GENESIS ENERGY, L.P.
2017 A NNUAL REPORT TO UNITHOLDERS
LETTER TO OUR UNITHOLDERS
In 2017, we made several strategic decisions that further diversify our businesses and cash flow streams,
strengthen our balance sheet and position all stakeholders for future success. We look forward to 2018 and believe
we are well positioned to deliver on our previously announced guidance on visible, achievable long term distribution
growth with a clear path forward to deleveraging.
In September of 2017, we acquired the Alkali Business from Tronox for $1.325 billion in cash. The
business, now known as Genesis Alkali, is the world's largest producer of natural soda ash, also known as sodium
carbonate, a basic building block for a number of ubiquitous products, including flat glass, container glass, dry
detergent and a number of variety of chemicals and other industrial products. The business produces approximately
4 million tons of natural soda ash per year, representing approximately 28% of all the natural soda ash produced in
the world and based on current production rates, has an estimated reserved life remaining of over 100 years. In
conjunction with the transaction, we sold approximately $750 million of 8.75% Class A Convertible Preferred Units
for cash to investment vehicles affiliated with KKR Global Infrastructure Investors II and GSO Capital Partners.
KKR and GSO have the right to convert their investment into approximately 22.2 million common units of the
partnership at a price of $33.71 per unit.
In October of 2017, we made the long term decision to reallocate capital by resetting our quarterly
distribution rate to $0.50 per common unit with an intention to grow it at least $0.01 a quarter each and every quarter
for the next 20 quarters. We believe the proactive reallocation of capital ultimately accomplished the following:
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Further enhanced our balance sheet and financial flexibility,
Solidified our distribution coverage with sustainable and visible immediate distribution growth going
forward,
Defined a clear path forward to a targeted leverage ratio of 3.75 turns, with the excess coverage as
future equity or available to pay down debt,
Flexibility to pursue accretive organic or acquisition opportunities.
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We view this reallocation of capital as a strategic move, giving us substantial flexibility to continue to
deliver value to investors throughout our capital structure in the future. While, as we have previously disclosed,
we have not been immune to significant headwinds in some of our businesses from the cyclical downturn in energy
which began in late 2014, our diversified businesses in general continue to perform well. As we say goodbye to
2017 and look forward to 2018 and beyond, we believe we are at, or approaching, cyclical lows in those businesses
most affected.
Our sodium and sulfur businesses continue to perform in-line with or above expectations, reflecting their
pre-eminent positions in their respective industries and markets they serve. With continued increases in world-
wide macroeconomic activity, we expect these businesses to continue their relative outperformance.
In the deepwater Gulf of Mexico, we continue to be pleased with the amount of investment and activity in
and around our existing infrastructure focused on continued in-field development and subsea tie-back opportunities.
We continue to have active discussions with several third-party operators regarding midstream infrastructure
requirements for several new +/- 75 kbd standalone new hub-type developments anticipated to be sanctioned in
2019 or so, with first deliveries in the 2022-2024 time frame. We also anticipate Mad Dog II, which is 100%
dedicated to our Cameron Highway system and represents approximately 140kbd of incremental deepwater
production handling capacity, coming online late in 2021 or 2022.
Our significant infrastructure projects in the Baton Rouge corridor, Texas City area and transportation
systems in the emerging Powder River basin were substantially completed in 2017, and we anticipate seeing
increasing contribution from these assets throughout 2018. While we are a bit behind schedule and might arguably
have a slightly slower ramp from these major investments, we are very excited and have many reasons to believe
that we will ultimately exceed our average base case economics across the projects.
Our marine business, which arguably has been the most impacted by the recent cyclical headwinds, is
showing signs of bottoming. The fundamentals in the market for the marine transportation of hydrocarbons look
to remain challenging, certainly in 2018 and into 2019. It may take even beyond then for there to be a more
reasonable supply/demand balance in marine capacity. Until that occurs, we would expect minimal recovery in the
financial results for that segment, which now represents only approximately 6% of our total segment margin for the
fourth quarter of 2017.
Finally, we executed on a few other finance related initiatives during 2017. We sold approximately $70
million worth of non-strategic assets at very attractive multiples to the partnership. Additionally, we refinanced our
existing 2021 senior notes, effectively extending their term to 2026 at approximately the same coupon, and having
no existing note maturities until later in 2022. The term on our existing revolving credit facility was extended
automatically until May of 2022 as a result of this particular notes refinancing.
Our primary objective continues to be to deliver the best value to all of our stakeholders in the capital
structure while never wavering from our commitment to safe and responsible operations. A lot has changed, we
recognize, in how the market apparently values unit prices for MLPs or other midstream entities over the last several
years.
We now believe the best way to promote unit price appreciation under current conditions is to exercise
strong financial discipline designed primarily to maintain and enhance our financial flexibility across the business
cycle. We believe our increased liquidity and even stronger balance sheet resulting from the strategic actions we
took in 2017, along with the continue performance of our diversified, and in many cases market leading, businesses,
should combine to give us the flexibility to continue to pursue acquisitions and/or organic projects that we feel are
consistent with delivering long term value to all of our stakeholders.
This environment continues to be one in which companies or partnerships can and have to differentiate
themselves. Given the quality of our businesses, the future growth already in place and our identified prospects, we
believe we are well positioned to continue to deliver long term value for our stakeholders in the years to come.
Grant E. Sims
Chief Executive Officer
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, 2017
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)
76-0513049
(I.R.S. Employer
Identification No.)
919 Milam, Suite 2100, Houston, TX 77002
(Address of principal executive offices) (Zip code)
(713) 860-2500
Registrant’s telephone number, including area code:
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Common Units
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
No
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
No
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
No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data
File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period
that the registrant was required to submit and post such files). Yes
No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K.
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
Accelerated filer
Smaller reporting company
Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying
with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2) of the Act). Yes
No
The aggregate market value of the Class A common units held by non-affiliates of the Registrant on June 30, 2017 (the last business day of
Registrant’s most recently completed second fiscal quarter) was approximately $3.3 billion based on $31.73 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 26, 2018, the Registrant had 122,539,221 Class A Common Units and 39,997 Class B Common
Units outstanding.
GENESIS ENERGY, L.P.
2017 FORM 10-K ANNUAL REPORT
Table of Contents
Item 1
Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2.
Item 3.
Properties
Legal Proceedings
Item 4. Mine Safety Disclosures
Part I
Part II
Item 5.
Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity
Securities
Selected Financial Data
Item 6.
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/d: Thousand Bbls per day.
Mcf: Thousand cubic feet of gas.
mmBtu: One million British thermal units, an energy measurement.
MMcf: Thousand Mcf.
NaHS: (commonly pronounced as “nash”) Sodium hydrosulfide.
NaOH or Caustic Soda: Sodium hydroxide.
Natural gas liquid(s) or NGL(s): The combination of ethane, propane, normal butane, isobutane and natural gasolines that,
when removed from natural gas, become liquid under various levels of higher pressure and lower temperature.
Sour gas: Natural gas containing more than four parts per million of hydrogen sulfide.
Wellhead: The point at which the hydrocarbons and water exit the ground.
FORWARD-LOOKING INFORMATION
The statements in this Annual Report on Form 10-K that are not historical information may be “forward looking
statements” as defined under federal law. All statements, other than historical facts, included in this document that address
activities, events or developments that we expect or anticipate will or may occur in the future, including things such as plans
for growth of the business, future capital expenditures, competitive strengths, goals, references to future goals or intentions,
estimated or projected future financial performance, and other such references are forward-looking statements, and historical
performance is not necessarily indicative of future performance. These forward-looking statements are identified as any
statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,”
“continue,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “could,” “plan,” “position,” “projection,”
“strategy,” “should” or “will,” or the negative of those terms or other variations of them or by comparable terminology. In
particular, statements, expressed or implied, concerning future actions, conditions or events or future operating results or the
ability to generate sales, income or cash flow are forward-looking statements. Forward-looking statements are not guarantees
of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of
operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will
determine these results are beyond our ability or the ability of our affiliates to control or predict. Specific factors that could
cause actual results to differ from those in the forward-looking statements include, among others:
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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,caustic soda and CO2, all of which may be affected by economic
activity, capital expenditures by energy producers, weather, alternative energy sources, international events,
conservation and technological advances;
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throughput levels and rates;
changes in, or challenges to, our tariff rates;
our ability to successfully identify and close strategic acquisitions on acceptable terms (including obtaining third-
party consents and waivers of preferential rights), develop or construct infrastructure assets, make cost saving
changes in operations and integrate acquired assets or businesses into our existing operations;
service interruptions in our pipeline transportation systems, and processing operations;
shutdowns or cutbacks at refineries, petrochemical plants, utilities, individual plants or other businesses for which
we transport crude oil, petroleum, natural gas or other products or to whom we sell soda ash, petroleum or other
products;
risks inherent in marine transportation and vessel operation, including accidents and discharge of pollutants;
changes in laws and regulations to which we are subject, including tax withholding issues, regulations regarding
qualifying income, accounting pronouncements, and safety, environmental and employment laws and regulations;
the effects of production declines resulting from the suspension of drilling in the Gulf of Mexico and the effects of
future laws and government regulation resulting from the Macondo accident and crude oil spill in the Gulf;
planned capital expenditures and availability of capital resources to fund capital expenditures;
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 or to increase quarterly cash distributions in the
future;
an increase in the competition that our operations encounter;
cost and availability of insurance;
hazards and operating risks that may not be covered fully by insurance;
our financial and commodity hedging arrangements, which may reduce our earnings, profitability and cash flow;
changes in global economic conditions, including capital and credit markets conditions, inflation and interest
rates;
natural disasters, accidents or terrorism;
changes in the financial condition of customers or counterparties;
adverse rulings, judgments, or settlements in litigation or other legal or tax matters;
the treatment of us as a corporation for federal income tax purposes or if we become subject to entity-level
taxation for state tax purposes; and
the potential that our internal controls may not be adequate, weaknesses may be discovered or remediation of any
identified weaknesses may not be successful and the impact these could have on our unit price.
You should not put undue reliance on any forward-looking statements. When considering forward-looking statements,
please review the risk factors described under “Risk Factors” discussed in Item 1A. These risks may also be specifically
described in our Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and Form 8-K/A and other documents that
we may file from time to time with the SEC. Except as required by applicable securities laws, we do not intend to update these
forward-looking statements and information.
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Item 1. Business
General
PART I
We are a growth-oriented master limited partnership formed in Delaware in 1996. Our common units are traded on the
New York Stock Exchange, or NYSE, under the ticker symbol “GEL.” We are (i) a provider of an integrated suite of midstream
services - primarily transportation, storage, sulfur removal, blending, terminalling and processing - for a large area of the Gulf
Coast region of the crude oil and natural gas industry and (ii) the largest producer in the world of natural soda ash. Our sulfur
removal business results in us being the largest producer, we believe, in the world of sodium hydrosulfide (or NaHS,
pronounced “nash”).
Historically, a substantial majority of our focus has been on the midstream segment of the crude oil and natural gas
industry in the Gulf of Mexico, Gulf Coast region of the United States and Wyoming. We provide an integrated suite of services
to refiners, crude oil and natural gas producers, and industrial and commercial enterprises and have a diverse portfolio of assets,
including pipelines, offshore hub and junction platforms, refinery-related plants, storage tanks and terminals, railcars, rail
loading and unloading facilities, barges and other vessels, and trucks. On September 1, 2017, we acquired our trona and trona-
based exploring, mining, processing, producing, marketing and selling business based in Wyoming (our “Alkali Business”) for
approximately $1.325 billion in cash. Our Alkali Business mines and processes trona from which it produces natural soda ash,
also known as sodium carbonate (Na2CO3), a basic building block for a number of ubiquitous products, including flat glass,
container glass, dry detergent and a variety of chemicals and other industrial products. Our Alkali business has a diverse
customer base in the United States, Canada, the European Community, the European Free Trade Area and the South African
Customs Union with many long-term relationships. It has been operating for almost 70 years and has an estimated remaining
reserve life (based on 2017 production) of over 100 years. Within our legacy midstream business, we have two distinct,
complementary types of operations-(i) our onshore-based refinery-centric operations located primarily in the Gulf Coast region
of the U.S., which focus on providing a suite of services primarily to refiners, which includes our sulfur removal,
transportation, storage, and other handling services and (ii) our offshore Gulf of Mexico crude oil and natural gas pipeline
transportation and handling operations, which focus on providing a suite of services primarily to integrated and large
independent energy companies who make intensive capital investments to develop numerous large-reservoir, long-lived crude
oil and natural gas properties. Our onshore-based operations occur upstream of, at, and downstream of refinery complexes.
Upstream of refineries, we aggregate, purchase, gather and transport crude oil, which we sell to refiners. Within refineries, we
provide services to assist in sulfur removal/balancing requirements. Downstream of refineries, we provide transportation
services as well as market outlets for finished refined petroleum products and certain refining by-products. In our offshore
crude oil and natural gas pipeline transportation and handling operations, we provide services to one of the most active drilling
and development regions in the U.S.-the Gulf of Mexico, a producing region representing approximately 18% of the crude oil
production in the U.S. in 2017. Our legacy midstream business has a diverse portfolio of customers, operations and assets,
including pipelines, offshore hub and junction platforms, refinery-related plants, storage tanks and terminals, railcars, rail
loading and unloading facilities, barges and other vessels, and trucks.
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 18% of the oil produced in the U.S. in 2017,
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the largest producer and marketer (based on tons produced), we believe, of NaHS in North and South America,
the largest producer (based on tons produced) of natural soda ash in the world, and
one of the largest providers of crude oil and petroleum transportation, storage, and other handling services for
large, complex refineries in Baton Rouge, Louisiana and Baytown, Texas, both of which have been operational for
approximately 100 years.
We conduct our operations and own our operating assets through our subsidiaries and joint ventures. Our general
partner, Genesis Energy, LLC, a wholly-owned subsidiary that owns a non-economic general partner interest in us, has sole
responsibility for conducting our business and managing our operations. Our outstanding common units (including our Class B
common units), and our outstanding Class A convertible preferred units, representing limited partner interests, constitute all of
the economic equity interests in us.
We currently manage our businesses through four divisions that constitute our reportable segments - offshore pipeline
transportation, sodium minerals and sulfur services (which includes our newly acquired Alkali Business and our sulfur removal
business), onshore facilities and transportation and marine transportation. Our disclosures related to prior periods have been
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recast to reflect our reorganized segments as well as our revised approach to defining and presenting Non-GAAP measures.
For additional information, please review the section entitled "Financial Measures."
Offshore Pipeline Transportation Segment
We conduct our offshore crude oil and natural gas pipeline transportation and handling operations through our offshore
pipeline transportation segment, which focuses on providing a suite of services to integrated and large independent energy
companies who make intensive capital investments (often in excess of billions of dollars) to develop numerous large-reservoir,
long-lived crude oil and natural gas properties in the Gulf of Mexico, primarily offshore Texas, Louisiana, Mississippi and
Alabama. This segment provides services to one of the most active drilling and development regions in the U.S.—the Gulf of
Mexico, a producing region representing approximately 18% of the crude oil production in the U.S. in 2017. Even though
those large-reservoir properties and the related pipelines and other infrastructure needed to develop them are capital intensive,
we believe they are generally much less sensitive to short-term commodity price volatility, particularly once a project has been
sanctioned. Due to the size and scope of these activities, our customers are predominantly large integrated oil companies and
large independent crude oil producers.
We own interests in various offshore crude oil and natural gas pipeline systems, platforms and related infrastructure.
We own interests in approximately 1,431 miles of crude oil pipelines with an aggregate design capacity of approximately 1,800
MBbls per day, a number of which pipeline systems are substantial and/or strategically located. For example, we own a 64%
interest in the Poseidon pipeline system and 100% of the Cameron Highway pipeline system, or CHOPS, which is one of the
largest crude oil pipelines (in terms of both length and design capacity) located in the Gulf of Mexico. We also own 100% of
the Southeast Keathley Canyon Pipeline Company, LLC ("SEKCO"), which is a deepwater pipeline servicing the Lucius field
in the southern Keathley Canyon area of the Gulf of Mexico.
Our interests in offshore natural gas pipeline systems and related infrastructure includes approximately 977 miles of
pipe with an aggregate design capacity of approximately 3,413 MMcf per day. We also own an interest in five offshore hub
platforms with aggregate processing capacity of approximately 711 MMcf per day of natural gas and 159 MBbls per day of
crude oil.
Our offshore pipelines generate cash flows from fees charged to customers or substantially similar arrangements that
otherwise limit our direct exposure to changes in commodity prices. Each of our offshore pipelines currently has significant
available capacity to accommodate future growth in the fields from which the production is dedicated to that pipeline, including
fields that have yet to commence production activities, as well as volumes from non-dedicated fields.
Sodium Minerals and Sulfur Services Segment
This segment includes operations of our new Alkali Business and our sulfur removal business.
Our Alkali business owns the largest leasehold position of accessible trona ore reserves in the Green River trona patch,
a geological formation holding the vast majority of the world’s accessible trona ore reserves. Our Alkali Business holds leases
covering approximately 88,000 acres of land, containing an estimated 830 million metric tonnes of proved and probable
reserves of trona ore, representing an estimated remaining reserve life of over 100 years based on its 2017 production rate,
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 trona patch for almost 70 years.
All of our Alkali Business’ mining and processing activities are conducted at its “Westvaco” and “Granger” facilities in
Wyoming. Utilizing our two facilities near Green River, WY, our Alkali Business involves the mining of trona ore, processing
the trona ore into soda ash, also known as sodium carbonate (Na2Co3), and the marketing, selling and distribution of the soda
ash and specialty products.
We sell our soda ash and specialty products to a diverse customer base directly in the United States, Canada, the
European Community, the European Free Trade Area and the South African Customs Union. Our Alkali Business also sells
through the American Natural Soda Ash Corporation, or ANSAC, exclusively in all other markets. ANSAC is a nonprofit
foreign sales association of which our Alkali Business and two other U.S. soda ash producers are members, whose purpose is to
promote export sales of U.S. produced soda ash in conformity with the Webb-Pomerene Act. ANSAC is our Alkali Business’
largest customer. See Note 14 for a further discussion of ANSAC.
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. The global market in which our Alkali
Business operates is competitive. Competition is based on a number of factors such as price, favorable logistics and consistent
customer service. In North America, primary competition is from other U.S.-based natural soda ash operations: Solvay
Chemicals, Ciner Resources, L.P., Tata Chemicals Soda Ash Partners in Wyoming, and Searles Valley Minerals, in California.
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As part of our sulfur removal business, we primarily (i) provide services to ten refining operations located mostly in
Texas, Louisiana, Arkansas, Oklahoma, Montana and Utah; (ii) operate significant storage and transportation assets in relation
to those services; and (iii) sell NaHS and NaOH (also known as caustic soda) to large industrial and commercial companies.
Our sulfur removal services primarily involve processing refiners’ high sulfur (or “sour”) gas streams to remove the sulfur. Our
sulfur removal services footprint also includes NaHS and caustic soda terminals, and we utilize railcars, ships, barges and
trucks to transport product. Our sulfur removal services contracts are typically long-term in nature and have an average
remaining term of five years. NaHS is a by-product derived from our refinery sulfur removal services process, and it constitutes
the sole consideration we receive for these services. A majority of the NaHS we receive is sourced from refineries owned and
operated by large companies, including Phillips 66, CITGO, HollyFrontier, Calumet and Ergon. We sell our NaHS to customers
in a variety of industries, with the largest customers involved in mining of base metals, primarily copper and molybdenum, and
the production of pulp and paper. We believe we are one of the largest marketers of NaHS in North and South America.
Onshore Facilities and Transportation Segment
Our onshore facilities and transportation segment owns and/or leases our increasingly integrated suite of onshore crude
oil and refined products infrastructure, including pipelines, trucks, terminals, railcars, and rail loading and unloading facilities.
It uses those assets, together with other modes of transportation owned by third parties and us, to service its customers and for
its own account. The increasingly integrated nature of our onshore facilities and transportation assets is particularly evident in
certain of our recently completed or ongoing growth initiatives in areas such as Louisiana, Texas and Wyoming.
We own five onshore crude oil pipeline systems, with approximately 600 miles of pipe located primarily in Alabama,
Florida, Louisiana, Mississippi, Texas and Wyoming. The Federal Energy Regulatory Commission, or FERC, regulates the
rates charged by five of our onshore systems to their customers. The rates for the other onshore pipeline are regulated by the
Railroad Commission of Texas. Our onshore pipelines generate cash flows from fees charged to customers. Each of our
onshore pipelines has significant available capacity to accommodate potential future growth in volumes.
We own five operational crude oil rail loading/unloading facilities located in Baton Rouge, Louisiana; Raceland,
Louisiana; Walnut Hill, Florida; Natchez, Mississippi and Douglas, Wyoming which provide synergies to our existing asset
footprint. We generally earn a fee for loading or unloading railcars at these facilities. Four of these facilities, our Baton Rouge,
Louisiana, Raceland, Louisiana, Walnut Hill, Florida, and Douglas, Wyoming facilities are directly connected to our existing
integrated crude oil pipeline and terminal infrastructure. 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. In addition to the
above, we have access to a suite of more than 200 trucks, 400 trailers, 504 railcars, and terminals and tankage with 4.6 million
barrels of storage capacity (excluding capacity associated with our common carrier crude oil pipelines) in multiple locations
along the Gulf Coast.
We own two CO2 pipelines with approximately 270 miles of pipe. We have leased our NEJD System, comprised of
183 miles of pipe in North East Jackson Dome, Mississippi, to an affiliate of an independent crude oil company through 2028.
