolidated Statements of
Operations Location
2021
2020
2019
Onshore facilities and
transportation product costs
Onshore facilities and
transportation product costs,
sodium minerals and sulfur
services operating costs
$
(7,634) $
(14,454) $
(786)
(8,891)
(16,525) $
(5,475)
(19,929) $
(7,790)
(8,576)
$
Sodium minerals and sulfur
services operating costs
1,174 $
1,186 $
1,941
Preferred Distribution Rate Reset Election
Other expense, net
$
(30,838) $
(857) $
(9,026)
We have no derivative contracts with credit contingent features.
19. Fair-Value Measurements
We classify financial assets and liabilities into the following three levels based on the inputs used to measure fair
value:
(1) Level 1 fair values are based on observable inputs such as quoted prices in active markets for identical assets and
liabilities;
(2) Level 2 fair values are based on pricing inputs other than quoted prices in active markets for identical assets and
liabilities and are either directly or indirectly observable as of the measurement date; and
(3) Level 3 fair values are based on unobservable inputs in which little or no market data exists.
As required by fair value accounting guidance, financial assets and liabilities are classified in their entirety based on
the lowest level of input that is significant to the fair value measurement.
Our assessment of the significance of a particular input to the fair value requires judgment and may affect the
placement of assets and liabilities within the fair value hierarchy levels.
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Table of Contents
The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were
accounted for at fair value on a recurring basis as of December 31, 2021 and 2020.
Recurring Fair Value Measures
Commodity derivatives:
Assets
Liabilities
Preferred Distribution Rate Reset Election
December 31, 2021
December 31, 2020
Level 1
Level 2
Level 3
Level 1
Level 2
Level 3
$
$
$
359 $
1,867 $
— $
1,754 $
616 $
(2,589) $
(608) $
— $
(5,459) $
— $
—
—
— $
— $ (83,210) $
— $
— $ (52,372)
Rollforward of Level 3 Fair Value Measurements
The following table provides a reconciliation of changes in fair value at the beginning and ending balances for our
derivatives classified as level 3:
Balance as of December 31, 2019
Net loss for the period including earnings
Balance as of December 31, 2020
Net loss for the period included in earnings
Balance as of December 31, 2021
$
$
(51,515)
(857)
(52,372)
(30,838)
(83,210)
Our commodity derivatives include exchange-traded futures and exchange-traded options contracts. The fair value of
these exchange-traded derivative contracts is based on unadjusted quoted prices in active markets and is, therefore, included in
Level 1 of the fair value hierarchy. The fair value of the swaps contracts was determined using market price quotations and a
pricing model. The swap contracts were considered a level 2 input in the fair value hierarchy at December 31, 2021.
The fair value of embedded derivative feature is based on a valuation model that estimates the fair value of the
convertible preferred units with and without a Rate Reset Election. This model contains inputs, including our common unit
price relative to the issuance price, the current dividend yield, the discount yield (which is adjusted periodically for changes
associated with the industry's credit markets), default probabilities, equity volatility, U.S. Treasury yields and timing estimates
which involve management judgment. Our equity volatility rate used to value our embedded derivative feature was 50% at
December 31, 2021. A significant increase or decrease in the value of these inputs could result in a material change in fair value
to this embedded derivative feature. Due to a decrease in our discount yield compared to December 31, 2020 as a result of
significant fluctuations in the energy industry credit markets and volatility in our common unit price during the period, as well
as the passage of time as we draw nearer to our coupon rate reset date in 2022, we recorded an unrealized loss of $30.8 million
for the year ended December 31, 2021. We report unrealized gains and losses associated with this embedded derivative in our
Consolidated Statements of Operations as “Other expense, net.”
See Note 18 for additional information on our derivative instruments.
Nonfinancial Assets and Liabilities
We utilize fair value on a non-recurring basis to perform impairment tests as required on our property, plant and
equipment, goodwill and intangible assets. Assets and liabilities acquired in business combinations are recorded at their fair
value as of the date of acquisition. The inputs used to determine such fair value are primarily based upon internally developed
cash flow models and would generally be classified in Level 3, in the event that we were required to measure and record such
assets within our Consolidated Financial Statements. Additionally, we use fair value to determine the inception value of our
asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically
for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property
to the contractually stipulated condition, and would generally be classified in Level 3.
Other Fair Value Measurements
We believe the debt outstanding under our senior secured credit facility approximates fair value as the stated rate of
interest approximates current market rates of interest for similar instruments with comparable maturities. At December 31, 2021
our senior unsecured notes had a carrying value of $3.0 billion and fair value of $3.0 billion, compared to a carrying value of
$2.8 billion and fair value of $2.7 billion at December 31, 2020. The fair value of the senior unsecured notes is determined
based on trade information in the financial markets of our public debt and is considered a Level 2 fair value measurement.