We receive a fixed quarterly payment under the NEJD arrangement. That company also has the exclusive right to use our Free
State pipeline, comprised of 86 miles of pipe, pursuant to a transportation agreement that expires in 2028. Payments on the Free
State pipeline are subject to an "incentive" tariff which provides that the average rate per mcf that we charge during any month
decreases as our aggregate throughput for that month increases above specified thresholds.
Marine Transportation Segment
We own a fleet of 89 barges (80 inland and 9 offshore) with a combined transportation capacity of 3.1 million barrels
and 42 push/tow boats (33 inland and 9 offshore). Our marine transportation segment is a provider of transportation services
by tank barge primarily for refined petroleum products, including heavy fuel oil and asphalt, as well as crude oil. Refiners
accounted for over 80% of our marine transportation volumes for 2017.
We also own the M/T American Phoenix, an ocean going tanker with 330,000 barrels of cargo capacity. The M/T
American Phoenix is currently transporting refined products.
We are a provider of transportation services for our customers and, in almost all cases, do not assume ownership of the
products that we transport. Most of 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. For more information
regarding our charter arrangements, please refer to the marine transportation segment discussion below. All of our vessels
operate under the U.S. flag and are qualified for domestic trade under the Jones Act.
Our Objectives and Strategies
Our primary objective continues to be to generate and grow stable cash flows while never wavering from our
commitment to safe and responsible operations. We recently made the strategic decision to re-set our quarterly distribution and
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provided a plan for visible, achievable long term distribution growth and a clear path forward to deleveraging. We believe these
steps, along with the future stable and repeatable cash flows from the acquisition of our Alkali Business as well as the
anticipated ramp from our recent strategic investments, provide a clear path forward to deleveraging and further enhancing our
financial flexibility to opportunistically pursue accretive organic projects and acquisitions should they present themselves.
Business Strategy
Our primary business strategy is to provide an integrated suite of services to refiners, crude oil and natural gas
producers, and industrial and commercial enterprises. Successfully executing this strategy should enable us to generate and
grow stable cash flows.
On September 1, 2017, we acquired our Alkali Business, which is the world’s largest producer of natural soda ash.
Natural soda ash accounts for approximately 25% of the world’s production of soda ash. We believe the significant cost
advantage in the production of natural soda ash over synthetically produced soda ash will remain for the foreseeable future,
somewhat mitigating the effects of market specific factors in the soda ash market in which we operate.
Within our legacy midstream business, we have two distinct, complementary types of operations: (i) our onshore-
based crude oil and refined petroleum products transportation, onshore facilities and transportation, and handling operations,
focusing predominantly on refinery-centric customers (as opposed to producers), and (ii) our offshore Gulf of Mexico crude oil
and natural gas pipeline transportation and handling operations, focusing on integrated and large independent energy companies
who make intensive capital investments to develop numerous large-reservoir, long-lived crude oil and natural gas properties. In
2016, refiners were the shippers of approximately 80% of the volumes transported on our onshore crude pipelines, and refiners
contract for over 80% of the use of our inland barges, which are used primarily to transport intermediate refined products (not
crude oil) between refining complexes. The integrated and large independent energy companies that use our offshore oil
pipelines produce oil that is ideally suited for the vast majority of refineries along the Gulf Coast, unlike the lighter crude oil
and condensates produced from numerous onshore shale plays.
We intend to develop our business by:
•
Identifying and exploiting incremental profit opportunities, including cost synergies, across an increasingly integrated
footprint;
• Optimizing our existing assets and creating synergies through additional commercial and operating advancement;
• Leveraging customer relationships across business segments;
• Attracting new customers and expanding our scope of services offered to existing customers;
• Expanding the geographic reach of our businesses;
• Economically expanding our pipeline and terminal operations;
• 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 through our recently announced plan to provide long term
distribution growth and a clear path forward to deleveraging; and
• Create strategic arrangements and share capital costs and risks through joint ventures and strategic alliances.
Competitive Strengths
We believe we are well positioned to execute our strategies and ultimately achieve our objectives due primarily to the
following competitive strengths:
• Our businesses encompass a balanced, diversified portfolio of customers, operations and assets. We operate four
business segments and own and operate assets that enable us to provide a number of services primarily to refiners,
crude oil and natural gas producers, and industrial and commercial enterprises that use natural soda ash, NaHS and
8
caustic soda. Our business lines complement each other by allowing us to offer an integrated suite of services to
common customers across segments. Our businesses are primarily focused on (i) providing offshore crude oil and
natural gas pipeline transportation and related handling services in the Gulf of Mexico to mostly integrated and large
independent energy companies (ii) producing sodium minerals and (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 18% of the oil produced in the U.S. in 2017. We are the largest producer (based on tons
produced) of natural soda ash in the world. We believe we are the largest producer and marketer (based on tons
produced) of NaHS in North and South America. We are one of the largest providers of crude oil and petroleum
product transportation, storage and other handling services for large, complex refineries in Baton Rouge, Louisiana
and Baytown, Texas, both of which have been operational for approximately 100 years.
• Our Alkali Business has significant cost advantages over synthetic production methods. Our Alkali Business has
significant cost advantages over synthetic production methods, including lower raw material and energy requirements.
According to IHS, on average, the cash cost to produce material soda ash has been about half of the cost to produce
synthetic soda ash.
• Our businesses provide relatively consistent consolidated financial performance. Our historically consistent and
improving financial performance, combined with our goal of a conservative capital structure over the long term, has
allowed us to generate relatively stable and increasing cash flows.
• We are financially flexible and have significant liquidity. As of December 31, 2017, we had $599.8 million available
under our $1.7 billion revolving credit agreement, including up to $171.0 million available under the $200 million
petroleum products inventory loan sublimit and $99.0 million available for letters of credit. Our inventory borrowing
base was $29.0 million at December 31, 2017.
• We have limited direct commodity price risk exposure in our oil and gas and NaHS businesses. The volumes of crude
oil, refined products or intermediate feedstocks we purchase are either subject to back-to-back sales contracts or are
hedged with NYMEX derivatives to limit our direct exposure to movements in the price of the commodity, although
we cannot completely eliminate commodity price exposure. Our risk management policy requires us to monitor the
effectiveness of the hedges to maintain a value at risk of such hedged inventory not in excess of $2.5 million. In
addition, our service contracts with refiners allow us to adjust the rates we charge for processing to maintain a balance
between NaHS supply and demand.
• Our offshore Gulf of Mexico crude oil and natural gas pipeline transportation and handling operations are located in
a significant producing region with large-reservoir, long-lived crude oil and natural gas properties. We provide a
suite of services, primarily to integrated and large independent energy companies who make intensive capital
investments to develop numerous large-reservoir, long-lived crude oil and natural gas properties, in one of the most
active drilling and development regions in the U.S.-the Gulf of Mexico, a producing region representing
approximately 18% of the crude oil production in the U.S. in 2017.
• 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.
9
• We have an experienced, knowledgeable and motivated executive management team with a proven track record. Our
executive management team has an average of more than 25 years of experience in the midstream sector. Its members
have worked in leadership roles at a number of large, successful public companies, including other publicly-traded
partnerships. Through their equity interest in us, our executive management team is incentivized to create value by
increasing cash flows.
Recent Developments and Status of Certain Growth Initiatives
The following is a brief listing of developments since December 31, 2016. Additional information regarding most of
these items may be found elsewhere in this report.
Alkali Business Acquisition
On September 1, 2017, we acquired our trona and trona-based exploring, mining, processing, producing, marketing
and selling business based in Wyoming (our “Alkali Business”) for approximately $1.325 billion in cash. Our Alkali Business
produces natural soda ash, also known as sodium carbonate (Na2CO3), a basic building block for a number of ubiquitous
products, including flat glass, container glass, dry detergent and a variety of chemicals and other industrial products. Our
Alkali business has a diverse customer base in the United States, Canada, the European Community, the European Free Trade
Area and the South African Customs Union with many long-term relationships. It has been operating for almost 70 years and
has an estimated remaining reserve life (based on 2017 production) of over 100 years. Our Alkali business owns the largest
leasehold position of accessible trona ore reserves in the Green River trona patch, a geological formation holding the vast
majority of the world’s accessible trona ore reserves As a result of this acquisition, we are the world's leading producer of
natural soda ash, which has significant cost advantages over synthetically produced soda ash.
To finance that transaction and the related costs, we used proceeds from (i) a $550.0 million public offering
of 6.50% senior unsecured notes due 2025 in August 2017, generating net proceeds of $540.1 million after issuance discount
and underwriting fees, (ii) a $750 million private placement of Class A Convertible Preferred units in September 2017,
generating net proceeds of $726.2 million, (iii) borrowings under our revolving credit facility and (iv) cash on hand.
Baton Rouge Area Infrastructure Expansion
We are currently expanding our existing Baton Rouge area infrastructure to allow for greater capacity and flexibility in
servicing our major refinery customer in the region. This expansion includes the construction of an additional 500,000 barrels
of crude oil tankage at our existing Baton Rouge Terminal. Additionally, this expansion will include the upgrading of pumping
and other infrastructure capabilities in order to allow for the efficient handling of expected increases in crude oil volumes
received at our Baton Rouge area facilities. We expect these assets to become operational in the first half of 2018.
Wyoming Infrastructure Expansion
We have recently begun construction of a new gathering system to connect crude oil production to our existing Powder
River basin pipeline infrastructure. This new gathering system is supported by a new long-term contract with one of the leading
operators in the Powder River basin. The operator will dedicate approximately 150,000 acres to the new gathering system and a
total of 300,000 acres to our Powder River basin pipeline infrastructure for a period of ten years, including approximately
150,000 acres that had previously been dedicated. We expect the new gathering system to become operational throughout 2018
depending on the pace of upstream activity.
Houston Area Crude Oil Pipeline and Terminal Infrastructure
We have constructed new, and expanded existing, crude oil pipeline and terminal facilities in Webster, Texas and Texas
City, Texas as a result of expanding our crude oil pipeline and terminal infrastructure in the Houston area. We have also
constructed a new crude oil pipeline that delivers crude oil received from upstream crude oil pipelines (including CHOPS,
which delivers crude oil originating in the deepwater Gulf of Mexico to the Texas City area) to our new Texas City Terminal,
which connects to our existing 18-inch Webster to Texas City crude oil pipeline. Our new Texas City Terminal includes
approximately 750,000 barrels of crude oil tankage. As a part of this project, we have also made the necessary upgrades on our
existing 18-inch Webster to Texas City crude oil pipeline to reverse the direction of flow. The result of this expanded crude oil
infrastructure allows additional optionality to Houston and Baytown area refineries, including the ExxonMobil Baytown
refinery, its largest refinery in the U.S.A., and provides additional delivery outlets for other crude oil pipelines. These assets
became operational in the second quarter of 2017.
10
Raceland Terminal and Crude Oil Pipeline
We have constructed a new crude oil terminal and pipeline in Raceland, Louisiana that connects to existing midstream
infrastructure to provide further distribution to the Louisiana refining markets. Our new Raceland Terminal consists of 515,000
barrels of crude oil tankage and unit train unloading facilities capable of unloading up to two unit trains per day. We have also
constructed a new crude oil pipeline that will deliver crude oil received from the Poseidon system, which currently delivers
crude oil originating in the deepwater Gulf of Mexico to the Houma, Louisiana area, to our new Raceland Terminal for further
distribution. These assets became fully operational at the end of the second quarter of 2017.
Inland Marine Barge Transportation Expansion
In 2016, we ordered 28 new-build barges and 18 new-build push boats for our inland marine barge transportation fleet.
Through December 31, 2017, we had periodically accepted delivery of all but two barges. We expect to take delivery of those
remaining vessels in 2018.
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, 2017.
Description of Segments and Related Assets
We conduct our businesses through four operating segments: offshore pipeline transportation, sodium minerals and
sulfur services, onshore facilities and transportation and marine transportation. These segments are strategic business units that
provide a variety of energy-related services. Financial information with respect to each of our segments can be found in Note
13 to our Consolidated Financial Statements in Item 8.
We have a diverse portfolio of customers, operations and assets, including pipelines, refinery-related plants, storage
tanks and terminals, railcars, rail loading and unloading facilities, barges and other vessels, and trucks. Substantially all of our
revenues are derived from providing services to refiners, integrated and large independent crude oil and natural gas companies,
and large industrial and commercial enterprises. Our onshore-based operations, excluding those associated with our Alkali
Business, occur upstream of, at, and downstream of refinery complexes. Upstream of refineries, we aggregate, purchase,
gather and transport crude oil, which we sell to refiners. Within refineries, we provide services to assist in sulfur removal/
11
balancing requirements. Downstream of refineries, we provide transportation services as well as market outlets for finished
refined petroleum products and certain refining byproducts. Within our Alkali Business, we sell our soda ash and specialty
products to a diverse customer base directly in the United States, Canada, the European Community, the European Free Trade
Area and the South African Customs Union.
Offshore Pipeline Transportation
Offshore Crude Oil and Natural Gas Pipelines
We own interests in several crude oil and natural gas pipelines and related infrastructure located offshore in the Gulf of
Mexico, a producing region representing approximately 18% of the crude oil production in the U.S. in 2017.
The table below reflects our interests in our operating offshore crude oil pipelines:
Offshore crude oil
pipelines
Operator
System
Miles
Design
Capacity
(Bbls/day) (1)
Interest
Owned
Throughput
(Bbls/day)
100% basis
Throughput
(Bbls/day) net
to ownership
interest
Main Lines
CHOPS
Poseidon
Odyssey
Eugene Island
Pipeline and Other
Total
Lateral Lines (2)
SEKCO
Shenzi Crude Oil
Pipeline
Allegheny Crude Oil
Pipeline
Marco Polo Crude
Oil Pipeline
Constitution Crude
Oil Pipeline
Tarantula
Genesis
Genesis
Shell
Pipeline
Genesis/
Shell
Pipeline
380
367
120
184
1,051
500,000
350,000
100%
64%
213,527
253,547
213,527
162,270
200,000
29%
116,408
33,758
39,000
29%
1,089,000
8,185
591,667
8,185
417,740
Genesis
149
115,000
100%
Genesis
Genesis
Genesis
Genesis
Genesis
83
40
37
67
4
230,000
100%
140,000
100%
120,000
100%
80,000
30,000
100%
100%
(1) Capacity figures presented represent 100% of the design capacity; except for Eugene Island, which represents our net capacity in
the undivided interest (29%) in that system. Ultimate capacities can vary primarily as a result of pressure requirements, installed
pumps, related facilities and the viscosity of the crude oil actually moved.
(2) Represents 100% owned lateral crude oil pipelines which, ultimately flow into our other offshore crude oil pipelines (including
CHOPS and Poseidon) and thus are excluded from main lines above.
• CHOPS. CHOPS is comprised of 24- to 30-inch diameter pipelines designed to deliver crude oil from fields in the
Gulf of Mexico to refining markets along the Texas Gulf Coast via interconnections with refineries located in Port
Arthur and Texas City, Texas. CHOPS also includes two strategically located multi-purpose offshore platforms.
• Poseidon. The Poseidon system is comprised of 16- to 24-inch diameter pipelines to deliver crude oil from
developments in the central and western offshore Gulf of Mexico to other pipelines and terminals onshore and offshore
Louisiana. An affiliate of Shell owns the remaining 36% interest in Poseidon.
• Odyssey. The Odyssey system is comprised of 12- to 20-inch diameter pipelines to deliver crude oil from
developments in the eastern Gulf of Mexico to other pipelines and terminals onshore Louisiana. An affiliate of Shell
owns the remaining 71% interest in Odyssey.
• Eugene Island. The Eugene Island system is comprised of a network of crude oil pipelines, the main pipeline of which
is 20 inches in diameter, to deliver crude oil from developments in the central Gulf of Mexico to other pipelines and
12
•
•
terminals onshore Louisiana. Other owners in Eugene Island include affiliates of Exxon Mobil, ConocoPhillips and
Shell Oil Company.
SEKCO Pipeline. SEKCO is a deepwater pipeline serving the Lucius crude oil and natural gas field located in the
southern Keathley Canyon area of the Gulf of Mexico. SEKCO has crude oil transportation agreements with five Gulf
of Mexico producers, including Anadarko U.S. Offshore Corporation, Exxon Mobil Corporation, Eni Petroleum US
LLC, Petrobras America and Inpex Corporation. Those producers have dedicated their production from Lucius to that
pipeline for the life of the reserves. We expect the SEKCO pipeline to also provide capacity for additional projects in
the deepwater Gulf of Mexico in the future.
Shenzi Crude Oil. The Shenzi Crude Oil Pipeline gathers crude oil production from the Shenzi production field located
in the Green Canyon area of the Gulf of Mexico offshore Louisiana for delivery to both our CHOPS and Poseidon
pipeline systems.
• Allegheny Crude Oil. The Allegheny Crude Oil Pipeline connects the Allegheny and South Timbalier 316 platforms in
the Green Canyon area of the Gulf of Mexico with the CHOPS and Poseidon pipelines.
• Marco Polo Crude Oil. The Marco Polo Crude Oil Pipeline transports crude oil from our Marco Polo crude oil
platform to an interconnect with the Allegheny Crude Oil Pipeline in Green Canyon Block 164.
• Constitution Crude Oil. The Constitution Crude Oil Pipeline gathers crude oil from the Constitution, Caesar Tonga and
Ticonderoga production fields located in the Green Canyon area of the Gulf of Mexico for delivery to either the
CHOPS or Poseidon pipelines.
None of our offshore crude oil pipelines are rate regulated with the exception of Eugene Island, which is regulated by
the FERC.
The table below reflects our interests in our operating offshore natural gas pipelines:
Offshore natural gas pipelines
Operator
System Miles
Design Capacity
(MMcf/day) (1)
Interest
Owned
Independence Trail
High Island Offshore System
Anaconda Gathering System
Green Canyon Laterals
Manta Ray Offshore Gathering
System
Nautilus System
Total
Genesis
Genesis
Genesis
Genesis
Enbridge
Enbridge
135
287
183
34
237
101
977
1,000
500
300
213
800
600
3,413
100%
100%
100%
Various (2)
25.7%
25.7%
(1) Capacity figures presented represent 100% of the design capacity.
(2) We proportionately consolidate our undivided interests, which range from 2.7% to 33.3%, in 28 miles of the Green Canyon Lateral
pipelines. The remainder of the laterals are wholly owned.
•
Independence Trail. The Independence Trail pipeline transports natural gas from certain pipeline interconnects to the
Tennessee Gas Pipeline at a pipeline interconnect on the West Delta 68 pipeline junction platform. Natural gas
transported on the Independence Trail Pipeline can originate from production fields in the Atwater Valley, DeSoto
Canyon, Lloyd Ridge and Mississippi Canyon areas of the Gulf of Mexico.
• High Island. The High Island Offshore System (HIOS) transports natural gas from producing fields located in the
Galveston, Garden Banks, West Cameron, High Island and East Breaks areas of the Gulf of Mexico to interconnects
with the Kinetica Energy Express. HIOS includes 201 miles of pipeline and eight pipeline junction and service
platforms that are regulated by the FERC. In addition, this system included the 86-mile East Breaks Gathering
System, which connects HIOS to the Hoover-Diana deepwater platform located in Alaminos Canyon Block 25.
• Anaconda. The Anaconda Gathering System gathers natural gas from producing fields located in the Green Canyon
area of the Gulf of Mexico for delivery to the Nautilus System.
• Green Canyon. The Green Canyon Laterals represent a collection of small diameter pipelines that gather natural gas
for delivery to HIOS and various other downstream pipelines.
• Manta Ray. The Manta Ray Offshore Gathering System gathers natural gas from producing fields located in the Green
Canyon, Southern Green Canyon, Ship Shoal, South Timbalier and Ewing Bank areas of the Gulf of Mexico for
13
delivery to numerous downstream pipelines, including the Nautilus System. This system includes three pipeline
junction platforms.
• Nautilus. The Nautilus System connects the Anaconda Gathering system and Manta Ray Offshore Gathering System to
the Neptune natural gas processing plant located in south Louisiana.
Offshore Hub Platforms
Offshore Hub platforms are typically used to interconnect the offshore pipeline network; provide an efficient means to
perform pipeline maintenance; locate compression, separation and production handling equipment and similar assets; and
conduct drilling operations during the initial development phase of a crude oil and natural gas property. The results of
operations from offshore platform services are primarily dependent upon the level of commodity charges and/or demand-type
fees billable to customers. Revenue from commodity charges is based on a fee per unit of volume delivered to the platform
(typically per MMcf of natural gas or per barrel of crude oil) multiplied by the total volume of each product delivered.
Demand-type fees are similar to firm capacity reservation agreements for a pipeline in that they are charged to a customer
regardless of the volume the customer actually delivers to the platform. Contracts for platform services often include both
demand-type fees and commodity charges, but demand-type fees generally expire after a contractually fixed period of time and
in some instances may be subject to cancellation by customers.
The table below reflects our interests in our operating offshore hub platforms:
Offshore hub platform
Marco Polo
Garden Banks 72 (2)
East Cameron 373
Total
Operator
Anadarko
Genesis
Genesis
Water
Depth (Feet)
Natural Gas
Capacity (MMcf/
day) (1)
Crude Oil
Capacity (Bbls/
day) (1)
Interest
Owned
4,300
518
441
300
216
195
711
120,000
36,000
3,000
159,000
100%
50%
100%
(1) Capacity figures presented represent 100% of the design capacity.
(2) We proportionately consolidate our undivided interest in the Garden Banks 72 platform.
• Marco Polo. The Marco Polo platform, which is located in Green Canyon Block 608, processes crude oil and natural
gas from production fields located in the South Green Canyon area of the Gulf of Mexico.
• Garden Banks. The Garden Banks 72 platform serves as a base for gathering deepwater production from the Garden
Banks area of the Gulf of Mexico. This platform also serves as a junction platform for the CHOPS and Poseidon
pipeline systems.
• East Cameron. The East Cameron 373 platform processes production from the Garden Banks and East Cameron areas
of the Gulf of Mexico.
Customers
Due to the cost of finding, developing and producing crude oil properties in the deepwater regions of the Gulf of
Mexico, most of our offshore pipeline customers are integrated crude oil companies and other large producers, and those
producers desire to have longer-term arrangements ensuring that their production can access the markets.
Usually, our offshore crude oil pipeline customers enter into buy-sell or other transportation arrangements, pursuant to
which the pipeline acquires possession (and, sometimes, title) from its customer of the relevant production at a specified
location (often a producer’s platform or at another interconnection) and redelivers possession (and title, if applicable) to such
customer of an equivalent volume at one or more specified downstream locations (such as a refinery or an interconnection with
another pipeline). Most of the production handled by our offshore pipelines is pursuant to life-of-reserve commitments that
include both firm and interruptible capacity arrangements.
Revenues from customers of our offshore pipeline transportation segment did not account for more than ten percent of
our consolidated revenues.
14
Competition
The principal competition for our offshore pipelines includes other crude oil and natural gas pipeline systems as well
as producers who may elect to build or utilize their own production handling facilities. Our offshore pipelines compete for new
production on the basis of geographic proximity to the production, cost of connection, available capacity, transportation rates
and access to onshore markets. In addition, the ability of our offshore pipelines to access future reserves will be subject to our
ability, or the producers’ ability, to fund the significant capital expenditures required to connect to the new production. In
general, most of our offshore pipelines are not subject to regulatory rate-making authority, and the rates our offshore pipelines
charge for services are dependent on the quality of the service required by the customer and the amount and term of the reserve
commitment by that customer.
Sodium Minerals and Sulfur Services
Our Sodium Minerals and Sulfur Services segment consists of our legacy sulfur removal business, as well as those of
our newly acquired Alkali Business as discussed in further detail below.
Alkali Business
Our Alkali Business is the world’s largest natural soda ash producer. We provide our soda ash to a variety of industries
such as flat glass, container glass, detergent and chemical manufacturing. Soda ash, also known by its chemical name sodium
carbonate (Na2CO3), is a highly valued raw material in the manufacture of glass due to its properties of lowering the melting
point of silica in the batch. Soda ash is also valued by detergent manufacturers for its absorptive and water softening properties.
We produce our products from trona, which we mine at two sites in the Green River Basin, Wyoming. The vast majority of the
world’s accessible trona reserves are located in the Green River Basin. According to historical production statistics,
approximately one-quarter of global soda ash is produced from trona, with the remainder being produced synthetically, which
requires chemical transformation of limestone and salt using a significantly higher amount of energy. Production of soda ash
from trona is significantly less expensive than producing it synthetically. In addition, life-cycle analyses reveal that production
from trona consumes less energy and produces less carbon dioxide and fewer undesirable by-products than synthetic
production.
Our Alkali segment includes the following:
• Dry mining of trona ore underground at our Westvaco facility;
•
Secondary recovery of trona from previously dry mined areas underground at our Westvaco and Granger facilities
through solution mining;
•
Processing of raw trona ore into soda ash and specialty sodium alkali products; and
• Marketing, sale and distribution of alkali products.
Our Alkali segment currently produces approximately 4 million tons of soda ash and downstream specialty products. All
mining and processing activities related to our products take place in our facilities located in the Green River Basin of
Wyoming, United States.
Dry mining of Trona Ore
Trona is dry mined underground at our Westvaco facility primarily through the operation of our single longwall mining
machine. Longwall mining provides higher recovery rates leading to extended mine life compared to other dry mining
techniques. Development of the “tunnels” necessary to access and ventilate our longwall is through room and pillar mining
completed primarily by our fleet of borer miners. The ore is conveyed underground to two hoisting operations where it travels
about 1,600 feet vertically to the surface and is either taken directly into the processing facilities or stored on outdoor stockpiles
for future consumption.
Secondary Recovery Solution Mining
We solution mine trona at both our Westvaco and Granger sites using secondary recovery techniques. Our secondary
recovery mining starts with the recovery of water streams from our operations and non-trona solids (“insolubles”) remaining
from the processing of dry mined trona. The water and some insolubles are injected through a number of wells into the old dry
mine workings at both our Westvaco and Granger sites. The insolubles settle out while the water travels through the old
15
workings, dissolving trona that remained during previous dry mining. Multiple pumping systems are used to pump the enriched
solution to the surface for processing.
Processing of Trona into Finished Alkali Products
Our Sesqui and Mono plants, located at our Westvaco site, convert dry-mined trona into soda ash. Crushing, dissolution
in water, filtration, and crystallization techniques are used to produce the desired final products. In the Mono process, the ore is
calcined with heat, prior to dissolution, to convert the trona to soda ash by the removal of water and carbon dioxide. A final
drying step using steam produces a dense soda ash product from the Mono process. In our Sesqui plant, the calcination is
performed at the end of the process, producing a light density soda ash that is preferred in applications desiring increased
absorptivity. The Sesqui process also has the ability to produce refined sodium sesquicarbonate (which we sell under the names
S-Carb ® and Sesqui™) for use as a buffer in animal feed formulations and in cleaning and personal care applications.
Solution mined trona is converted into dense soda ash in our ELDM operation at the Westvaco site and at our Granger
facility. The steps to produce soda ash are similar to the dry mined processes, except the crushing and dissolving steps are
eliminated because the trona is already in a water solution as it leaves the mine.
Intermediate, semi-processed products are extracted from our soda ash processes at Westvaco at strategic locations for
use as feedstocks for production of sodium bicarbonate and 50% caustic soda (NaOH).
Marketing, Sale and Distribution of Alkali Products
We sell our alkali products to customers directly in the United States, Canada, the European Community, the European
Free Trade Area and the South African Customs Union. We sell through ANSAC exclusively in all other markets. ANSAC is a
nonprofit foreign sales association in which we and two other U.S. soda ash producers are members, whose purpose is to
promote export sales of U.S. produced soda ash in conformity with the Webb-Pomerene Act.
All of our alkali products are shipped by rail and truck from our facilities in the Green River Basin. We operate a fleet of
nearly 3,200 covered hopper cars which we use to deliver nearly 90% of the sales of alkali products from the Green River
facilities, all of which are shipped via a single rail line owned and operated by Union Pacific Railroad. We lease these railcars
from banks and leasing companies and from FMC Corporation under agreements with varying term-lengths. We recover costs
of leasing through mileage credits paid under agreements with customers and carriers in accordance with established industry
practices and government requirements.
We sell most of our Alkali products as soda ash. Soda ash is the only product we sell to ANSAC. Soda ash is highly
valued by manufacturers of flat and container glass because it lowers the temperature of the batch in a glass furnace. It is also
valued by detergent manufacturers for its absorptive qualities. Demand for soda ash in the United States has been relatively flat
over the last five years. Sales of soda ash in rapidly developing economies have grown more rapidly as a growing middle class
demands more products that use soda ash, such as glass for housing and autos and detergents for cleaning.
In addition, we also market sodium bicarbonate to private label manufacturers who package it for sale to retail grocery
customers as baking soda. We also sell sodium bicarbonate to manufacturers of packaged baked goods and similar products.
Animal feed is an important market for sodium bicarbonate, which is mixed with feed to increase the yield of dairy cows and
improve the health of poultry and other livestock. Sodium bicarbonate is also sold to customers who use it in hemodialysis
applications and as an active ingredient in pharmaceutical products.
Sulfur Removal Business
Our sodium minerals and sulfur services segment, through our legacy sulfur removal business, primarily (i) provides
sulfur-extraction services to ten refining operations located mostly in Texas, Louisiana, Arkansas, Oklahoma, Montana and
Utah, (ii) operates significant storage and transportation assets in relation to those services and (iii) sells NaHS and caustic soda
to large industrial and commercial companies. Our sulfur removal services primarily involve processing refiners' high sulfur (or
“sour”) gas streams that the refineries have generated from crude oil processing operations. Our process applies our proprietary
technology, which uses large quantities of caustic soda (the primary raw material used in our process) to act as a scrubbing
agent under prescribed temperature and pressure to remove sulfur. Sulfur removal in a refinery is a key factor in optimizing
production of refined products such as gasoline, diesel and aviation fuel. Our sulfur removal technology returns a clean (sulfur-
free) hydrocarbon stream to the refinery for further processing into refined products, and simultaneously produces NaHS. The
resultant NaHS constitutes the sole consideration we receive for our sulfur removal services. A majority of the NaHS we
receive is sourced from refineries owned and operated by large companies, including Phillips 66, CITGO, HollyFrontier,
Calumet and Ergon. Our ten sulfur removal services contracts have an average remaining life of five years. This includes the
extended term of our recently renegotiated sulfur removal services contract with Phillips 66 at our Westlake, Louisiana facility,
which now extends through 2026. The timing upon which these contracts renew vary based upon location and terms specified
within each specific contract.
Our sodium minerals and sulfur services footprint includes NaHS and caustic soda terminals in the Gulf Coast, the
Midwest, Montana, Utah, British Columbia and South America. In conjunction with our onshore facilities and transportation
16
segment, we sell and deliver (via railcars, ships, barges and trucks) NaHS and caustic soda to approximately 150 customers. We
believe we are one of the largest marketers of NaHS in North and South America. By minimizing our costs through utilization
of our own logistical assets and leased storage sites, we believe we have a competitive advantage over other suppliers of NaHS.
NaHS is used in the specialty chemicals business (plastic additives, dyes and personal care products), in pulp and paper
business, and in connection with mining operations (nickel, gold and separating copper from molybdenum) as well as bauxite
refining (aluminum). NaHS has also gained acceptance in environmental applications, including waste treatment programs
requiring stabilization and reduction of heavy and toxic metals and flue gas scrubbing. Additionally, NaHS can be used for
removing hair from hides at the beginning of the tannery process.
Caustic soda is used in many of the same industries as NaHS. Many applications require both chemicals for use in the
same process. For example, caustic soda can increase the yields in bauxite refining, pulp manufacturing and in the recovery of
copper, gold and nickel. Caustic soda is also used as a cleaning agent (when combined with water and heated) for process
equipment and storage tanks at refineries.
Customers
We provide on-site sulfur removal services utilizing NaHS units at ten refining locations. Even though some of our
customers have elected to own the sulfur removal facilities located at their refineries, we operate those facilities. We market all
of our NaHS as well as small amounts of NaHS for a handful of third parties.
We sell our NaHS to customers in a variety of industries, with the largest customers involved in mining of base metals,
primarily copper and molybdenum and the production of pulp and paper. We sell to customers in the copper mining industry in
the western U.S., Canada and Mexico. We also export the NaHS to South America for sale to customers for mining in Peru and
Chile. No sulfur removal customer or NaHS sales customer is responsible for more than ten percent of our consolidated
revenues. Many of the industries that our NaHS customers are in (such as copper mining and the pulp and paper industry)
participate in global markets for their products. As a result, this creates an indirect exposure for NaHS to global demand for the
end products of our customers. Provisions in our service contracts with refiners allow us to adjust our sour gas processing rates
(sulfur removal) to maintain a balance between NaHS supply and demand.
We sell caustic soda to many of the same customers who purchase NaHS from us, including pulp and paper
manufacturers and customers in the copper mining industry. We also supply caustic soda to some of the refineries in which we
operate for use in cleaning processing equipment.
Our natural soda ash is sold to a diverse customer base in the United States, Canada, the European Community, the
European Free Trade Area and the South African Customs Union. Our Alkali Business sells exclusively through the American
Natural Soda Ash Corporation, or ANSAC, in all other markets. ANSAC is a nonprofit foreign sales association in which our
Alkali Business and two other U.S. soda ash producers are members. ANSAC is our Alkali Business’ largest customer. Soda
ash sold to ANSAC is later resold to other customers worldwide. Soda ash is utilized by our customers as basic building block
for a number of ubiquitous products, including flat glass, container glass, dry detergent and a variety of chemicals and other
industrial products.
Competition
The global soda ash market in which our Alkali Business operates is competitive. Competition is based on a number of
factors such as price, favorable logistics and consistent customer service. In North America, primary competition is from other
U.S.-based natural soda ash operations: Solvay Chemicals, Ciner Resources, L.P., Tata Chemicals Soda Ash Partners in
Wyoming, and Searles Valley Minerals, in California. Because of the structural cost advantages of natural soda ash production
in the United States, including lower raw material and energy requirements, imports have not been an important source of
competition in North America. According to IHS, on average, the cash cost to produce material soda ash has been about half of
the cost to produce synthetic soda ash. Sales of soda ash and specialty products outside of North America (principally through
ANSAC) face competition from a variety of others, in most cases producers of soda ash using the synthetic method, but to a
lesser extent producers of natural soda ash based in Turkey, China and Africa. Our Alkali Business’ specialty Alkali products
also experience significant competition from producers of sodium bicarbonate, such as Church & Dwight Co., Solvay
Chemicals and Natural Soda LLC.
Soda ash is highly valued by manufacturers of flat and container glass because it lowers the temperature of the batch
in a glass furnace. It is also valued by detergent manufacturers for its absorptive qualities. In addition, soda ash is used in paper
production applications and other consumer and industrial applications. Demand for soda ash in the United States has been
relatively flat over the last five years. Sales of soda ash in rapidly developing economies have grown more rapidly as a growing
middle class demands more products that use soda ash, such as glass for housing and autos and detergents for cleaning.
ANSAC is our Alkali Business's largest customer, with total sales representing 27% of total sales in the segment. Apart
from ANSAC, our sodium minerals and sulfur services segment is not dependent on any single or small group of customers, the
loss of one of which would not have a material adverse effect on us.
17
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.
Onshore Facilities and Transportation
We provide onshore facilities and transportation services to Gulf Coast crude oil refineries and producers through a
combination of purchasing, transporting, storing, blending and marketing of crude oil and refined products (primarily fuel oil,
asphalt, and other heavy refined products). In connection with these services, we utilize our increasingly integrated portfolio of
logistical assets consisting of pipelines, trucks, terminals, railcars and barges. The increasingly integrated nature of our onshore
facilities and transportation assets is particularly evident in certain of our recently completed or ongoing growth initiatives in
areas such as Louisiana, Texas and Wyoming. Our crude oil related services include gathering crude oil from producers at the
wellhead, transporting crude oil by gathering line, truck, railcar and barge to pipeline injection points, transporting crude oil for
our gathering and marketing operations and for other shippers on our pipelines and marketing crude oil to refiners. Not unlike
our crude oil operations, we also gather refined products from refineries, transport refined products via pipeline, truck, railcar
and barge, and sell refined products to customers in wholesale markets. For certain of these services, we generate fee-based
income related to the transportation services provided. In some cases, we also profit from the difference between the price at
which we re-sell the crude oil and petroleum products less the price at which we purchase the crude oil and products, minus the
associated costs of aggregation and transportation.
Our crude oil onshore facilities and transportation operations are concentrated in Texas, Louisiana, Alabama, Florida,
Mississippi and Wyoming. These operations help to ensure (among other things) a base supply source for our crude oil pipeline
systems, refinery customers and other shippers while providing our producer customers with a market outlet for their
production. We attempt to limit our direct commodity price risk in our onshore facilities and transportation segment by utilizing
back-to-back purchases and sales, matching sale and purchase volumes on a monthly basis and hedging unsold volumes
(primarily with NYMEX derivatives to offset the remaining price risk); however, we cannot completely eliminate commodity
price risks. By utilizing our network of pipelines, trucks, railcars, barges, and terminals, we are able to provide transportation
related services to, and in many cases back-to-back gathering and marketing arrangements with, crude oil refiners and
producers. Additionally, our crude oil gathering and marketing expertise and knowledge base provide us with an ability to
capitalize on opportunities that arise from time to time in our market areas. We gather and market approximately 50,000 barrels
per day of crude oil, much of which is produced from large resource basins throughout Texas and the Gulf Coast. Our crude oil
pipelines transport many of these barrels, as well barrels for third party producers and refiners to which we charge fees for our
transportation services. Given our network of terminals, we also have the ability to store crude oil during periods of contango
(crude oil prices for future deliveries are higher than for current deliveries) for delivery in future months. When we purchase
and store crude oil during periods of contango, we attempt to limit direct commodity price risk by simultaneously entering into
a contract to sell the inventory in a future period, either with a counterparty or in the crude oil futures market. The most
substantial component of the costs we incur while aggregating crude oil and petroleum products relates to operating our fleet of
owned and leased trucks and railcars and incurring transportation related costs.
18
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 five onshore common carrier crude oil pipeline systems: the Texas System, the Jay System, the
Mississippi System, the Louisiana System and the Wyoming System.
Texas System
Jay System
Mississippi
System
Louisiana
System
Wyoming
System
Crude Oil
100%
Crude Oil
100%
Crude Oil
Intermediates
Refined
Products
100%
150,000
14,155
135
45,000
8,290
235
350,000
135,310
25
Crude Oil
100%
PRCS 10"-
75,000
PRE 12"-
125,000
22,329
155
Crude Oil
100%
Existing 8" -
60,000
Looped 18" -
275,000
32,684
47
1,100,000
230,000
247,500
350,000
450,000
Hastings
Junction, TX
to Webster,
TX
Texas City,
TX to
Webster, TX
FERC/
TXRRC
Port Hudson,
LA to Baton
Rouge, LA
Wright, WY
(Campbell
County) to
Douglas, WY
(Pronghorn)
Baton Rouge,
LA to Port
Allen, LA
Douglas, WY
to Guernsey,
WY
Southern AL/
FL to Mobile,
AL
Soso, MS to
Liberty, MS
FERC
FERC
FERC
FERC
Product
Interest Owned
Design Capacity (Bbls/day)
2017 Throughput (Bbls/day)
System Miles
Approximate owned tankage
storage capacity (Bbls)
Location
Rate Regulated
•
•
Texas System. Our Texas System transports crude oil from Hastings Junction (south of Houston) to several delivery
points near Houston, Texas (including our Webster, Texas facility). This system also takes delivery of crude oil
volumes at Texas City for delivery to our Webster, Texas facility, which ultimately connects to other crude oil
pipelines. We earn a tariff for our transportation services, with the tariff rate per barrel of crude oil varying with the
distance from injection point to delivery point. As mentioned in "Recent Developments and Status of Certain Growth
Initiatives" our Houston area crude oil infrastructure project became fully operational in the second quarter of 2017.
Jay System. Our Jay System provides crude oil shippers access to refineries, pipelines and storage near Mobile,
Alabama. That system also includes gathering connections to approximately 43 wells, additional crude oil storage
capacity of 20,000 barrels in the field, an interconnect with our Walnut Hill rail facility, a delivery connection to a
refinery in Alabama and an interconnection to another common carrier pipeline that delivers crude oil into Mississippi.
19
• Mississippi System. Our Mississippi System provides shippers of crude oil in Mississippi indirect access to refineries,
pipelines, storage, terminals and other crude oil infrastructure located in the Midwest. That system is adjacent to
several crude oil fields that are in various phases of being produced through tertiary recovery strategy, including CO2
injection and flooding. We provide transportation services on our Mississippi pipeline through an “incentive” tariff
which provides that the average rate per barrel that we charge during any month decreases as our aggregate throughput
for that month increases above specified thresholds.
•
Louisiana System. Our Louisiana System transports crude oil from Port Hudson to our Baton Rouge Scenic Station rail
unloading facility and continues downstream to the Anchorage Tank Farm servicing Exxon Mobil Corporation's Baton
Rouge refinery. This refinery is one of the largest refinery complexes in North America, with more than 500,000
barrels per day of refining capacity. Our Louisiana system also connects the Anchorage Tank Farm to our new Port of
Baton Rouge Terminal (which was also built to service Exxon's Baton Rouge refinery), allowing bidirectional flow of
crude oil, intermediates and refined products between the Anchorage Tank Farm and this terminal via a dedicated
crude pipeline and a dedicated intermediates pipeline.
This pipeline system serves as a key asset in our increasingly integrated Baton Rouge area midstream infrastructure,
which also includes terminal and rail facilities as discussed previously.
Additionally, as discussed in "Recent Developments and Growth Initiatives" above, we have completed construction
on a new terminal, crude oil pipeline and unit train unloading facility in Raceland, Louisiana which was connected to
existing midstream infrastructure and provides further distribution to the Louisiana refining markets. This became
fully operational in the second quarter of 2017.
• Wyoming System. Our Powder River Crude Services ("PRCS") crude oil pipeline transports crude oil from receipt
point stations in Campbell County and Converse County, Wyoming to our Pronghorn Station near Douglas, Wyoming.
The PRCS pipeline has a design capacity of approximately 75,000 barrels per day and is supplied by truck volumes
and gathering infrastructure of PRCS and third parties in the Powder River Basin. Our Powder River Express ("PRE")
crude oil pipeline transports crude oil from our Pronghorn Station to our Guernsey Station in Platte County, Wyoming.
The PRE pipeline has a design capacity of approximately 125,000 barrels per day and is supplied by volumes from
the PRCS pipeline and truck volumes at our Pronghorn station and provides connectivity to multiple downstream
pipeline markets at Guernsey, including regional refineries and Cushing, Oklahoma via the Pony Express Pipeline.
This pipeline system serves as a key asset in our increasingly integrated Wyoming midstream infrastructure, which
also includes terminals and rail facilities.