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20. Employee Benefit Plans
We sponsor a defined benefit pension plan for union-only employees of our Alkali Business. We account for the
Alkali Business pension plan as a single employer pension plan that benefits only employees of our Alkali Business, and thus,
the related assets and liability costs of the plan are recorded in the Consolidated Balance Sheets. Under the Alkali Business
pension plan, each eligible employee will automatically become a participant upon completion of one year of credited service.
Retirement benefits under this plan are calculated based on the total years of service of an eligible participant, multiplied by a
specified benefit rate in effect at the termination of the plan participant's years of service.
The change in benefit obligations, plan assets and funded status along with amounts recognized in the Consolidated
Balance Sheets are as follows:
Change in benefit obligation:
Benefit Obligation, beginning of year
$
52,510 $
42,291
December 31,
2021
2020
Service Cost
Interest Cost
Actuarial Loss (Gain)
Benefits Paid
Benefit Obligation, end of year
Change in plan assets:
Fair Value of Plan Assets, beginning of year
Actual Return on Plan Assets
Employer Contributions
Benefits Paid
Fair Value of Plan assets, end of year
Funded Status at end of period
Amounts recognized in the Consolidated Balance Sheets:
Non-current assets
Current liabilities
Non-current Liabilities
Net Liability at end of year
6,020
1,576
(3,051)
(1,121)
55,934
32,043
2,051
2,315
(1,121)
35,288
5,493
1,469
4,005
(748)
52,510
24,051
4,123
4,617
(748)
32,043
$
$
(20,646) $
(20,467)
— $
—
—
—
(20,646)
$
(20,646) $
(20,467)
(20,467)
Amounts recognized in accumulated other comprehensive loss:
Prior Service Cost
Net actuarial loss
5,189
418
Amounts recognized in accumulated other comprehensive loss:
$
5,607 $
5,676
3,689
9,365
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Estimated Future Cash Flows- The following employer contributions and benefit payments, which reflect expected future
service, are expected to be paid as follows:
Employer Contributions
Expected 2022 Contributions by Employer
Future Expected Benefit Payments
2022
2023
2024
2025
2026
2027-2031
$
$
2,436
1,265
1,450
1,620
1,796
1,983
12,319
Net Periodic Pension Costs- The components of net periodic pension costs for the Alkali benefit plan are as follows:
Service Cost
Interest Cost
Expected Return on Assets
Amortization of Prior Service Cost
Total Net Periodic Benefit Costs
December 31,
2021
2020
2019
$
6,020 $
5,493
$
4,351
1,576
(1,831)
487
1,469
(1,539)
487
1,340
(1,252)
406
$
6,252 $
5,910
$
4,845
Significant Assumptions - Discount rates are determined annually and are based on rates of return of high-quality long-term
fixed income securities currently available and expected to be available during the maturity of the pension benefits.
The long-term rate of return estimation for the Alkali Business pension plan is based on a capital asset pricing model
using historical data and a forecasted earnings model. An expected return on plan assets analysis is performed which
incorporates the current portfolio allocation, historical asset-class returns and an assessment of expected future performance
using asset-class risk factors.
The Alkali Business pension plan is administered by a Board-appointed committee that has fiduciary responsibility for
the plan's management. The committee is responsible for the oversight and management of the plan's investments. The
committee maintains an investment policy that provides guidelines for selection and retention of investment managers or funds,
allocation of plan assets and performance review procedures and updating of the policy. The objective of the committee's
investment policy is to manage the plan assets in such a way that will allow for the on-going payment of the Company's
obligation to the beneficiaries.
Weighted average assumptions used to
determine benefit obligation:
Discount Rate
Expected Long-term Rate of Return
Rate of Compensation Increase
December 31, 2021
December 31, 2020
3.27 %
5.35 %
N/A
3.06 %
5.47 %
N/A
The discount rate used to determine the net periodic cost at the beginning of the period was 3.06%.