Other Onshore Facilities and Transportation Operations
We own five operational crude oil rail loading/unloading facilities located in Baton Rouge, Louisiana; Raceland,
Louisiana; Walnut Hill, Florida; Natchez, Mississippi and Douglas, Wyoming which provide synergies to our existing asset
footprint. We generally earn a fee for loading or unloading railcars at these facilities. Four of these facilities, our Baton Rouge,
Louisiana, Raceland, Louisiana, Walnut Hill, Florida, and Douglas, Wyoming facilities are directly connected to our existing
integrated crude oil pipeline and terminal infrastructure. See further discussion of these facilities above.
Within our onshore facilities and transportation business segment, we employ many types of logistically flexible
assets. These assets include 200 trucks, 400 trailers, 504 railcars, and terminals and other tankage with 4.6 million barrels of
leased and owned storage capacity in multiple locations along the Gulf Coast, accessible by pipeline, truck, rail or barge, in
addition to tankage related to our crude oil pipelines, previously mentioned. Our leased railcars consist of approximately 32
refined product railcars and 472 crude oil railcars.
Our refined products onshore facilities and transportation operations are concentrated in the Gulf Coast region,
principally Texas and Louisiana, and in Wyoming. Through our footprint of owned and leased pipelines, trucks, leased railcars,
terminals and barges, we are able to provide Gulf Coast area refineries with transportation services as well as market outlets for
certain heavy refined products. We primarily engage in the transportation and supply of fuel oil, asphalt, and other heavy
refined products to our customers in wholesale markets. We have the ability from time to time to obtain various grades of
refined products from our refinery customers and blend them to meet the requirements of our other market customers.
However, because our refinery customers may choose to manufacture such refined products based on a number of economic
and operating factors, we cannot predict the timing of contribution margins related to our blending services.
20
CO2 Pipelines
We transport CO2 on our Free State pipeline for a fee and we lease our Northeast Jackson Dome Pipeline System, or
NEJD System, for a fee.
Product
Interest owned
System miles
Pipeline diameter
Location
Rate Regulated
Free State Pipeline
CO2
100%
86
20"
Jackson Dome near Jackson, MS
to East Mississippi
No
Our Free State pipeline extends from CO2 source fields near Jackson, Mississippi to crude oil fields in eastern
Mississippi. We have a transportation services agreement through 2028 related to our Free State pipeline with a single shipper
who has the right to use 100% of that pipeline's capacity.
Our NEJD System transports CO2 to tertiary crude oil recovery operations in southwest Mississippi. We have leased
that pipeline to an affiliate of the shipper on our Free State pipeline through 2028. Our NEJD lessee is responsible for all
operations and maintenance on that system and will bear and assume substantially all obligations and liabilities with respect to
that system.
Customers
Our onshore facilities and transportation business encompasses numerous refiners and hundreds of producers, for
which we provide transportation related services, as well as gather from and market to crude oil and refined products. During
2017, more than 10% of our consolidated revenues were generated from Shell.
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. Additionally, the shipper on our Free State pipeline is required to use our Free State pipeline for any transportation
of CO2 within a dedicated area.
In our refined products onshore facilities and transportation operations, we compete primarily with regional
companies. See "Marine Transportation - Competition" for additional discussion of our competitors. Competitive factors in
our onshore facilities and transportation business include price, relationships with customers, range and quality of services,
knowledge of products and markets, availability of trade credit and capabilities of risk management systems.
Marine Transportation
Our marine transportation segment consists of (i) our inland marine fleet which transports heavy refined petroleum
products, including asphalt, principally serving refineries and storage terminals along the Gulf Coast, Intracoastal Canal and
western river systems of the U.S., principally along the Mississippi River and its tributaries, (ii) our offshore marine fleet which
transports crude oil and refined petroleum products, principally serving refineries and storage terminals along the Gulf Coast,
Eastern Seaboard, Great Lakes and Caribbean, and (iii) our modern double-hulled, Jones Act qualified tanker M/T American
Phoenix which is currently under charter serving a customer along the Gulf Coast until 2020. The below table includes
operational information relating to our marine transportation fleet:
21
Aggregate Fleet Design Capacity (Bbls) (in
thousands)
Individual Vessel Capacity Range (Bbls) (in
thousands) (1)
Number of:
Push/Tug Boats
Barges
Product Tankers
Inland
2,229
23-39
33
80
—
Offshore
American Phoenix
885
65-136
9
9
—
330
330
—
—
1
(1) Represents capacity per barge ranges on our inland and offshore barge, as well as the capacity of our M/T American Phoenix.
Customers
Our marine customers are primarily refiners and some large energy companies. Our M/T American Phoenix is
currently operating under a long term charter into 2020 with a large refining customer. We are a provider of transportation
services for our customers and, in almost all cases, do not assume ownership of the products we transport. Marine
transportation services are conducted under term contracts, some of which have renewal options for customers with whom we
have traditionally had long-standing relationships, as well as spot contracts. Most have been our customers for many years and
we generally anticipate continued relationships; however, there is no assurance that any individual contract will be renewed.
A term contract is an agreement with a specific customer to transport cargo from a designated origin to a designated
destination at a set rate (affreightment) or at a daily rate (time charter). The rate may or may not escalate during the term of the
contract; however, the base rate generally remains constant and contracts often include escalation provisions to recover changes
in specific costs such as fuel. Time charters, which insulate us from revenue fluctuations caused by weather and navigational
delays and temporary market declines, represented over 95% of our marine transportation revenues under term contracts during
2017, 2016 and 2015. A spot contract is an agreement with a customer to move cargo from a specific origin to a designated
destination for a rate negotiated at the time the cargo movement takes place. Spot contract rates are at the current “market” rate
and are subject to market volatility. We typically maintain a higher mix of term contracts to spot contracts to provide a
predictable revenue stream while maintaining spot market exposure to take advantage of new business opportunities and
existing customers’ peak demands. During 2017, 2016 and 2015, approximately 64%, 62% and 75%, respectively, of our
marine transportation revenues were from term contracts and 36%, 38% and 25%, respectively, were from spot contracts.
Revenues from customers of our marine transportation segment did not account for more than ten percent of our
consolidated revenues.
Competition
Our competitors for the marine transportation of crude oil and heavy refined petroleum products are both midstream
MLPs with marine transportation divisions, along with companies that are in the business of solely marine transportation
operations. Competition among common marine carriers is based on a number of factors including proximity to production,
refineries and connecting infrastructures, customer service, and transportation pricing.
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.
Geographic Segments
All of our operations are in the U.S. Additionally, we transport and sell NaHS to customers in South America, Mexico
and Canada. Our Alkali Business sells certain products in Canada, the European Community Free Trade Area and the South
22
Africa Customs Union. Additionally sales in our Alkali Business are made to ANSAC, the nonprofit foreign sales association.
Revenues from customers in foreign countries totaled approximately $9 million, $8 million and $12 million in 2017, 2016 and
2015, respectively. These amounts exclude sales to certain customers where the title to certain NaHS shipments is transferred in
the U.S. prior to the NaHS being transported to South America, Mexico or Canada, as well as sales from our Alkali Business to
ANSAC as title transfer on these sales in the U.S. In addition this excludes sales of alkali products to foreign customers, as title
transfers in the U.S. on virtually all other non-ANSAC sales to foreign customers within our Alkali Business. The remainder of
our revenues was generated from sales to customers in the U.S.
Credit Exposure
Due to the nature of our operations, a disproportionate percentage of our trade receivables constitute obligations of
refiners, large oil producers and integrated oil companies. This energy industry concentration has the potential to affect our
overall exposure to credit risk, either positively or negatively, in that our customers could be affected by similar changes in
economic, industry or other conditions. However, we believe that the credit risk posed by this industry concentration is offset
by the creditworthiness of our specific customer base in the context of our specific transactions as well as other factors,
including the strategic nature of certain of our assets and relationships and our credit procedures. Our portfolio of accounts
receivable is generally comprised in large part of obligations of refiners, integrated and large independent oil and natural gas
producers, and mining and other industrial companies that purchase NaHS and soda ash, most of which have stable payment
histories. The credit risk related to contracts that are traded on the NYMEX is limited due to the daily cash settlement
procedures and other NYMEX requirements.
When we market crude oil, petroleum products, NaHS, soda ash and provide transportation and other services, we
must determine the amount, if any, of the line of credit we will extend to any given customer. We have established procedures
to manage our credit exposure, including initial credit approvals, credit limits, collateral requirements and rights of offset.
Letters of credit, prepayments and guarantees are also utilized to limit credit risk to ensure that our established credit criteria are
met. We use similar procedures to manage our exposure to our customers in the offshore pipeline transportation and marine
transportation segments.
As a result of our activities in the Gulf of Mexico and onshore (including our Alkali Business), our largest customers
include Shell, Exxon Mobil Corporation, BP PLC, Marathon Petroleum Corporation, Anadarko Petroleum Corporation and
ANSAC.
Employees
To carry out our business activities, we employed approximately 2,100 employees at December 31, 2017. We believe
that relationships with our employees are good.
Regulation
Pipeline Rate and Access Regulation
The rates and the terms and conditions of service of our interstate common carrier pipeline operations are subject to
regulation by FERC under the Interstate Commerce Act, or ICA. Under the ICA, rates must be “just and reasonable,” and must
not be unduly discriminatory or confer any undue preference on any shipper. FERC regulations require that oil pipeline rates
and terms and conditions of service for regulated pipelines be filed with FERC and posted publicly.
Effective January 1, 1995, FERC promulgated rules simplifying and streamlining the ratemaking process. Previously
established rates were “grandfathered,” limiting the challenges that could be made to existing tariff rates. Increases from
grandfathered rates of interstate oil pipelines are currently regulated by FERC primarily through an index methodology,
whereby a pipeline is allowed to change its rates based on the year-to-year change in an index. Under FERC regulations, we are
able to change our rates within prescribed ceiling levels that are tied to the Producer Price Index for Finished Goods. Rate
increases made pursuant to the index will be subject to protest, but such protests must show that the rate increase resulting from
application of the index is substantially in excess of the applicable pipeline’s increase in costs.
In addition to the index methodology, FERC allows for rate changes under three other methods—cost-of-service,
competitive market showings and agreements between shippers and the oil pipeline company that the rate is acceptable, or
Settlement Rates. The pipeline tariff rates on our Mississippi, Jay, Louisiana, and Wyoming Systems are either rates that are
subject to change under the index methodology or Settlement Rates. None of our tariffs have been subjected to a protest or
complaint by any shipper or other interested party.
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.
23
Our intrastate common carrier pipeline operations in Texas are subject to regulation by the Railroad Commission of
Texas. The applicable Texas statutes require that pipeline rates and practices be reasonable and non-discriminatory and that
pipeline rates provide a fair return on the aggregate value of the property of a common carrier, after providing reasonable
allowance for depreciation and other factors and for reasonable operating expenses. Although no assurance can be given that
the tariffs we charge would ultimately be upheld if challenged, we believe that the tariffs now in effect can be sustained.
Our CO2 pipelines are subject to regulation by the state agencies in the states in which they are located.
Marine Regulations
Maritime Law. The operation of towboats, tugboats, barges, vessels and marine equipment create maritime obligations
involving property, personnel and cargo and are subject to regulation by the U.S. Coast Guard, or USCG, the Environmental
Protection Agency, or EPA, the Department of Homeland Security, or DHS, federal laws, state laws and certain international
conventions under General Maritime Law. These obligations can create risks which are varied and include, among other things,
the risk of collision and allision, which may precipitate claims for personal injury, cargo, contract, pollution, third-party claims
and property damages to vessels and facilities. Routine towage operations can also create risk of personal injury under the
Jones Act and General Maritime Law, cargo claims involving the quality of a product and delivery, terminal claims, contractual
claims and regulatory issues. Federal regulations also require that all tank barges engaged in the transportation of oil and
petroleum in the U.S. be double hulled. All of our barges are double-hulled.
All of our barges are inspected by the USCG and carry certificates of inspection. All of our towboats and tugboats are
certificated by the USCG. Most of our vessels are built to American Bureau of Shipping, or ABS, classification standards and
in some instances are inspected periodically by ABS to maintain the vessels in class standards. The crews we employ aboard
vessels, including captains, pilots, engineers, tankermen and ordinary seamen, are documented by the USCG.
We are required by various governmental agencies to obtain licenses, certificates and permits for our vessels
depending upon such factors as the cargo transported, the waters in which the vessels operate and other factors. We are of the
opinion that our vessels have obtained and can maintain all required licenses, certificates and permits required by such
governmental agencies for the foreseeable future.
We believe that additional security and environmental related regulations may be imposed on the marine industry in
the form of contingency planning requirements. Generally, we endorse the anticipated additional regulations and believe we are
currently operating to standards at least equal to anticipated additional regulations.
Jones Act: The Jones Act is a federal law that restricts maritime transportation between locations in the U.S. to vessels
built and registered in the U.S. and owned and manned by U.S. citizens. We are responsible for monitoring the ownership of
our subsidiary that engages in maritime transportation and for taking any remedial action necessary to insure that no violation
of the Jones Act ownership restrictions occurs. Jones Act requirements significantly increase operating costs of U.S.-flag vessel
operations compared to foreign-flag vessel operations. Further, the USCG and ABS maintain the most stringent regime of
vessel inspection in the world, which tends to result in higher regulatory compliance costs for U.S.-flag operators than for
owners of vessels registered under foreign flags or flags of convenience. The Jones Act and General Maritime Law also provide
damage remedies for crew members injured in the service of the vessel arising from employer negligence or vessel
unseaworthiness.
Merchant Marine Act of 1936: The Merchant Marine Act of 1936 is a federal law providing that, upon proclamation
by the president of the U.S. of a national emergency or a threat to the national security, the U.S. Secretary of Transportation
may requisition or purchase any vessel or other watercraft owned by U.S. citizens (including us, provided that we are
considered a U.S. citizen for this purpose). If one of our tow boats or barges were purchased or requisitioned by the U.S.
government under this law, we would be entitled to be paid the fair market value of the vessel in the case of a purchase or, in
the case of a requisition, the fair market value of charter hire. However, if one of our tow boats is requisitioned or purchased
and its associated barge or barges are left idle, we would not be entitled to receive any compensation for the lost revenues
resulting from the idled barges. We also would not be entitled to be compensated for any consequential damages we suffer as a
result of the requisition or purchase of any of our tow boats or barges.
Security Requirements: The Maritime Transportation Security Act of 2002 requires, among other things, submission to
and approval by the USCG of vessel and waterfront facility security plans, or VSP. Our VSP’s have been approved and we are
operating in compliance with the plans for all of its vessels and that are subject to the requirements, whether engaged in
domestic or foreign trade.
Railcar Regulation
We operate a number of railcar loading and unloading facilities and lease a significant number of railcars. Our railcar
operations are subject to the regulatory jurisdiction of the Federal Railroad Administration of the DOT, the Occupational Safety
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and Health Administration, or OSHA, as well as other federal and state regulatory agencies. We believe that our railcar
operations are in substantial compliance with all existing federal, state and local regulations.
DOT and OSHA have jurisdiction under several federal statutes over a number of safety and health aspects of rail
operations, including the transportation of hazardous materials. State agencies regulate some aspects of rail operations with
respect to health and safety in areas not otherwise preempted by federal law.
Regulation of the Mining Industry in the United States
We have the right to mine trona through leases we hold from the U.S. Federal government, the State of Wyoming and an
affiliate of Anadarko Petroleum (“Anadarko”). Our leases with the U.S. government are issued under the provisions of the
Mineral Leasing Act of 1920 (30 U.S.C. 18 et. Seq.) and are administered by the U.S. Bureau of Land Management (“BLM”)
and our leases with the state of Wyoming are issued under Wyoming Statutes 36-6-101 et. seq. Anadarko is the successor to
rights originally granted to the Union Pacific Railroad in connection with the construction of the first transcontinental railroad
in North America. For more information please see discussion of Mining and Mineral Tenure in Item 1 below.
We pay royalties to the BLM, the State of Wyoming and Anadarko. These royalties are calculated based upon the gross
value of soda ash and related products at a certain stage in the mining process. We are obligated to pay minimum royalties or
annual rentals to our lessors regardless of actual sales and in the case of Anadarko to pay royalties in advance based on a
formula based on the amount of trona produced and sold in the previous year which is then credited against production royalties
owed. The royalty rates we pay to our lessors may change upon our renewal of such leases; however, we anticipate being able
to renew all material leases at the appropriate time. In the past, the U.S. Congress has passed legislation to cap royalties
collected by BLM at a rate lower than the rate stated in our federal leases.
Our mining operations in Wyoming are subject to mine permits issued by the Land Quality Division of the Wyoming
Department of Environmental Quality (“WDEQ”). WDEQ imposes detailed reclamation obligations on us as a holder of mine
permits.. As of December 31, 2017, the amount of our reclamation bond was approximately $80 million. The amount of the
bond is subject to change based upon periodic re-evaluation by WDEQ.
The health and safety of our employees working underground and on the surface are subject to detailed regulation. The
safety of our operations at Westvaco are regulated the U.S. Mine Safety and Health Administration (“MSHA”) and our Granger
Facility by the Wyoming Occupational Safety and Health Administration (“Wyoming OSHA”). MSHA administers the
provisions of the Federal Mine Safety and Health Act of 1977 and enforces compliance with that statute’s mandatory safety and
health standards. As part of MSHA’s oversight, representatives perform at least four unannounced inspections (approximately
once quarterly) each year at Westvaco. Wyoming OSHA regulates the health and safety of non-mining operations under a plan
approved by the U.S. Occupational Health and Safety Administration. When our Granger facility was restarted in 2009 on
solution mine feed (i.e. without any miners working underground), Wyoming OSHA assumed responsibility for the facility.
Regulation of Finished Product Manufacturing
Our business is subject to extensive regulation by federal, state, local and foreign governments. Governmental authorities
regulate the generation and treatment of waste and air emissions at our operations and facilities. We also comply with
worldwide, voluntary standards developed by the International Organization for Standardization (“ISO”), a nongovernmental
organization that promotes the development of standards and serves as a bridging organization for quality standards, such as
ISO 9001:2015 for quality management and ISO 22000 for food safety management.
Several of the production operations in our Alkali Business are subject to regulation by the U.S. Food and Drug
Administration (“FDA”). Our sodium bicarbonate plant is a registered facility for the production of food and pharmaceutical
grade ingredients and we comply with strict Current Good Manufacturing Practice (“CGMP”) requirements in our operations.
The U.S. Food Safety Modernization Act requires that parts of our facility that produce animal nutrition products comply with
new more rigorous manufacturing standards. We believe that we materially comply with requirements currently in effect and
have a program in place to comply with additional requirements which come into effect in 2018. 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.
Chemical Registration
The European Union adopted a regulatory framework for chemicals in 2006 known as Registration, Evaluation and
Authorization of Chemicals (“REACH”). Manufacturers and importers of chemical substances must register information
regarding the properties of their existing chemical substances with the European Chemicals Agency. The timeline for existing
chemical substances to be registered is based on volume.. The first group of chemical substances was required to be registered
in 2010, with additional registrations due in 2013 and 2018.
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Our Alkali Business's soda ash was registered for import into the EU from a foreign manufacturer under REACH
prior to the 2010 deadline and will register our sodium bicarbonate prior the 2018 deadline if we plan to sell such products in
the EU. None of our Alkali Business production operations are located in the EU. None of our alkali products are listed as a
“Substance of Very High Concern” or are proposed for classification as a human health hazard or for restriction.
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 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.
Hazardous Substances and Waste Handling
The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, or CERCLA, also
known as the “Superfund” law, and analogous state laws impose liability, without regard to fault or the legality of the original
conduct, on certain classes of persons. These persons include current owners and operators of the site where a release of
hazardous substances occurred, prior owners or operators that owned or operated the site at the time of the release of hazardous
substances, and companies that disposed or arranged for the disposal of the hazardous substances found at the site. We currently
own or lease, and have in the past owned or leased, properties that have been in use for many years with the gathering and
transportation of hydrocarbons including crude oil and other activities that could cause an environmental impact. Persons
deemed “responsible persons” under CERCLA may be subject to strict and joint and several liability for the costs of removing
or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property
contamination (including groundwater contamination), for damages to natural resources, and for the costs of certain health
studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health
or the environment and to seek to recover the costs they incur from the responsible classes of persons. It is not uncommon for
neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by
hazardous substances or other pollutants released into the environment.
We also may incur liability under the Resource Conservation and Recovery Act, as amended, or RCRA, and analogous
state laws which impose requirements and also liability relating to the management and disposal of solid and hazardous wastes.
While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment,
transportation and disposal of hazardous wastes. Certain petroleum production wastes are excluded from RCRA’s hazardous
waste regulations. However, it is possible that these wastes, which could include wastes currently generated during our
operations, will in the future be designated as “hazardous wastes” and, therefore, be subject to more rigorous and costly
disposal requirements. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain crude oil
and natural gas exploration and production wastes as “hazardous wastes.” Also, in December 2016, the EPA agreed in a consent
decree to review its regulation of oil and gas waste. It has until March 2019 to determine whether any revisions are necessary.
Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating
expenses.
We believe that we are in substantial compliance with the requirements of CERCLA, RCRA and related state and local
laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations required
under such laws and regulations. Although we believe that the current costs of managing our wastes as they are presently
classified are reflected in our budget, any legislative or regulatory reclassification of oil and natural gas exploration and
production wastes could increase our costs to manage and dispose of such wastes.
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Water Discharges
The Federal Water Pollution Control Act, as amended, also known as the “Clean Water Act,” and analogous state laws
impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including crude oil, into navigable
waters of the U.S., as well as state waters. Permits must be obtained to discharge pollutants into these waters. Spill prevention,
control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures
to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. The
Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated
waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. On June 29, 2015, the EPA and
the U.S. Army Corps of Engineers, or Corps, jointly promulgated final rules redefining the scope of waters protected under the
Clean Water Act. To the extent the rule expands 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. Following its
promulgation, numerous states and industry groups challenged the rule and, on October 9, 2015, a federal court stayed the
rule’s implementation nationwide, pending further action in court. In response to this decision, the EPA and the Corps have
resumed nationwide use of the agencies’ prior regulations defining the term “waters of the United States.” Further, on February
28, 2017, President Trump signed an executive order directing the relevant executive agencies to review the rules and to initiate
rulemaking to rescind or revise them, as appropriate under the stated policies of protecting navigable waters from pollution
while promoting economic growth, reducing uncertainty, and showing due regard for Congress and the states. On July 27,
2017, the EPA and the Corps published a proposed rule to rescind the 2015 rules, and, on November 22, 2017, the agencies
published a proposed rule to maintain the status quo pending the agencies review of the 2015 rules.
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.
Noncompliance with the Clean Water Act or the Oil Pollution Act may result in substantial administrative, civil and
criminal penalties, as well as injunctive obligations. We believe we are in material compliance with each of these requirements.
Air Emissions
The Federal Clean Air Act, or CAA, as amended, and analogous state and local laws and regulations restrict the
emission of air pollutants, and impose permit requirements and other obligations. Regulated emissions occur as a result of our
operations, including the handling or storage of crude oil and other petroleum products. Both federal and state laws impose
substantial penalties for violation of these applicable requirements. Accordingly, our failure to comply with these requirements
could subject us to monetary penalties, injunctions, conditions or restrictions on operations, revocation or suspension of
necessary permits and, potentially, criminal enforcement actions.
On August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new air
emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package
includes New Source Performance standards to address emissions of sulfur dioxide and volatile organic compounds and a
separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production
and processing activities. The final rules seek to achieve a 95% reduction in volatile organic compounds emitted by requiring
the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured
after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers,
dehydrators, storage tanks and other production equipment. The EPA received numerous requests for reconsideration of these
rules from both industry and the environmental community, and court challenges to the rules were also filed. In response, the
EPA has issued, and will likely continue to issue, revised rules responsive to some of the requests for reconsideration. In
particular, on May 12, 2016, the EPA amended its regulations to impose new standards for methane and volatile organic
compounds emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and
natural gas sector. However, in a March 28, 2017 executive order, President Trump directed the EPA to review the 2016
regulations and, if appropriate, to initiate a rulemaking to rescind or revise them consistent with the stated policy of promoting
clean and safe development of the nation’s energy resources, while at the same time avoiding regulatory burdens that
unnecessarily encumber energy production. On June 16, 2017, the EPA published a proposed rule to stay for two years certain
requirements of the 2016 regulations, including fugitive emission requirements. These standards, as well as any future laws and
their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or
the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the
use of specific equipment or technologies to control emissions.
NEPA
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Under the National Environmental Policy Act, or NEPA, a federal agency, commonly in conjunction with a current
permittee or applicant, may be required to prepare an environmental assessment or a detailed environmental impact statement
before taking any major action, including issuing a permit for a pipeline extension or addition that would affect the quality of
the environment. Should an environmental impact statement or environmental assessment be required for any proposed pipeline
extensions or additions, NEPA may prevent or delay construction or alter the proposed location, design or method of
construction.
Endangered Species Act
The federal Endangered Species Act and analogous state statutes restrict activities that may adversely affect
endangered and threatened species or their habitat. Similar protections are offered to migratory birds under the Migratory Bird
Treaty Act, though, in December 2017, the U.S. Fish and Wildlife Service provided guidance limiting the reach of the Act. The
designation of previously unidentified endangered or threatened species in areas where we operate could cause us to incur
additional costs or become subject to operating delays, restrictions or bans.
Climate Change
In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse
gases ("GHGs") present an endangerment to human health and the environment because emissions of such gases are, according
to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. These findings served as a
statutory prerequisite for EPA to adopt and implement regulations that would restrict emissions of GHGs under existing
provisions of the CAA. The EPA also adopted two sets of related rules, one of which purports to regulate emissions of GHGs
from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources of emissions
such as power plants or industrial facilities. The EPA finalized the motor vehicle rule in April 2010 and it became effective in
July 2010. The EPA adopted the stationary source rule, also known as the "Tailoring Rule," in May 2010, and it became
effective in January 2011. The tailoring rule established new GHG emissions thresholds that determine when stationary sources
must obtain permits under the PSD and Title V programs of the Clean Air Act. On June 23, 2014, in Utility Air Regulatory
Group v. EPA (“UARG v. EPA”), the Supreme Court held that stationary sources could not become subject to PSD or Title V
permitting solely by reason of their GHG emissions. The Court ruled, however, that the EPA may require installation of best
available control technology for GHG emissions at sources otherwise subject to the PSD and Title V programs. On August 26,
2016, the EPA proposed changes needed to bring the EPA’s air permitting regulations in line with the Supreme Court’s decision
on GHG permitting. The proposed rule was published in the Federal Register on October 3, 2016 and the public comment
period closed on December 2, 2016.
Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified
large GHG emission sources in the U.S., beginning in 2011 for emissions occurring in 2010. Further, in November 2010, the
EPA expanded its existing GHG reporting rule to include onshore and offshore crude oil and natural gas production and onshore
processing, transmission, storage and distribution facilities, which may include certain of our facilities, beginning in 2012 for
emissions occurring in 2011. In October 2015, the EPA amended the GHG reporting rule to add the reporting of GHG
emissions from gathering and boosting systems, completions and workovers of crude oil wells using hydraulic fracturing, and
blowdowns of natural gas transmission pipelines. As a result of this continued regulatory focus, future GHG regulations of the
crude oil and natural gas industry remain a possibility.
Further, the U.S. Congress has from time to time considered various proposals to reduce GHG emissions, and almost
half of the states, either individually or through multi-state regional initiatives, have already taken legal measures to reduce
GHG emissions, primarily through the planned development of GHG emission inventories and/or GHG cap-and-trade
programs. The net effect of this legislation is to impose increasing costs on the combustion of carbon-based fuels such as crude
oil, refined petroleum products and natural gas. Our compliance with any future legislation or regulation of GHGs, if it occurs,
may result in materially increased compliance and operating costs.
In addition, in December 2015, the United States participated in the 21st Conference of the Parties (COP-21) of the
United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties
to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of
GHGs. The Agreement went into effect on November 4, 2016. The Agreement establishes a framework for the parties to
cooperate and report actions to reduce GHG emissions. However, on June 1, 2017, President Trump announced that the United
States would withdraw from the Paris Agreement, and begin negotiations to either re-enter or negotiate an entirely new
agreement with more favorable terms for the United States. The Paris Agreement sets forth a specific exit process, whereby a
party may not provide notice of its withdrawal until three years from the effective date, with such withdrawal taking effect one
year from such notice. It is not clear what steps the Trump Administration plans to take to withdraw from the Paris Agreement,
whether a new agreement can be negotiated, or what terms would be included in such an agreement. Furthermore, in response
to the announcement, many state and local leaders have stated their intent to intensify efforts to uphold the commitments set
forth in the international accord.
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The effect on our operations of CAA regulations, legislative efforts or related implementation regulations that regulate
or restrict emissions of GHGs in areas that we conduct business could adversely affect the demand for the products that we
transport, store and distribute and, depending on the particular program adopted, could increase our costs to operate and
maintain our facilities by requiring that we, among other things, measure and report our emissions, install new emission
controls on our facilities, acquire allowances to authorize our GHG emissions, pay any taxes related to our GHG emissions and
administer and manage a GHG emissions program. We may be unable to include some or all of such increased costs in the rates
charged by our pipelines or other facilities, and any such recovery may depend on events beyond our control, including the
outcome of future rate proceedings before the FERC or state regulatory agencies and the provisions of any final legislation or
implementing regulations. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries
could also increase the cost of consuming, and thereby adversely affect demand for the crude oil and natural gas that we
produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our
business, financial condition and results of operations. It is not possible at this time to predict with any accuracy the structure or
outcome of any future legislative or regulatory efforts to address such emissions or the eventual costs to us of compliance.
Furthermore, there have also been efforts in recent years to influence the investment community, including investment
advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and
pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism
and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities,
operations and ability to access capital. In addition, claims have been made against certain energy companies alleging that GHG
emissions from crude oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a
result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege
personal injury, property damages, or other liabilities. While our business is not a party to any such litigation, we could be
named in actions making similar allegations. An unfavorable ruling in any such case could adversely impact our business,
financial condition and results of operations.
Moreover, there has been public discussion that climate change may be associated with extreme weather conditions
such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible
consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could
cause some areas to experience temperatures substantially hotter or colder than their historical averages. Extreme weather
conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be
fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm
or weather hazards affecting our operations.
Safety and Security Regulations
Our crude oil and CO2 pipelines are subject to construction, installation, operation and safety regulation by the U.S.
Department of Transportation, or DOT, and various other federal, state and local agencies. Congress has enacted several
pipeline safety acts over the years. Currently, the Pipeline and Hazardous Materials Safety Administration, or PHMSA, under
DOT administers pipeline safety requirements for natural gas and hazardous liquid pipelines pursuant to detailed regulations set
forth in 49 C.F.R. Parts 190 to 195. These regulations, among other things, address pipeline integrity management and pipeline
operator qualification rules. In June 2016, Congress approved new pipeline safety legislation, the “Protecting Our Infrastructure
of Pipelines and Enhancing Safety Act of 2016,” or the PIPES Act, which provides the PHMSA with additional authority to
address imminent hazards by imposing emergency restrictions, prohibitions, and safety measures on owners and operators of
gas or hazardous liquids pipeline facilities. Significant expenses could be incurred in the future if additional safety measures are
required or if safety standards are raised and exceed the current pipeline control system capabilities.
We are subject to the PHMSA Integrity Management, or IM, regulations, which require that we perform baseline
assessments of all pipelines that could affect a High Consequence Area, or HCA, including certain populated areas and
environmentally sensitive areas. After completing a baseline assessment, we continue to assess all pipelines at specified
intervals and periodically evaluate the integrity of each pipeline segment that could affect a HCA. The integrity of these
pipelines must be assessed by internal inspection, pressure test, or equivalent alternative new technology.
The IM regulations required us to prepare an Integrity Management Plan, or IMP, that details the risk assessment
factors, the overall risk rating for each segment of pipe, a schedule for completing the integrity assessment, the methods to
assess pipeline integrity, and an explanation of the assessment methods selected. The regulations also require periodic review of
HCA pipeline segments to ensure that adequate preventative and mitigative measures exist and that companies take prompt
action to address pipeline integrity issues. No assurance can be given that the cost of testing and the required rehabilitation
identified will not be material costs to us that may not be fully recoverable by tariff increases.
Recently, the PHMSA has proposed additional regulations for gas pipeline safety. For example, in March 2016, the
PHMSA proposed a rule that would expand IM requirements beyond HCAs to gas pipelines in newly defined Moderate
Consequence Areas. The public comment period closed in July 2016. Also, in January 2017, the PHMSA released an advance
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copy of its final rules to expand safety regulations for hazardous liquid pipelines by, among other things, expanding the
required use of leak detection systems, requiring more frequent testing for corrosion and other flaws, and requiring companies
to inspect pipelines in areas affected by extreme weather or natural disasters. The final rule was withdrawn by the PHMSA in
January 2017, and it is unclear whether and to what extent the PHMSA will move forward with its regulatory reforms.
We have developed a Risk Management Plan required by the EPA as part of our IMP. This plan is intended to
minimize the offsite consequences of catastrophic spills. As part of this program, we have developed a mapping program. This
mapping program identified HCAs and unusually sensitive areas along the pipeline right-of-ways in addition to mapping of
shorelines to characterize the potential impact of a spill of crude oil on waterways.
Our crude oil, refined products and sodium minerals and sulfur services operations are also subject to the requirements
of OSHA and comparable state statutes. Various other federal and state regulations require that we train all operations
employees in Hazardous Communication ("HAZCOM") and disclose information about the hazardous materials used in our
operations. Certain information must be reported to employees, government agencies and local citizens upon request.
States are responsible for enforcing the federal regulations and more stringent state pipeline regulations and inspection
with respect to hazardous liquids pipelines, including crude oil, natural gas and CO2 pipelines. In practice, states vary
considerably in their authority and capacity to address pipeline safety. We do not anticipate any significant problems in
complying with applicable state laws and regulations in those states in which we operate.
Our trucking operations are licensed to perform both intrastate and interstate motor carrier services. As a motor carrier,
we are subject to certain safety regulations issued by the DOT. The trucking regulations cover, among other things, driver
operations, log book maintenance, truck manifest preparations, safety placard placement on the trucks and trailer vehicles, drug
and alcohol testing, operation and equipment safety and many other aspects of truck operations. We are also subject to OSHA
with respect to our trucking operations.
The USCG regulates occupational health standards related to our marine operations. Shore-side operations are subject
to the regulations of OSHA and comparable state statutes. The Maritime Transportation Security Act requires, among other
things, submission to and approval of the USCG of vessel security plans.
Since the terrorist attacks of September 11, 2001, the U.S. Government has issued numerous warnings that energy
assets could be the subject of future terrorist attacks. We have instituted security measures and procedures in conformity with
federal guidance. We will institute, as appropriate, additional security measures or procedures indicated by the federal
government. None of these measures or procedures should be construed as a guarantee that our assets are protected in the event
of a terrorist attack
Reporting of Ore Reserve and Mineral Resources
As of December 31, 2017, we had estimated mineral ore reserves in our Alkali Business. Our Alkali Business extracts
trona, a natural hydrous sodium carbonate mineral used in the production of soda ash in southwestern Wyoming, USA. Soda
ash, the commercial term for sodium carbonate (Na2CO3), is a basic ingredient in many consumer goods and a raw material
used in a diversity of manufacturing processes.
U.S. registrants are required to report ore reserves under SEC Industry Guide 7, “Description of Property by Issuers
Engaged or To Be Engaged in Significant Mining Operations.” Industry Guide 7 requires that sufficient technical and economic
studies have been completed to reasonably assure economic extraction of the declared reserves, based on the parameters and
assumptions current to the end of the reporting period.
The mineral reserve estimates are based on detailed geological, geotechnical, mine engineering and mineral processing
inputs, and financial models developed and reviewed by employees/management of our Alkali Business, who possess years of
experience directly related to the resources, mining and processing characteristics or financial performance of our operations.
Additionally, our management and technical staff includes senior personnel who have remained closely involved with each of
our active mining and mineral processing operations.
Reserve estimates for our Alkali operations at Green River Wyoming follow accepted mining industry practice and are
guided by our long-term experience in extraction of trona ore from underground mining and sodium carbonate from solution
mining in the district. Estimates of recoverable reserves for both techniques are routinely reconciled with actual production, and
our Alkali ore reserves disclosures comply with SEC Industry Guide 7.
Under SEC Industry Guide 7, Proven reserves are the highest category of ore reserve estimates, whereby the quantity
and quality have been computed from detailed sampling and modeling, while Probable reserves provide slightly lower geologic
assurance.
Mineral Tenure - Wyoming
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SEC Industry Guide 7 requires us to describe our rights to access and mine the minerals we report as ore reserves and to
disclose any change in mineral tenure of material significance. Mineral tenure for our trona mining operations in Wyoming
USA is secured through private and federal government leases, regulated by the BLM and WDEQ. All of our exploration and
mining operations are subject to multiple levels of environmental regulatory review, that include approvals of environmental
programs and public comment periods as pre-conditions to granting of mineral tenure. General descriptions of the rights and
regulatory framework for minerals of relevance to Alkali follow here.
Ownership of land and minerals relative to trona beds in the Green River Basin of southwestern Wyoming is divided
between the Federal Government (56%), Anadarko Petroleum (38%) and the State of Wyoming (6%). Anadarko’s acquisition in
2000 of the Union Pacific Resources Group (“UPRG”) included the land and mineral ownership originally granted to UPRG’s
parent company, the Union Pacific Railroad.
Leasing of Federal minerals under 41 Stat. 437, 30 U.S. Code § 124 (Section 23), “Agricultural entry or purchase of
lands withdrawn or classified as containing sodium or sulphur,” is authorized by the Mineral Leasing Act of February 25,
1920, and subsequent amendments. The U.S. Government’s interests are administered by the BLM which has designated an
area of 700,000 acres (283,280 hectares) as the Known Sodium Leasing Area (“KSLA”). In 1993, the BLM established a
Mechanical Mining Trona Area (“MMTA”) within the KSLA and suspended oil and gas leasing within the boundary. Our
mineral tenure and assets at Green River are strengthened by the KSLA and MMTA.
Mineral leasing authority by the State of Wyoming is granted in W.S. 36-6-101(b). The primary environmental
regulatory authority with respect to trona extraction is the WDEQ. The WDEQ is the primary issuer of the environmental
permits relevant to our operations, including air quality permits, mining and reclamation permits, as well as class III and class
V underground injection control permits.
Alkali Business - Green River, Wyoming
In 2017 we acquired our Alkali Business, making us the world’s leading producer of natural soda ash. Natural soda ash
is refined from trona, a sodium carbonate mineral composed of soda ash (Na2CO3), sodium bicarbonate (NaHCO3) and water
with the chemical formula Na2CO3NaHCO32H2O. Approximately 75% of the world’s natural soda ash is produced from trona
extracted from underground mines and solution mining in the Green River Basin of southwestern Wyoming.
The Green River trona beds are collectively the largest deposit of trona and the undisputed largest source of raw material
feed for the production of natural soda ash in the world. The origin of the trona deposits is the result of very unusual, geological
circumstances. Sodium-rich springs are believed to have fed ancient Lake Gosiute, a large, shallow inland lake that reached a
maximum extent of over 15,000 square miles (about 40,000 sq km) around 50 million years ago. In response to repetitive
cycles of lake expansion, contraction and evaporation, and changes in temperature and salinity, trona was precipitated in beds
of remarkable purity and extent. In addition to trona, the evaporite sodium mineral assemblage includes variable levels of other
sodium carbonate minerals as well as halite (NaCl). At least 25 beds of natural trona in the Wilkins Peak Member of the Eocene
Green River Formation exceed at least locally three feet (1 m) in thickness and are estimated by the USGS to contain a
cumulative resource of over 100 billion tons of trona. Individual trona beds are numbered in ascending order and trona beds of
significance lie at modern depths between about 400 to 2,000 feet (120-600 m). Our current dry mining and solution mining
operations exploit three trona beds, and our reserves are contained in four beds.
Our trona resources and mining operations are held under leases covering 88,342 acres (equivalent to 138 sq miles or
357 sq kilometers) over portions of 23 townships, primarily in two contiguous units informally known as the “Westvaco” and
“Granger” blocks. Mineral and mining rights are secured by leases from the Federal government, the State of Wyoming, and
Anadarko Petroleum. We lease approximately 25,215 acres from the U.S. Government under the Mineral Leasing Act of 1920
(Title 30 §181) which includes trona under its definition of a “solid leasable mineral.” Federal minerals are administered by the
U.S. Bureau of Land Management (BLM). We lease 40,883 acres from Anadarko Land Corporation, a subsidiary of Anadarko
Petroleum. Anadarko’s acquisition of the Union Pacific Railroad Group in 2000 included alternate sections of land for 20 miles
on either side of the trans-continental railroad, originally granted to Union Pacific under the Pacific Railroad Act of 1862 and
subsequent railroad land grants. We also lease 22,243 acres from the State of Wyoming. Royalty payments range from 6% to
8% of the sales value of soda ash products.
Our Westvaco site is located approximately 25 miles (40-65 km) north-northwest of Green River. We extract trona ore
from our Westvaco underground mine by mechanized, continuous mining methods. Our current underground dry mine
production is from a single, near-horizontal bed approximately 10 feet (3.05 meters) thick at a depth from surface of 1500-1600
feet (450-490 meters). Ore is extracted from an extensive network of parallel drifts and connecting cross-cuts, known as room-
and-pillar mining, and from longwall mining. Longwall miners shear off successive panels of ore which drops onto a conveyor
belt for delivery to vertical shafts to be hoisted to the surface. The Westvaco mine has been in uninterrupted, continuous
operation since its start in 1947 by Westvaco Chemical Company. The Westvaco interests were acquired by FMC in 1948.
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We also extract trona by secondary recovery solution mining operations in previously dry mined portions of the
Westvaco mine and in trona beds impacted by former dry mining of the Granger mine. The Granger mine and processing
facility, about 10 miles (15 km) northeast of the eponymous town, operated as an underground mine from 1976 to 2002. FMC
acquired the properties in 1999 by acquiring Tg Soda Ash, originally developed as a unit of Texasgulf and then owned by Elf
Atochem. FMC converted the mine and mill to solution mining in 2005. In our secondary recovery solution mining operations,
we pump process waters from our surface facilities, along with insoluble remnant from the processing of dry mined ore, into
former underground mine workings where the insoluble constituents settle out and sodium carbonate and bicarbonate are
leached from trona left behind from previous dry mining. The return mine water is pumped back to the Westvaco and Granger
surface processing facilities for recovery of sodium solids.