Pension Plan Assets - We maintain target allocation percentages among various asset classes based on an investment policy
established for the pension plan, which was last amended in November 2020. The target allocation is designed based on the
strategic objectives, spending policy and risk tolerance of the plan. Pension plan asset allocations at December 31, 2021 by
asset category are as follows:
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December 31, 2021
Equity securities
Fixed Income
Alternative Investments
Cash and Equivalents
Target % Minimum Maximum
67 %
20 %
11 %
2 %
58 %
11 %
2 %
— %
76 %
29 %
20 %
7 %
A summary of total investments for our pension plan assets measured at fair value is presented as of December 31 for
the periods below:
2021
2020
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
Cash and cash equivalents
$ 2,989 $ — $ — $ 2,989
$ 32,043 $ — $ — $ 32,043
Equity securities
Fixed income and other
securities
25,309
6,990
—
—
—
25,309
—
6,990
—
—
—
—
—
—
—
—
$ 35,288 $ — $ — $ 35,288
$ 32,043 $ — $ — $ 32,043
As identified above, all of our plan assets as of December 31, 2020 were held in cash and equivalents. On January 1,
2021 we switched the trustee of our plan assets and the investment advisors for our plan assets, also modifying our investment
advisor fiduciary services from a 3(21) to a 3(38) which allows the advisors more investment discretion. In order to prepare for
this switch, we had to move our investments to cash and equivalents on December 31, 2020.
21. Commitments and Contingencies
Commitments and Guarantees
We are subject to various environmental laws and regulations. Policies and procedures are in place to monitor
compliance and to detect and address any releases of crude oil from our pipelines or other facilities; however no assurance can
be made that such environmental releases may not substantially affect our business.
Other Matters
Our facilities and operations may experience damage as a result of an accident or natural disaster. These hazards can
cause personal injury or loss of life, severe damage to and destruction of property and equipment, pollution or environmental
damage and suspension of operations. We maintain insurance that we consider adequate to cover our operations and properties,
in amounts we consider reasonable. Our insurance does not cover every potential risk associated with operating our facilities,
including the potential loss of significant revenues. The occurrence of a significant event that is not fully-insured could
materially and adversely affect our results of operations. We believe we are adequately insured for public liability and property
damage to others and that our coverage is similar to other companies with operations similar to ours. No assurance can be made
that we will be able to maintain adequate insurance in the future at premium rates that we consider reasonable.
We are subject to lawsuits in the normal course of business and examination by tax and other regulatory authorities.
We do not expect such matters presently pending to have a material effect on our financial position, results of operations or
cash flows.
22. Income Taxes
We are not a taxable entity for federal income tax purposes. As such, we do not directly pay federal income taxes.
Other than with respect to our corporate subsidiaries and the Texas Margin Tax, our taxable income or loss is includible in the
federal income tax returns of each of our partners.
A few of our operations are owned by wholly-owned corporate subsidiaries that are taxable as corporations. We pay
federal and state income taxes on these operations.
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Our income tax (benefit) expense is as follows:
Current:
Federal
State
Total current income tax expense
Deferred:
Federal
State
Total deferred income tax expense
Total income tax expense
Year Ended December 31,
2021
2020
2019
$
$
$
$
$
— $
690
690 $
1,097 $
(117)
980 $
1,670 $
— $
650
650 $
78 $
599
677 $
1,327 $
—
591
591
930
(866)
64
655
Deferred income taxes relate to temporary differences based on tax laws and statutory rates that were enacted at the
balance sheet date. Deferred tax assets and liabilities consist of the following:
Deferred tax assets:
Net operating loss carryforwards
Other
Total long-term deferred tax asset
Valuation allowances
Total deferred tax assets
Deferred tax liabilities:
Long-term:
Fixed assets
Intangible assets
Other
Total long-term liability
Total deferred tax liabilities
Total net deferred tax liability
December 31,
2021
2020
$
16,174 $
14,918
1,277
17,451
(2,760)
$
14,691 $
$
(1,803) $
(25,772)
(1,413)
(28,988)
(28,988) $
(14,297) $
$
$
985
15,903
(2,366)
13,537
(1,882)
(23,251)
(1,721)
(26,854)
(26,854)
(13,317)
We record a valuation allowance when it is more likely than not that some portion or all of the deferred tax assets will
not be realized. The ultimate realization of the deferred tax assets depends on the ability to generate sufficient taxable income of
the appropriate character in the future and in the appropriate taxing jurisdictions.
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The reconciliation between the Partnership's effective tax rate on income (loss) from operations and the statutory tax
rate is as follows:
Income (loss) from operations before income taxes
Partnership income not subject to federal income tax
Income (loss) subject to federal income taxes
Tax expense (benefit) at federal statutory rate
State income taxes, net of federal tax
Return to provision, federal and state
Other
Valuation allowance
Income tax expense
Year Ended December 31,
2021
2020
2019
$
(136,362)
$
(398,987)
$
100,721
398,729
(99,832)
$
$
$
$
140,092
3,730
783
574
(227)
112
428
$
$
(258)
(54)
1,213
(383)
117
434
$
1,670
$
1,327
$
889
187
729
(219)
(42)
—
655
Effective tax rate on income (loss) from operations before income taxes
(1.2) %
(0.3) %
0.7 %
At December 31, 2021, 2020 and 2019, we had no uncertain tax positions.
50