The following table summarizes the estimated in-place trona ore reserve of our Alkali Business:
Mine Deposit
Reserve Category
Million c tons
(dry weight)
Grade
(% Trona)
Dry extraction
Dry-mining
Solution mining
Solution mining
Alkali
Proven
Probable
Total Reserves
Proven
Probable
Total Reserves
Total Reserves
302.5
158.4
460.9
—
448.4
448.4
909.3
89.7
89.1
89.5
—
86.3
86.3
87.9
Our trona ore reserves are calculated from in-place trona-bearing material that can be economically and legally
extracted and processed into commercial products at the time of reserve determination. Our reserves estimates are developed
using industry-standard, best-practice procedures, and our disclosures have been reviewed internally and externally to ensure
compliance with SEC Industry Guide 7. Dry mining reserves and solution mining reserves are fundamentally different in terms
of extraction methods and costs, predicted recoveries and the procedures used for reserve calculations.
Estimated dry mining ore reserves of 460.9 million short tons include dilution from un-mineralized material within and
marginal to the trona ore bed. Support pillars are excluded from dry mining reserves, but a portion of the trona contained in the
pillars is recovered by solution mining, as described below. A bulk density factor of 133 lb/cu ft (2.16 g/cc) is used for
conversion of volumes to mass. Key dry mining parameters include minimum trona ore bed thickness, minimum trona grade,
and maximum percent insolubles. Mining cost assumptions are based on data accumulated from our 60+ years of experience in
the Green River trona district.
Solution mining ore reserves of 448.4 million short tons are reported on an in-place basis, inclusive of dilution from
insoluble material that remains in the ground. The solution mining reserves are calculated using recovery parameters developed
from our 20+ years of cumulative secondary recovery solution mining experience. Key factors include the surface area of
remaining support pillars and other trona-mineralized surfaces exposed to liquid solutions injected into voids created by dry
mining, solubility and alkalinity data, and predicted dissolution rates for sodium carbonate over residence times.
Dry mined and solution mined trona are refined into soda ash at our Westvaco and Granger facilities, located within the
boundaries of their respective contiguous lease blocks, and involve multiple processing lines, steam generation facilities,
evaporation ponds, spare parts warehouses, maintenance shops, and offices for engineering, production, and support staff. Our
Green River trona mining and processing facilities typically operate at an effective capacity of about four million short tons of
marketable soda ash per year.
The sum of our total proven and probable reserves estimated as of December 31, 2017, was 909 million short tons at an
average grade of about 87% trona, equates to approximately 550 million short tons of soda ash, sufficient to sustain production
for over 100 years at our current rate of approximately 4 million short tons per year of refined soda ash. Our 2017 reserve
disclosure is partially based the report of a third party consultant that generated an updated reserve estimate as of September 1,
2017. Our reported reserves reflect that estimate, reconciled with 2017 depletion. Our mine plan is inherently forward-looking,
under the meaning of the U.S. Securities Act of 1933 and subsequent amendments and is subject to uncertainties and
unanticipated events beyond our control.
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Available Information
The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at
100 F Street, N.E., Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room
by calling the SEC at 1-800-SEC-0330. We make available free of charge on our internet website (www.genesisenergy.com)
our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports
filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable
after we electronically file the material with, or furnish it to, the SEC. These documents are also available at the SEC’s website
(www.sec.gov). Additionally, on our internet website we make available our Corporate Governance Guidelines, Code of
Business Conduct and Ethics, Audit Committee Charter and Governance, Compensation and Business Development Committee
Charter. Information on our website is not incorporated into this Form 10-K or our other securities filings and is not a part of
this Form 10-K or our other securities filings.
Item 1A. Risk Factors
Risks Related to Our Business
Our indebtedness could adversely restrict our ability to operate, affect our financial condition, and prevent us from
complying with our requirements under our debt instruments and could prevent us from paying cash distributions to our
unitholders.
We have outstanding debt and the ability to incur more debt. As of December 31, 2017, we had approximately $1.1
billion outstanding of senior secured indebtedness and an additional $2.6 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; access capital
markets (debt and equity); or to otherwise fully realize the value of our assets and opportunities because of the need to
dedicate a substantial portion of our cash flows from operations to payments on our indebtedness or to comply with
any restrictive terms of our indebtedness;
limit our flexibility in planning for, or reacting to, changes in our businesses and the industries in which we operate;
and
place us at a competitive disadvantage as compared to our competitors that have less debt.
We may incur additional indebtedness (public or private) in the future under our existing credit agreement, by issuing
debt instruments, under new credit agreements, under joint venture credit agreements, under capital leases or synthetic leases,
on a project-finance or other basis or a combination of any of these. If we incur additional indebtedness in the future, it likely
would be under our existing credit agreement or under arrangements that may have terms and conditions at least as restrictive
as those contained in our existing credit agreement and the indentures governing our existing notes. Failure to comply with the
terms and conditions of any existing or future indebtedness would constitute an event of default. If an event of default occurs,
the lenders or noteholders will have the right to accelerate the maturity of such indebtedness and foreclose upon the collateral,
if any, securing that indebtedness. In addition, if there is a change of control as described in our credit facility, that would be an
event of default, unless our creditors agreed otherwise, and, under our credit facility, any such event could limit our ability to
fulfill our obligations under our debt instruments and to make cash distributions to unitholders which could adversely affect the
market price of our securities.
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In addition, from time to time, some of our joint ventures may have substantial indebtedness, which will include
affirmative and negative covenants and other provisions that limit their freedom to conduct certain operations, events of
default, prepayment and other customary terms.
We may not be able to access adequate capital (debt and/or equity) on economically viable terms or any terms.
The capital markets (debt and equity) have previously been from time to time disrupted and volatile as a result of
adverse conditions, including recessionary pressures, bubble-affects and precipitous commodity price declines. These
circumstances and events, which can last for extended periods of time, have led to reduced capital availability, tighter lending
standards and higher interest rates on loans for companies in the energy industry, especially non-investment grade companies.
Although we cannot predict the future condition of the capital markets, future turmoil in capital markets and the related higher
cost of capital could have a material adverse effect on our business, liquidity, financial condition and cash flows, particularly if
our ability to borrow money from lenders or access the capital markets to finance our operations were to be impaired for long.
If we are unable to access the amounts and types of capital we seek at a cost and/or on terms that have been available
to us historically, we could be materially and adversely affected. Such an inability to access capital could limit or prohibit our
ability to execute significant portions of our business plan, such as executing our growth strategy, refinancing our debt and/or
optimizing our capital structure.
We may not be able to fully execute our growth strategy due to various factors, such as unreceptive capital markets and/
or excessive competition for acquisitions.
Our strategy contemplates substantial growth through the development and acquisition of a wide range of midstream
and other energy infrastructure assets while maintaining a strong balance sheet. This strategy includes constructing and
acquiring additional assets and businesses to enhance our ability to compete effectively, diversify our asset portfolio and,
thereby, provide more stable cash flow. We regularly consider and enter into discussions regarding, and are currently
contemplating, additional potential joint ventures, stand-alone projects and other transactions that we believe will present
opportunities to realize synergies, expand our role in the energy infrastructure business, and increase our market position and,
ultimately, increase distributions to unitholders. A number of factors could adversely affect our ability to execute our growth
strategy, including an inability to raise adequate capital on acceptable terms, competition from competitors and/or an inability
to successfully integrate one or more acquired businesses into our operations.
We will need new capital to finance the future development and acquisition of assets and businesses. Limitations on
our access to capital will impair our ability to execute this strategy. Expensive capital will limit our ability to develop or acquire
accretive assets. Although we intend to continue to expand our business, this strategy may require substantial capital, and we
may not be able to raise the necessary funds on satisfactory terms, if at all.
In addition, we experience competition for the assets we purchase or contemplate purchasing. Increased competition
for a limited pool of assets could result in our not being the successful bidder more often or our acquiring assets at a higher
relative price than that which we have paid historically. Either occurrence would limit our ability to fully execute our growth
strategy. Our ability to execute our growth strategy may impact the market price of our securities.
We may be unable to integrate successfully businesses we acquire. We may incur substantial expenses, delays or other
problems in connection with our growth strategy that could negatively impact our results of operations. Moreover, acquisitions
and business expansions involve numerous risks, including:
•
•
•
difficulties in the assimilation of the operations, technologies, services and products of the acquired companies or
business segments;
inefficiencies and complexities that can arise because of unfamiliarity with new assets and the businesses associated
with them, including unfamiliarity with their markets; and
diversion of the attention of management and other personnel from day-to-day business to the development or
acquisition of new businesses and other business opportunities.
Our actual construction, development and acquisition costs could exceed our forecast, and our cash flow from
construction and development projects may not be immediate.
Our forecast contemplates significant expenditures for the development, construction or other acquisition of energy
infrastructure assets, including some construction and development projects with technological challenges. We (or our joint
ventures) may not be able to complete our projects at the costs currently estimated. If we (or our joint ventures) experience
material cost overruns, we will have to finance these overruns using one or more of the following methods:
•
•
•
using cash from operations;
delaying other planned projects;
incurring additional indebtedness; or
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•
issuing additional debt or equity.
Any or all of these methods may not be available when needed or may adversely affect our future results of
operations.
In addition, some construction projects require substantial investments over a long period of time before they begin
generating any meaningful cash flow.
Fluctuations in interest rates could adversely affect our business.
We have exposure to movements in interest rates. The interest rates on our credit facility ($1.1 billion outstanding at
December 31, 2017) are variable. Our results of operations and our cash flow, as well as our access to future capital and our
ability to fund our growth strategy, could be adversely affected by significant increases in interest rates.
An increase in interest rates may also cause a corresponding decline in demand for equity investments, in general, and
in particular, for yield-based equity investments such as our common units. Any such reduction in demand for our common
units resulting from other more attractive investment opportunities may cause the trading price of our common units to decline.
We may not have sufficient cash from operations to pay the current level of quarterly distribution following the
establishment of cash reserves and payment of fees and expenses.
The amount of cash we distribute on our units principally depends upon margins we generate from our businesses,
which fluctuate from quarter to quarter based on, among other things:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
the volumes and prices at which we purchase and sell crude oil, natural gas, refined products, and caustic soda;
the volumes of sodium hydrosulfide, or NaHS, and soda ash that we receive for our sodium minerals and sulfur
services and the prices at which we sell NaHS and soda ash;
the demand for our services;
the level of competition;
the level of our operating costs;
the effect of worldwide energy conservation measures;
governmental regulations and taxes;
the level of our general and administrative costs; and
prevailing economic conditions.
In addition, the actual amount of cash we will have available for distribution will depend on other factors that include:
the level of capital expenditures we make, including the cost of acquisitions (if any);
our debt service requirements;
fluctuations in our working capital;
restrictions on distributions contained in our debt instruments;
our ability to borrow under our working capital facility to pay distributions; and
the amount of cash reserves required in the conduct of our business.
Our ability to pay distributions each quarter depends primarily on our cash flow, including cash flow from financial
reserves and working capital borrowings, and our cash requirements, so it is not solely a function of profitability, which will be
affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and we may not
make distributions during periods when we record net income.
Our profitability and cash flow are dependent on our ability to increase or, at a minimum, maintain our current
commodity-crude oil, natural gas, refined products, soda ash, NaHS and caustic soda-volumes, which often depend on
actions and commitments by parties beyond our control.
Our profitability and cash flow are dependent on our ability to increase or, at a minimum, maintain our current
commodity-crude oil, natural gas, refined products, soda ash, NaHS, and caustic soda-volumes. We access commodity volumes
through various sources, such as our mines, producers, service providers (including gatherers, shippers, marketers and other
aggregators) and refiners. Depending on the needs of each customer and the market in which it operates, we can either provide
a service for a fee (as in the case of our pipeline, marine vessel and railcar transportation operations), we can acquire the
commodity from our customer and resell it to another party, or, in the case of soda ash, we can produce the commodity
ourselves.
Our source of volumes depends on successful exploration and development of additional crude oil and natural gas
reserves by others; our successful development of our trona reserves, continued demand for refining and our related sulfur
35
removal and other services, for which we are paid in NaHS; the breadth and depth of our logistics operations; the extent that
third parties provide NaHS for resale; and other matters beyond our control.
The crude oil, natural gas and refined products available to us and our refinery customers are derived from reserves
produced from existing wells, and these reserves naturally decline over time. In order to offset this natural decline, our energy
infrastructure assets must access additional reserves. Additionally, some of the projects we have planned or recently completed
are dependent on reserves that we expect to be produced from newly discovered properties that producers are currently
developing.
Finding and developing new reserves is very expensive, requiring large capital expenditures by producers for
exploration and development drilling, installing production facilities and constructing pipeline extensions to reach new wells.
Many economic and business factors out of our control can adversely affect the decision by any producer to explore for and
develop new reserves. These factors include the prevailing market price of the commodity, the capital budgets of producers, the
depletion rate of existing reservoirs, the success of new wells drilled, environmental concerns, regulatory initiatives, cost and
availability of equipment, capital budget limitations or the lack of available capital and other matters beyond our control.
Additional reserves, if discovered, may not be developed in the near future or at all. The precipitous decline in crude oil and
natural gas prices beginning in late 2014, which continued into 2017 has forced most producers to significantly curtail their
planned capital expenditures. Thus, crude oil and natural gas production in our market areas could decline, which could have a
material negative impact on our revenues and prospects.
Demand for our services is dependent on the demand for crude oil and natural gas. Any decrease in demand for crude
oil or natural gas, including by those refineries or connecting carriers to which we deliver could adversely affect our cash flows.
The demand for crude oil also is dependent on the competition from refineries, the impact of future economic conditions, fuel
conservation measures, alternative fuel requirements or sources fuel sources such as electricity, coal, fuel oils or nuclear energy,
government regulation or technological advances in fuel economy and energy generation devices, all of which could reduce
demand for our services. A reduction in demand for our services in the markets we serve could result in impairments of our
assets and have a material adverse effect on our business, financial condition and results of operations.
Our ability to access NaHS depends primarily on the demand for our proprietary sulfur removal process. Demand for
our services could be adversely affected by many factors, including lower refinery utilization rates, U.S. refineries accessing
more “sweet” (instead of "sour") crude, and the development of alternative sulfur removal processes that might be more
economically beneficial to refiners.
We are dependent on third parties for NaOH for use in our sulfur removal process as well as volume to market to third
parties. Should regulatory requirements or operational difficulties disrupt the manufacture of caustic soda by these producers,
we could be affected.
Our sulfur removal operations are dependent upon the supply of caustic soda, the demand for NaHS, and the
continuing operations of the refiners for whom we process sour natural gas.
Caustic soda is a major component of the proprietary sulfur removal process we provide to our refinery customers.
Because we are a large consumer of caustic soda, we can leverage our economies of scale and logistics capabilities to
effectively market caustic soda to third parties. NaHS, the resulting by-product from our sulfur removal operations, is a vital
ingredient in a number of industrial and consumer products and processes. Any decrease in the supply of caustic soda could
affect our ability to provide sulfur removal services to refiners and any decrease in the demand for NaHS by the parties to
whom we sell the NaHS could adversely affect our business. Refineries’ need for our sulfur removal services is also dependent
on refining competition from other refineries by refiners to process more “sweet” (instead of sour) crude, the impact of future
economic conditions, fuel conservation measures, alternative fuel requirements, government regulation or technological
advances in fuel economy and energy generation devices, all of which could reduce demand for our services.
Our crude oil and natural gas transportation operations are dependent upon demand for crude oil by refiners, primarily
in the Midwest and Gulf Coast, and the demand for natural gas.
Any decrease in this demand for crude oil by those refineries or connecting carriers to which, or for the natural gas, we
deliver could adversely affect our cash flows. Those refineries’ demand for crude oil also is dependent on the competition from
other refineries, the impact of future economic conditions, fuel conservation measures, alternative fuel requirements,
government regulation or technological advances in fuel economy and energy generation devices, all of which could reduce
demand for our services. The demand for natural gas is dependent on the impact of future economic conditions, fuel
conservation measures, alternative fuel requirements and alternative fuel sources such as electricity, coal, fuel oils or nuclear
energy, government regulation or technological advances in fuel economy and energy generation devices, all of which could
reduce demand for our services.
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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 who’s drilling activity levels and
spending for transportation have been, and may continue to be, impacted by the deterioration in the commodity markets.
Many of our customers finance their drilling activities through cash flow from operations, the incurrence of debt or the
issuance of equity. New credit facilities and other debt financing from institutional sources have generally become more
difficult and expensive to obtain, and there may be a general reduction in the amount of credit available in the markets in which
we conduct business. Additionally, many of our customers’ equity values have substantially declined. Adverse price changes
put downward pressure on drilling budgets for crude oil and natural gas producers, which have resulted, and could continue to
result, in lower volumes than we otherwise would have seen being transported on our pipeline and transportation systems,
which could have a material negative impact on our revenues and prospects. For example, prices for crude oil declined
precipitously in the second half of 2014 from approximately $109 per barrel in June 2014 to approximately $30 per barrel in
January 2016, recovered to approximately $53 per barrel as of the end of January, 2017, and may continue such volatility going
forward.
Fluctuations in prices for crude oil, refined petroleum products, NaHS, soda ash and caustic soda could adversely
affect our business.
Because we purchase (or otherwise acquire) and sell crude oil, refined petroleum products, NaHS soda ash and caustic
soda we are exposed to some direct commodity price risks. Prices for those commodities can fluctuate in response to changes
in supply, market uncertainty and a variety of additional factors that are beyond our control, which could have an adverse effect
on our cash flows, profit and/or Segment Margin. We attempt to limit those commodity price risks through back-to-back
purchases and sales, hedges and other contractual arrangements; however, we cannot completely eliminate our commodity
price risk exposure.
37
Our use of derivative financial instruments could result in financial losses.
We use derivative financial instruments and other hedging mechanisms from time to time to limit a portion of the
effects resulting from changes in commodity prices. To the extent we hedge our commodity price exposure, we forego the
benefits we would otherwise experience if commodity prices were to increase. In addition, we could experience losses resulting
from our hedging and other derivative positions. Such losses could occur under various circumstances, including if our
counterparty does not perform its obligations under the hedge arrangement, our hedge is imperfect, or our hedging policies and
procedures are not followed.
Non-utilization of certain assets could significantly reduce our profitability due to the fixed costs incurred with respect
to such assets.
From time to time in connection with our business, we may lease or otherwise secure the right to use certain third
party assets (such as railcars, trucks, barges, pipeline capacity, storage capacity and other similar assets) with the expectation
that the revenues we generate through the use of such assets will be greater than the fixed costs we incur pursuant to the
applicable leases or other arrangements. However, when such assets are not utilized or are under-utilized, our profitability is
negatively affected because the revenues we earn are either non-existent or reduced (in the event of under-utilization), but we
remain obligated to continue paying any applicable fixed charges, in addition to incurring any other costs attributable to the
non-utilization of such assets. For example, in connection with our rail operations, we lease all of our railcars that obligate us to
pay the applicable lease rate without regard to utilization. If business conditions are such that we do not utilize a portion of our
leased assets for any period of time, we will still be obligated to pay the applicable fixed lease rate. In addition, during the
period of time that we are not utilizing such assets, we will incur incremental costs associated with the cost of storing such
assets, and we will continue to incur costs for maintenance and upkeep. Our failure to utilize a significant portion of our leased
assets and other similar assets could have a significant negative impact on our profitability and cash flows.
In addition, certain of our field and pipeline operating costs and expenses are fixed and do not vary with the volumes
we gather and transport. These costs and expenses may not decrease ratably or at all should we experience a reduction in our
volumes transported by truck, marine vessel or rail or transported by our pipelines. As a result, we may experience declines in
our margin and profitability if our volumes decrease.
We cannot cause our joint ventures to take or not to take certain actions unless some or all of the joint venture
participants agree.
Due to the nature of joint ventures, each participant (including us) in our material joint ventures has made substantial
investments (including contributions and other commitments) in that joint venture and, accordingly, has required that the
relevant charter documents contain certain features designed to provide each participant with the opportunity to participate in
the management of the joint venture and to protect its investment in that joint venture, as well as any other assets which may be
substantially dependent on or otherwise affected by the activities of that joint venture. These participation and protective
features include a corporate governance structure that consists of a management committee composed of members, only some
of which are appointed by us. In addition, many of our joint ventures are operated by our “partners” and have “stand-alone”
credit agreements that limit their freedom to take certain actions. Thus, without the concurrence of the other joint venture
participants and/or the lenders of our joint venture participants, we cannot cause our joint ventures to take or not to take certain
actions, even though those actions may be in the best interest of the joint ventures or us.
The insolvency of an operator of our joint ventures, the failure of an operator of our joint ventures to adequately
perform operations or an operator’s breach of applicable agreements could reduce our revenue and result in our liability to
governmental authorities for compliance with environmental, safety and other regulatory requirements and to the operator’s
suppliers and vendors. As a result, the success and timing of development activities of our joint ventures operated by others and
the economic results derived therefrom depends upon a number of factors outside our control, including the operator’s timing
and amount of capital expenditures, expertise and financial resources, and the inclusion of other participants.
In addition, joint venture participants may have obligations that are important to the success of the joint venture, such
as the obligation to pay their share of capital and other costs of the joint venture. The performance and ability of third parties to
satisfy their obligations under joint venture arrangements is outside our control. If these third parties do not satisfy their
obligations under these arrangements, our business may be adversely affected.
We are exposed to the credit risk of our customers in the ordinary course of our business activities.
When we (or our joint ventures) market our products or services, we (or our joint ventures) must determine the
amount, if any, of the line of credit. Since certain transactions can involve very large payments, the risk of nonpayment and
nonperformance by customers, industry participants and others is an important consideration in our business.
For example, in those cases where we provide division order services for crude oil and natural gas purchased at the
wellhead, we may be responsible for distribution of proceeds to all of the interest owners. In other cases, we pay all of or a
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portion of the production proceeds to an operator who distributes these proceeds to the various interest owners. These
arrangements expose us to operator credit risk. As a result, we must determine that operators have sufficient financial resources
to make such payments and distributions and to indemnify and defend us in case of a protest, action or complaint.
Additionally, we sell NaHS, soda ash and caustic soda to customers in a variety of industries. Some of these customers
are in industries that have been impacted by a decline in demand for their products and services. Even if our credit review and
analytical procedures work properly, we have experienced, and we could continue to experience losses in dealings with other
parties.
Further, many of our customers were impacted by the weakened economic conditions, and precipitous decline in
commodity prices, such as crude oil, natural gas, copper, molybdenum, and aluminum experienced in recent years in a manner
that influenced the need for our products and services and their ability to pay us for those products and services. It is uncertain
if commodity prices will increase in the near future.
We may not be able to renew our marine transportation time charters and contracts when they expire at favorable rates
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, 2017, our marine transportation segment received approximately 64% 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 36% of our marine transportation revenues from
spot contracts, where competition is high and rates are typically volatile and subject to short-term market fluctuations, and
where we bear the risk of vessel downtime due to weather and navigational delays. If we deploy a greater percentage of our
vessels in the spot market, we may experience a lower overall utilization of our fleet through waiting time or ballast voyages,
leading to a decline in our operating revenue and gross profit. There can be no assurance that we will be able to enter into
future time charters or other fixed contracts on terms favorable to us. For further discussion of our marine transportation
contracts, see “Marine Transportation - Customers”.
Our operations are subject to federal, state and local environmental protection and safety laws and regulations.
Our operations are subject to the risk of incurring substantial environmental and safety related costs and liabilities. In
particular, our operations are subject to stringent federal, state and local environmental protection and safety laws and
regulations. These laws and regulations may (i) require the acquisition of and compliance with permits for regulated activities,
(ii) limit or prohibit operations on environmentally sensitive lands such as wetlands or wilderness areas, seismically sensitive
areas, or areas inhabited by endangered or threatened species, (iii) result in capital expenditures to limit or prevent emissions or
discharges, and (iv) place burdensome restrictions on our operations, including the management and disposal of wastes. Failure
to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, including
the assessment of monetary penalties, the imposition of investigatory and remedial obligations, the suspension or revocation of
necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and the issuance
of orders enjoining future operations or imposing additional compliance requirements. Changes in environmental laws and
regulations occur frequently, typically increasing in stringency through time, and any changes that result in more stringent and
costly operating restrictions, emission control, waste handling, disposal, cleanup and other environmental requirements have
the potential to have a material adverse effect on our operations. While we believe that we are in substantial compliance with
current environmental laws and regulations and that continued compliance with existing requirements would not materially
affect us, there is no assurance that this trend will continue in the future. Revised or new additional regulations that result in
increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our
customers, could have a material adverse effect on our business, financial position, results of operations and cash flows.
Moreover, our operations, including the transportation and storage of crude oil, natural gas and other commodities, involves a
risk that crude oil, natural gas and related hydrocarbons or other substances may be released into the environment, which may
result in substantial expenditures for a response action, significant government penalties, liability to government agencies for
natural resources damages, liability to private parties for personal injury or property damages, and significant business
interruption. These costs and liabilities could rise under increasingly strict environmental and safety laws, including regulations
and enforcement policies, or claims for damages to property or persons resulting from our operations. If we are unable to
recover such resulting costs through increased rates or insurance reimbursements, our cash flows and distributions to our
unitholders could be materially affected. See “Regulation - Environmental Regulations” for additional discussion of
environmental laws and regulations affecting our operations.
Climate change legislation and regulatory initiatives may decrease demand for the products we store, transport and sell
and increase our operating costs.
In December 2009,the EPA published its findings that emissions of carbon dioxide, methane and other GHGs present
an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing
to the warming of the earth's atmosphere and other climatic changes. These findings served as a statutory prerequisite for EPA
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to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the CAA. The EPA has
adopted two sets of related rules, one which purports to regulate emissions of GHGs from motor vehicles and the other of
which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial
facilities. The EPA finalized the motor vehicle rule in April 2010 and it became effective in July 2010. The EPA adopted the
stationary source rule, also known as the "Tailoring Rule," in May 2010, and it became effective in January 2011. The tailoring
rule established new GHG emissions thresholds that determine when stationary sources must obtain permits under the PSD and
Title V programs of the Clean Air Act. On June 23, 2014, in Utility Air Regulatory Group v. EPA (“UARG v. EPA”), the
Supreme Court held that stationary sources could not become subject to PSD or Title V permitting solely by reason of their
GHG emissions. The Court ruled, however, that the EPA may require installation of best available control technology for GHG
emissions at sources otherwise subject to the PSD and Title V programs. On August 26, 2016, the EPA proposed changes
needed to bring the EPA’s air permitting regulations in line with the Supreme Court’s decision on GHG permitting. The
proposed rule was published in the Federal Register on October 3, 2016 and the public comment period closed on December 2,
2016.
Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified
large GHG emission sources in the U.S. beginning in 2011 for emissions occurring in 2010. Further, in November 2010, the
EPA expanded its existing GHG reporting rule to include onshore and offshore crude oil and natural gas production and
onshore processing, transmission, storage and distribution facilities, which may include certain of our facilities, beginning in
2012 for emissions occurring in 2011. In October 2015, the EPA amended the GHG reporting rule to add the reporting of GHG
emissions from gathering and boosting systems, completions and workovers of crude oil wells using hydraulic fracturing, and
blowdowns of natural gas transmission pipelines. As a result of this continued regulatory focus, future GHG regulations of the
crude oil and natural gas industry remain a possibility.
Further, the U.S. Congress has from time to time considered various proposals to reduce GHG emissions, and almost
half of the states, either individually or through multi-state regional initiatives, have already taken legal measures to reduce
GHG emissions, primarily through the planned development of GHG emission inventories and/or GHG cap-and-trade
programs. The net effect of this legislation is to impose increasing costs on the combustion of carbon-based fuels such as crude
oil, refined petroleum products and natural gas. Our compliance with any future legislation or regulation of GHGs, if it occurs,
may result in materially increased compliance and operating costs.
In addition, in December 2015, the United States participated in the 21st Conference of the Parties, or COP-21, of the
United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties
to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of
GHGs. The Agreement went into effect on November 4, 2016. The Agreement establishes a framework for the parties to
cooperate and report actions to reduce GHG emissions. However, on June 1, 2017, President Trump announced that the United
States would withdraw from the Paris Agreement, and begin negotiations to either re-enter or negotiate an entirely new
agreement with more favorable terms for the United States. The Paris Agreement sets forth a specific exit process, whereby a
party may not provide notice of its withdrawal until three years from the effective date, with such withdrawal taking effect one
year from such notice. It is not clear what steps the Trump Administration plans to take to withdraw from the Paris Agreement,
whether a new agreement can be negotiated, or what terms would be included in such an agreement. Furthermore, in response
to the announcement, many state and local leaders have stated their intent to intensify efforts to uphold the commitments set
forth in the international accord.
The effect on our operations of CAA regulations, legislative efforts or related implementation regulations that regulate
or restrict emissions of GHGs in areas that we conduct business could adversely affect the demand for the products that we
transport, store and distribute and, depending on the particular program adopted, could increase our costs to operate and
maintain our facilities by requiring that we, among other things, measure and report our emissions, install new emission
controls on our facilities, acquire allowances to authorize our GHG emissions, pay any taxes related to our GHG emissions and
administer and manage a GHG emissions program. We may be unable to include some or all of such increased costs in the rates
charged by our pipelines or other facilities, and any such recovery may depend on events beyond our control, including the
outcome of future rate proceedings before the FERC or state regulatory agencies and the provisions of any final legislation or
implementing regulations. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries
could also increase the cost of consuming, and thereby adversely affect demand for the crude oil and natural gas that we
produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our
business, financial condition and results of operations. It is not possible at this time to predict with any accuracy the structure or
outcome of any future legislative or regulatory efforts to address such emissions or the eventual costs to us of compliance.
Furthermore, there have also 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
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GHG emissions from crude oil and natural gas operations constitute a public nuisance under federal and/or state common law.
As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could
allege personal injury, property damages, or other liabilities. While our business is not a party to any such litigation, we could
be named in actions making similar allegations. An unfavorable ruling in any such case could adversely impact our business,
financial condition and results of operations.
Moreover, there has been public discussion that climate change may be associated with extreme weather conditions
such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible
consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could
cause some areas to experience temperatures substantially hotter or colder than their historical averages. Extreme weather
conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be
fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm
or weather hazards affecting our operations.
Restrictions on drilling or mining activities to protect certain species of wildlife could adversely affect our business.
The federal Endangered Species Act and analogous state statutes restrict activities that may adversely affect
endangered and threatened species or their habitat. Similar protections are offered to migratory birds under the Migratory Bird
Treaty Act, though, in December 2017, the U.S. Fish and Wildlife Service provided guidance limiting the reach of the Act. The
designation of previously unidentified endangered or threatened species in areas where we operate could cause us to incur
additional costs or become subject to operating delays, restrictions or bans.
We have reclamation and mine closing obligations. If the assumptions underlying our accruals are inaccurate, we
could be required to expend greater amounts than anticipated.
Our mining operations in Wyoming are subject to mine permits issued by the Land Quality Division of the Wyoming
Department of Environmental Quality (“WDEQ”). WDEQ imposes detailed reclamation obligations on us as a holder of mine
permits. We accrue for the costs of current mine disturbance and of final mine closure. The amounts recorded are dependent
upon a number of variables, including the estimated future closure costs, estimated proven reserves, assumptions involving
profit margins, inflation rates and the assumed credit-adjusted risk-free interest rates. If these accruals are insufficient or our
liability in a particular year is greater than currently anticipated, our future operating results could be materially adversely
affected.
Failure to obtain or renew surety bonds on acceptable terms could affect our ability to secure reclamation obligations
and, therefore, our ability to conduct our mining operations.
We are required to obtain surety bonds or post other financial security to secure performance or payment of certain
long-term obligations, such as mine closure or reclamation costs. The amount of security required to be obtained can change as
the result of new laws, as well as changes to the factors used to calculate the bonding or security amounts. We may have
difficulty procuring or maintaining our surety bonds. Our bond issuers may demand higher fees or additional collateral,
including letters of credit or other terms less favorable to us upon those renewals. Because we are required to have these bonds
or other acceptable security in place before mining can commence or continue, our failure to maintain surety bonds, letters of
credit or other guarantees or security arrangements would materially and adversely affect our ability to mine trona. That failure
could result from a variety of factors, including lack of availability, higher expense or unfavorable market terms, the exercise
by third-party surety bond issuers of their right to refuse to renew the surety and restrictions on availability of collateral for
current and future third-party surety bond issuers under the terms of our financing arrangements.
Regulation of the rates, terms and conditions of services and a changing regulatory environment could affect our
financial position, results of operations or cash flow.
FERC regulates certain of our energy infrastructure assets engaged in interstate operations. Our intrastate pipeline
operations are regulated by state agencies. Our railcar operations are subject to the regulatory jurisdiction of the Federal
Railroad Administration of the DOT, the Occupational Safety and Health Administration, as well as other federal and state
regulatory agencies. This regulation extends to such matters as:
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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.
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In addition, some of our pipelines and other infrastructure are subject to laws providing for open and/or non-
discriminatory access.
Given the extent of this regulation, the evolving nature of federal and state regulation and the possibility for additional
changes, the current regulatory regime may change and affect our financial position, results of operations or cash flow.
A natural disaster, accident, terrorist attack or other interruption event involving us could result in severe personal
injury, property damage and/or environmental damage, which could curtail our operations and otherwise adversely affect
our assets and cash flow.
Some of our operations involve significant risks of severe personal injury, property damage and environmental
damage, any of which could curtail our operations and otherwise expose us to liability and adversely affect our cash flow.
Virtually all of our operations are exposed to the elements, including hurricanes, tornadoes, storms, floods and earthquakes. A
significant portion of our operations are located along the U.S. Gulf Coast, and our offshore pipelines are located in the Gulf of
Mexico. These areas can be subject to hurricanes.
If one or more facilities that are owned by us or that connect to us is damaged or otherwise affected by severe weather
or any other disaster, accident, catastrophe or event, our operations could be significantly interrupted. Similar interruptions
could result from damage to production or other facilities that supply our facilities or other stoppages arising from factors
beyond our control. These interruptions might involve significant damage to people, property or the environment, and repairs
might take from a week or less for a minor incident to six months or more for a major interruption. Any event that interrupts the
fees generated by our energy infrastructure assets, or which causes us to make significant expenditures not covered by
insurance, could reduce our cash available for paying our interest obligations as well as unitholder distributions and,
accordingly, adversely impact the market price of our securities. Additionally, the proceeds of any property insurance
maintained by us may not be paid in a timely manner or be in an amount sufficient to meet our needs if such an event were to
occur, and we may not be able to renew it or obtain other desirable insurance on commercially reasonable terms, if at all.
On September 11, 2001, the U.S. was the target of terrorist attacks of unprecedented scale. Since the September 11
attacks, the U.S. government has issued warnings that energy assets, specifically the nation’s pipeline infrastructure, may be the
future targets of terrorist organizations. These developments have subjected our operations to increased risks. Any future
terrorist attack at our facilities, those of our customers and, in some cases, those of other pipelines, could have a material
adverse effect on our business.
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.
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Our business would be adversely affected if we failed to comply with the Jones Act foreign ownership provisions.
We are subject to the Jones Act and other federal laws that restrict maritime cargo transportation between points in the
U.S. only to vessels operating under the U.S. flag, built in the U.S., at least 75% owned and operated by U.S. citizens (or
owned and operated by other entities meeting U.S. citizenship requirements to own vessels operating in the U.S. coastwise
trade and, in the case of limited partnerships, where the general partner meets U.S. citizenship requirements) and manned by
U.S. crews. To maintain our privilege of operating vessels in the Jones Act trade, we must maintain U.S. citizen status for Jones
Act purposes. To ensure compliance with the Jones Act, we must be U.S. citizens qualified to document vessels for coastwise
trade. We could cease being a U.S. citizen if certain events were to occur, including if non-U.S. citizens were to own 25% or
more of our equity interest or were otherwise deemed to control us or our general partner. We are responsible for monitoring
ownership to ensure compliance with the Jones Act. The consequences of our failure to comply with the Jones Act provisions
on coastwise trade, including failing to qualify as a U.S. citizen, would have an adverse effect on us as we may be prohibited
from operating our vessels in the U.S. coastwise trade or, under certain circumstances, permanently lose U.S. coastwise trading
rights or be subject to fines or forfeiture of our vessels.
Our business would be adversely affected if the Jones Act provisions on coastwise trade or international trade
agreements were modified or repealed or as a result of modifications to existing legislation or regulations governing the
crude oil and natural gas industry in response to the recent lifting of the crude oil export ban and the Deepwater Horizon
drilling rig incident in the U.S. Gulf of Mexico and subsequent crude oil spill.
If the restrictions contained in the Jones Act were repealed or altered or certain international trade agreements were
changed, the maritime transportation of cargo between U.S. ports could be opened to foreign flag or foreign-built vessels. The
Secretary of the Department of Homeland Security, or the Secretary, is vested with the authority and discretion to waive the
coastwise laws if the Secretary deems that such action is necessary in the interest of national defense. Any waiver of the
coastwise laws, whether in response to natural disasters or otherwise, could result in increased competition from foreign
product carrier and barge operators, which could reduce our revenues and cash available for distribution.
In December 2015, Congress voted to lift the four decade crude oil export ban. Although the impact of this legislation
is not yet determinable, increased exports of U.S. crude oil may lead to increased calls to repeal or modify the Jones Act. Even
before lifting the export ban, in the past several years, interest groups have lobbied Congress to repeal or modify the Jones Act
to facilitate foreign-flag competition for trades and cargoes currently reserved for U.S. flag vessels under the Jones Act.
Foreign-flag vessels generally have lower construction costs and generally operate at significantly lower costs than we do in
U.S. markets, which would likely result in reduced charter rates. We believe that continued efforts will be made to modify or
repeal the Jones Act. If these efforts are successful, foreign-flag vessels could be permitted to trade in the U.S. coastwise trade
and significantly increase competition with our fleet, which could have an adverse effect on our business.
Events within the crude oil and natural gas industry, such as the April 2010 fire and explosion on the Deepwater
Horizon drilling rig in the U.S. Gulf of Mexico and the resulting crude oil spill and moratorium on certain drilling activities in
the U.S. Gulf of Mexico implemented by the Bureau of Ocean Energy Management, Regulation and Enforcement (formerly,
the Minerals Management Service), may adversely affect our customers’ operations and, consequently, our operations. Such
events may also subject companies operating in the crude oil and natural gas industry, including us, to additional regulatory
scrutiny and result in additional regulations and restrictions adversely affecting the U.S. crude oil and natural gas industry.
A decrease in the cost of importing refined petroleum products could cause demand for U.S. flag product carrier and
barge capacity and charter rates to decline, which would decrease our revenues and our ability to pay cash distributions on
our units.
The demand for U.S. flag product carriers and barges is influenced by the cost of importing refined petroleum
products. Historically, charter rates for vessels qualified to participate in the U.S. coastwise trade under the Jones Act have been
higher than charter rates for foreign flag vessels. This is due to the higher construction and operating costs of U.S. flag vessels
under the Jones Act requirements that such vessels be built in the U.S. and manned by U.S. crews. This has made it less
expensive for certain areas of the U.S. that are underserved by pipelines or which lack local refining capacity, such as in the
Northeast, to import refined petroleum products carried aboard foreign flag vessels than to obtain them from U.S. refineries. If
the cost of importing refined petroleum products decreases to the extent that it becomes less expensive to import refined
petroleum products to other regions of the East Coast and the West Coast than producing such products in the U.S. and
transporting them on U.S. flag vessels, demand for our vessels and the charter rates for them could decrease.
The lifting of the U.S. crude oil export ban could adversely impact our U.S. Flag Fleet.
In December 2015, Congress voted to lift the four decade crude oil export ban. Although the impact of this legislation
on our U.S. Flag fleet’s operations is not determinable, the easing of the crude oil export ban could result in reduced coastwise
transportation of crude oil, which may have an adverse impact on our U.S. Flag segment.
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We face periodic dry-docking costs for our vessels, which can be substantial.
Vessels must be dry-docked periodically for regulatory compliance and for maintenance and repair. Our dry-docking
requirements are subject to associated risks, including delay, cost overruns, lack of necessary equipment, unforeseen
engineering problems, employee strikes or other work stoppages, unanticipated cost increases, inability to obtain necessary
certifications and approvals and shortages of materials or skilled labor. A significant delay in dry-dockings could have an
adverse effect on our marine transportation contract commitments. The cost of repairs and renewals required at each dry-dock
are difficult to predict with certainty and can be substantial.
The U.S. inland waterway infrastructure is aging and may result in increased costs and disruptions to our marine
transportation segment.
Maintenance of the U.S. inland waterway system is vital to our marine transportation operations. The system is
composed of over 12,000 miles of commercially navigable waterway, supported by over 240 locks and dams designed to
provide flood control, maintain pool levels of water in certain areas of the country and facilitate navigation on the inland river
system. The U.S. inland waterway infrastructure is aging, with more than half of the locks over 50 years old. As a result, due to
the age of the locks, scheduled and unscheduled maintenance outages may be more frequent in nature, resulting in delays and
additional operating expenses. Failure of the federal government to adequately fund infrastructure maintenance and
improvements in the future would have a negative impact on our ability to deliver products for its marine transportation
customers on a timely basis.
As a result of our Alkali Business Acquisition, the scope and size of our operations and business has substantially
changed. We cannot provide assurance that our expansion in scope and size will be successful.
Our Alkali Business Acquisition has substantially expanded the scope and size of our business by adding substantial
assets and operations to our existing business. The anticipated future growth of our business will impose significant added
responsibilities on management, including the need to identify, recruit, train and integrate additional employees. Our senior
management’s attention may be diverted from the management of daily operations to the integration of the assets acquired in
our Alkali Business Acquisition. Our ability to manage our business and growth will require us to continue to improve our
operational, financial and management controls, reporting systems and procedures. We may also encounter risks, costs and
expenses associated with any undisclosed or other unanticipated liabilities and use more cash and other financial resources on
integration and implementation activities than we expect. We may not be able to successfully integrate our Alkali Business into
our existing operations or realize the expected economic benefits of our Alkali Business Acquisition, which may have a
material adverse effect on our business, financial condition and results of operations, including our distributable cash flow.
Failure to successfully combine our business with the assets acquired in our Alkali Business Acquisition, or an
inaccurate estimate by us of the benefits to be realized from our Alkali Business Acquisition, may adversely affect our future
results.
Our Alkali Business Acquisition involves potential risks, including:
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the failure to realize expected profitability, growth or accretion;
environmental or regulatory compliance matters or liabilities;
antitrust or legal compliance matters or liabilities;
labor compliance matters or liabilities;
title or permit issues;
the incurrence of significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or
restructuring charges; and
the incurrence of unanticipated liabilities and costs for which indemnification is unavailable or inadequate.
The expected benefits from our Alkali Business Acquisition may not be realized if our estimates of the potential net
cash flows associated with the assets acquired by us in our Alkali Business Acquisition are materially inaccurate or if we failed
to identify operating issues or liabilities associated with the assets prior to closing. The accuracy of our estimates of the
potential net cash flows attributable to such assets is inherently uncertain. If certain issues are identified following the closing
of our Alkali Business Acquisition, the stock purchase agreement provides for limited recourse against Tronox.
If any of these risks or unanticipated liabilities or costs materialize, any desired benefits of our Alkali Business
Acquisition may not be fully realized, if at all, and our future financial condition, results of operations and distributable cash
flow could be negatively impacted.
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Risks Related to Our Partnership Structure
Our significant unitholders may sell units or other limited partner interests in the trading market, which could reduce
the market price of common units.
As of December 31, 2017, we have a number of significant unitholders. For example, certain members of the Davison
family (including their affiliates) and management owned approximately 17 million or 13.7% of our common units. From time
to time, we also may have other unitholders that have large positions in our common units. In the future, any such parties may
acquire additional interest or dispose of some or all of their interest. If they dispose of a substantial portion of their interest in
the trading markets, such sales could reduce the market price of common units. In connection with certain transactions, we
have put in place resale shelf registration statements, which allow unit holders thereunder to sell their common units at any time
(subject to certain restrictions) and to include those securities in any equity offering we consummate for our own account.
Individual members of the Davison family can exert significant influence over us and may have conflicts of interest
with us and may be permitted to favor their interests to the detriment of our other unitholders.
James E. Davison and James E. Davison, Jr., each of whom is a director of our general partner, each own a significant
portion of our common units, including our Class B Common Units, the holders of which elect our directors. Other members
of the Davison family also own a significant portion of our common units. Collectively, members of the Davison family and
their affiliates own approximately 10.1% of our Class A Common Units and 76.9% 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 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.
45
Unitholders with registration rights have rights to require underwritten offerings that could limit our ability to raise
capital in the public equity market.
Unitholders with registration rights have rights to require us to conduct underwritten offerings of our common units. If
we want to access the capital markets (debt and equity), those unitholders’ ability to sell a portion of their common units could
satisfy investor’s demand for our common units or may reduce the market price for our common units, thereby reducing the net
proceeds we would receive from a sale of newly issued units.
We may issue additional common units without unitholder’s approval, which would dilute their ownership interests.
We may issue an unlimited number of limited partner interests of any type without the approval of our unitholders.
The issuance of additional common units or other equity securities of equal or senior rank will have the following
effects:
•
•
•
•
our unitholders’ proportionate ownership interest in us will decrease;
the amount of cash available for distribution on each unit may decrease;
the relative voting strength of each previously outstanding unit may be diminished; and
the market price of our common units may decline.
Our general partner has a limited call right that may require unitholders to sell their units at an undesirable time or
price.
If at any time our general partner and its affiliates own more than 80% of any class of our units, our general partner
will have the right, but not the obligation, which it may assign to any of its affiliates, including any controlling unitholder, or to
us, to acquire all, but not less than all, of the units held by unaffiliated persons at a price not less than their then-current market
price. As a result, unitholders may be required to sell their units at an undesirable time or price and may not receive any return
on their investment. Unitholders may also incur a tax liability upon a sale of their units.
The interruption of distributions to us from our subsidiaries and joint ventures could affect our ability to make
payments on indebtedness or cash distributions to our unitholders.
We are a holding company. As such, our primary assets are the equity interests in our subsidiaries and joint ventures.
Consequently, our ability to fund our commitments (including payments on our indebtedness) and to make cash distributions
depends upon the earnings and cash flow of our subsidiaries and joint ventures and the distribution of that cash to us.
Distributions from our joint ventures are subject to the discretion of their respective management committees. Further, certain
joint ventures’ charter documents may vest in their management committees’ certain discretion regarding cash distributions.
Accordingly, our joint ventures may not continue to make distributions to us at current levels or at all.
We do not have the same flexibility as other types of organizations to accumulate cash and equity to protect against
illiquidity in the future.
Unlike a corporation, our partnership agreement requires us to make quarterly distributions to our unitholders of all
available cash reduced by any amounts reserved for commitments and contingencies, including capital and operating costs and
debt service requirements. The value of our units and other limited partner interests may decrease in direct correlation with
decreases in the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the future, we may not be
able to issue more equity to recapitalize.
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them.
Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the
distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three
years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of
the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted
limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to
the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the
liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their
partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a
distribution is permitted.
Unitholder liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for
those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership
46
is organized under Delaware law, and we conduct business in other states. The limitations on the liability of holders of limited
partner interests for the obligations of a limited partnership have not been clearly established in some states in which we do
business or may do business in from time to time in the future. Unitholders could be liable for any and all of our obligations as
if unitholders were a general partner if a court or government agency were to determine that:
• we were conducting business in a state but had not complied with that particular state’s partnership statute; or
•
unitholders right to act with other unitholders to remove or replace our general partner, to approve some amendments
to our partnership agreement or to take other actions under our partnership agreement constitutes “control” of our
business.
Tax Risks to Our Common Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as us not being
subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service, or IRS, were to
treat us as a corporation (for U.S. federal income tax purposes) or if we were to become subject to a material amount of
entity-level taxation for state tax purposes, then our cash available for distribution to our unitholders would be substantially
reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated
as a partnership for federal income tax purposes. Section 7704 of the Internal Revenue Code provides that publicly traded
partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to in this discussion as the
“Qualifying Income Exception,” exists with respect to publicly traded partnerships 90% or more of the gross income of which
for each taxable year consists of “qualifying income.” If less than 90% of our gross income for any taxable year is “qualifying
income” from transportation, processing or marketing of natural resources (including minerals, crude oil, natural gas or
products thereof), interest or dividends income, we will be taxable as a corporation under Section 7704 of the Internal Revenue
Code for federal income tax purposes for that taxable year and all subsequent years. We have not requested a ruling from the
IRS with respect to our treatment as a partnership for federal income tax purposes.
The decision of the U.S. Court of Appeals for the Fifth Circuit in Tidewater Inc. v. U.S., 565 F.3d 299 (5th Cir. April
13, 2009) held that the marine time charter being analyzed in that case was a “lease” that generated rental income rather than
income from transportation services for purposes of a foreign sales corporation provision of the Internal Revenue Code. Even
though (i) the Tidewater case did not involve a publicly traded partnership and it was not decided under Section 7704 of the
Internal Revenue Code relating to “qualifying income,” (ii) some experienced practitioners believe the decision was not well
reasoned, (iii) the IRS stated in an Action on Decision (AOD 2010-01) that it disagrees with and will not acquiesce to the Fifth
Circuit’s marine time charter analysis contained in the Tidewater case and (iv) the IRS has issued several favorable private
letter rulings (which can be relied upon and cited as precedent by only the taxpayers that obtained them) relating to time
charters since the Tidewater decision was issued, the Tidewater decision creates some uncertainty regarding the status of
income from certain of our marine time charters as “qualifying income” under Section 7704 of the Internal Revenue Code.
Notwithstanding the foregoing, the Tidewater case is relevant authority because it is the only case of which we and our outside
tax counsel are aware directly analyzing whether a particular time charter would constitute a lease or service agreement for
certain U.S. federal tax purposes. Due to the uncertainty created by the Tidewater decision, our outside tax counsel, Akin Gump
Strauss Hauer & Feld, LLP, was required to change the standard in its opinion relating to our status as a partnership for federal
income tax purposes to “should” from “will.”
Although we do not believe based upon our current operations that we are treated as a corporation for federal income
tax purposes, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal
income tax purposes or otherwise subject us to taxation as an entity. If we were treated as a corporation for federal income tax
purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of
21% and would pay state income tax at varying rates. Distributions to our unitholders would generally be taxable to them again
as corporate distributions and no income, gains, losses, or deductions would flow through to them. Because a tax would be
imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced.
Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return
to our unitholders, likely causing a substantial reduction in the value of our common units.
At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to
subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For
example, we are required to pay Texas franchise tax on our gross income apportioned to Texas. Imposition of any such taxes on
us by any other state would reduce our cash available for distribution to our unitholders.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential
legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
47
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our
common units may be modified by administrative, legislative or judicial interpretation at any time. From time to time, members
of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded
partnerships. Although there is no current legislative proposal, a prior legislative proposal would have eliminated the
qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our
treatment as a partnership for U.S. federal income tax purposes.
Further, final Treasury Regulations under Section 7704(d)(1)(E) of the Code that apply to taxable years beginning on
or after January 19, 2017 interpret the scope of qualifying income requirements for publicly traded partnerships by providing
industry-specific guidance. We believe the income we treat as qualifying income satisfies the requirements under the final
Treasury Regulations. However, there are no assurances that the final Treasury Regulations will not be revised to take a
position that is contrary to our interpretation of current law.
Any modifications to the U.S. federal income tax laws may be applied retroactively and could make it more difficult
or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal
income tax purposes. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted.
Any such changes could cause a material reduction in our anticipated cash flows and could cause us to be treated as an
association taxable as a corporation for U.S. federal income tax purposes subjecting us to the entity-level tax and adversely
affecting the value of our common units.
A successful IRS contest of the federal income tax positions we take may adversely affect the market for our common
units, and the costs of any IRS contest would reduce our cash available for distribution to our unitholders and our general
partner.
The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or
court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we
take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which
they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner
because these costs will reduce our cash available for distribution.
Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes
audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable
penalties and interest) resulting from such audit adjustments directly from us. To the extent possible under the new rules, our
general partner may elect to either cause us to pay the taxes (including any applicable penalties and interest) directly to the IRS
or, if we are eligible, issue a revised information statement to each unitholder and former unitholder with respect to an audited
and adjusted return. Although our general partner may elect to have it, our unitholders and former unitholders take such audit
adjustments into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their
interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or
effective in all circumstances. If we make payments of taxes and any penalties and interest directly to the IRS in the year in
which the audit is completed, our cash available for distribution to our unitholders might be substantially reduced, in which
case our current unitholders may bear some or all of the tax liability resulting from such audit adjustments, even if such
unitholders did not own common units in us during the tax year under audit. These rules are not applicable for tax years
beginning on or prior to December 31, 2017.
Our unitholders will be required to pay taxes on income (as well as deemed distributions, if any) from us even if they do
not receive any cash distributions from us.
Our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on
their share of our taxable income (as well as deemed distributions, if any) even if unitholders receive no cash distributions from
us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income (or deemed
distributions, if any) or even the tax liability that results from that income (or deemed distribution).
Tax gain or loss on the disposition of our common units could be more or less than expected.
If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the
amount realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net
taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect
to the common units a unitholder sells will, in effect, become taxable income to the unitholder if it sells such common units at a
price greater than its tax basis in those common units, even if the price received is less than its original cost. A substantial
portion of the amount realized, whether or not representing gain, may be ordinary income due to potential recapture items,
including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our non-recourse
liabilities, if our unitholders sell their common units, they may incur a tax liability in excess of the amount of cash they receive
from the sale.
48
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in
adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), other retirement
plans and non-U.S. persons, raises issues unique to them. For example, virtually all of our income allocated to organizations
that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income
and will be taxable to them. Allocations and/or distributions to non-U.S. persons will be subject to withholding taxes at the
highest applicable effective tax rate and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on
their share of our taxable income. Tax-exempt entities and non-U.S. persons should consult their tax advisors before investing
in our common units.
Recently enacted legislation provides that if a unitholder sells or otherwise disposes of a common unit, the transferee
is required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person,
and we are required to deduct and withhold from the transferee amounts that should have been withheld by the transferee but
were not withheld. However, the IRS has determined that this withholding requirement should not apply to any disposition of a
publicly traded interest in a publicly traded partnership (such as us) until regulations or other guidance have been issued
clarifying the application of this withholding requirement to dispositions of interests in publicly traded partnerships.
Accordingly, while this new withholding requirement does not currently apply to interests in us, there can be no assurance that
such requirement will not apply in the future.
We will treat each purchaser of our common units as having the same tax benefits without regard to the common units
actually purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.
Because we cannot match transferors and transferees of our common units, we adopt depreciation and amortization
conventions that may not conform to all aspects of existing Treasury Regulations and may result in audit adjustments to our
unitholders’ tax returns without the benefit of additional deductions. A successful IRS challenge to those conventions could
adversely affect the amount of tax benefits available to a common unitholder. It also could affect the timing of these tax
benefits or the amount of gain from a sale of common units and could have a negative impact on the value of our common units
or result in audit adjustments to the common unitholder’s tax returns.
Our unitholders will likely be subject to state and local taxes in states where they do not live as a result of an investment
in the common units.
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including foreign, state and
local taxes, unincorporated business taxes and estate inheritance or intangible taxes that are imposed by the various
jurisdictions in which we do business or own property, even if our unitholders do not live in any of those jurisdictions. Our
unitholders will likely be required to file foreign, state, and local income tax returns and pay state and local income taxes in
some or all of these jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those
requirements. We own assets and do business in more than 20 states including Texas, Louisiana, Mississippi, Alabama, Florida,
Arkansas and Oklahoma. Many of the states we currently do business in impose a personal income tax. It is our unitholders’
responsibility to file all applicable U.S. federal, foreign, state and local tax returns.
We have subsidiaries that are treated as corporations for federal income tax purposes and subject to corporate-level
income taxes.
We conduct a portion of our operations through subsidiaries that are, or are treated as, corporations for federal income
tax purposes. We may elect to conduct additional operations in corporate form in the future. These corporate subsidiaries will
be subject to corporate-level tax, which, effective for taxable years beginning after December 31, 2017, is 21%, and will likely
pay state (and possibly local) income tax at varying rates, on their taxable income. Any such entity level taxes will reduce the
cash available for distribution to us and, in turn, to our unitholders. If the IRS were to successfully assert that these corporate
subsidiaries have more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, our cash
available for distribution to our unitholders would be further reduced.
49
We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units
each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the
date a particular common unit is transferred.
We prorate our items of income, gain, loss, and deduction between transferors and transferees of our common units
each month based upon the ownership of our common units on the first day of each month (the Allocation Date), instead of on
the basis of the date a particular unit is transferred. Similarly, we generally allocate certain deductions for depreciation of
capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner,
any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. The U.S.
Department of the Treasury adopted final Treasury Regulations allowing a similar monthly simplifying convention, but such
regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration
method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having
disposed of those units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those
units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as
having disposed of the loaned units, such unitholder may no longer be treated for tax purposes as a partner with respect to those
units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition.
Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units
may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully
taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a
loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing
their units.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
See Item 1. “Business.” We also have various operating leases for rental of office space, office and field equipment
and vehicles. See “Commitments and Off-Balance Sheet Arrangements” in Management’s Discussion and Analysis of Financial
Condition and Results of Operations, and Note 21 to our Consolidated Financial Statements in Item 8 for the future minimum
rental payments. Such information is incorporated herein by reference.
Item 3. Legal Proceedings
We are involved from time to time in various claims, lawsuits and administrative proceedings incidental to our
business. In our opinion, the ultimate outcome, if any, of such proceedings is not expected to have a material adverse effect on
our financial condition, results of operations or cash flows. See Note 21 to our Consolidated Financial Statements in Item 8.
Item 4. Mine Safety Disclosures
Information regarding mine safety and other regulatory action at our mine in Green River, Wyoming is included in
Exhibit 95 to this Form 10-K.
50
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.” The
following table sets forth, for the periods indicated, the high and low sale prices per common unit and the amount of cash
distributions declared and paid per common unit.
2016
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
2017
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
Price Range
High
Low
Cash
Distributions
(1)
$ 37.35
$19.55
$ 40.35
$29.19
$ 40.90
$33.03
$ 38.36
$31.80
$ 37.88
$30.66
$ 33.52
$ 32.59
$28.16
$25.65
$ 26.55
$20.43
$
$
$
$
$
$
$
$
0.6550
0.6725
0.6900
0.7000
0.7100
0.7200
0.7225
0.5000
(1) Cash distributions are shown in the quarter paid and are based on the prior quarter’s activities.
At February 26, 2018, we had 122,539,221 Class A common units outstanding. As of December 31, 2017, the closing
price of our common units was $22.35 and we had approximately 33,000 record holders of our Class A common units, which
include holders who own units through their brokers “in street name.” Additionally, we have issued 22,411,728 Class A
Convertible Preferred Units for which there is no established public trading market.
Available cash generally means, for each fiscal quarter, all cash on hand at the end of the quarter:
•
less the amount of cash reserves that our general partner determines in its reasonable discretion is necessary or
appropriate to:
•
•
provide for the proper conduct of our business;
comply with applicable law, any of our debt instruments, or other agreements; or
•
•
provide funds for distributions to our unitholders for any one or more of the next four quarters;
plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital
borrowings. Working capital borrowings are generally borrowings that are made under our credit facility and in all
cases are used solely for working capital purposes or to pay distributions to partners.
The full definition of available cash is set forth in our partnership agreement and amendments thereto, which are incorporated
by reference as an exhibit to this Form 10-K.
See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and
Capital Resources – Capital Expenditures and Distributions Paid to our Unitholders” and Note 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.
51
Item 6. Selected Financial Data
The table below includes selected financial and other data for the Partnership for the years ended December 31, 2017,
2016, 2015, 2014 and 2013 (in thousands, except per unit and volume data). The selected financial data should be read in
conjunction with our Consolidated Financial Statements and Item 7. “Management’s Discussion and Analysis of Financial
Condition and Results of Operations.”
52
Income Statement Data:
Revenues:
Offshore pipeline transportation
Sodium minerals and sulfur services
Marine transportation
Onshore facilities and transportation
Total revenues
Equity of earnings of equity investees
Income from continuing operations after
income taxes
Net income attributable to Genesis
Energy, L.P.
Net income available to Common
Unitholders
Net income attributable to Common
Unitholders per Common Unit: Basic
and Diluted
Cash distributions declared per Common
Unit
Balance Sheet Data (at end of period):
Current assets
Total assets (2)
Long-term liabilities (2)
Convertible Preferred Units
Partners' capital:
Common unitholders
Accumulated Other Comprehensive
Income
Noncontrolling interests
Total partners’ capital
Other Data:
Volumes:
Offshore crude oil pipeline (barrels per
day)
Onshore crude oil pipeline (barrels per
day)
Natural gas transportation volumes
(MMBtus/d)
CO2 pipeline (Mcf per day)
NaHS sales (DST)
Soda Ash volumes (short tons sold)
NaOH sales (DST)
Crude oil and petroleum products sales
(barrels per day)
(1)
2017
(1)
2016
(1)
2015
2014 (1)
2013 (1)
Year Ended December 31,
318,239
462,622
205,287
1,042,229
2,028,377
51,046
82,079
$
$
$
334,679
171,503
213,021
993,290
1,712,493
47,944
111,082
$
$
$
140,230
177,880
238,757
1,689,662
2,246,529
54,450
421,585
$
$
$
3,296
207,401
229,282
3,406,185
3,846,164
43,135
106,202
$
$
$
3,923
205,985
152,542
3,772,380
4,134,830
22,675
84,004
82,647
$
113,249
$
422,528
$
106,202
$
86,109
60,652
$
113,249
$
422,528
$
106,202
$
86,109
0.50
2.6525
636,033
7,137,481
3,966,602
697,151
$
$
$
$
$
$
1.00
2.7175
359,569
5,702,592
3,321,739
$
$
$
$
$
4.10
2.4700
306,316
5,459,599
3,136,712
$
$
$
$
$
1.18
2.2300
355,366
3,210,624
1,618,276
$
$
$
$
$
1.03
2.0150
535,223
2,848,528
1,304,238
— $
— $
— $
—
$
$
$
$
$
$
$
$
$
$
$
2,026,147
2,130,331
2,029,101
1,229,203
1,097,737
(604)
(8,079)
$
2,017,464
$
—
(10,281)
2,120,050
$
—
(8,350)
2,020,751
—
—
—
—
$
1,229,203
$
1,097,737
591,667
581,763
518,211
446,548
404,787
212,768
114,130
144,084
116,225
104,026
496,302
77,921
133,404
1,398,000
84,816
679,862
97,955
125,766
—
80,021
708,556
161,409
127,063
—
86,914
—
173,770
150,038
—
94,693
—
190,274
147,297
—
87,463
51,771
62,484
91,074
99,139
99,651
(1) Our operating results and financial position have been affected by acquisitions. For additional information regarding our
acquisitions and divestitures during 2017, 2016 and 2015, see Note 3 to our Consolidated Financial Statements included in Item 8.
53
(2) As relating to new accounting guidance issued by the FASB which we adopted in 2015, our long-term liabilities and total assets for
all years presented reflect changes in presentation of debt issuance costs as a direct reduction of related debt liabilities with
amortization of debt issuance costs reported as interest expense.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Introduction
We are a growth-oriented master limited partnership formed in Delaware in 1996. Our common units are traded on the
New York Stock Exchange, or NYSE, under the ticker symbol “GEL.” We are (i) a provider of an integrated suite of midstream
services - primarily transportation, storage, sulfur removal, blending, terminalling and processing-for a large area of the Gulf
Coast region of the crude oil and natural gas industry and (ii) the largest producer in the world of natural soda ash. Our sulfur
removal business results in us being the largest producer, we believe, in the world of sodium hydrosulfide (or NaHS,
pronounced “nash”).
Historically, a substantial majority of our focus has been on the midstream segment of the crude oil and natural gas
industry in the Gulf Coast region of the United States, 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 enterprises and have a diverse portfolio
of assets, including pipelines, offshore hub and junction platforms, refinery-related plants, storage tanks and terminals, railcars,
rail loading and unloading facilities, barges and other vessels, and trucks. On September 1, 2017, we acquired our trona and
trona-based exploring, mining, processing, producing, marketing and selling business based in Wyoming (our “Alkali
Business”) for approximately $1.325 billion in cash. Our Alkali Business mines and processes trona from which it produces
natural soda ash, also known as sodium carbonate (Na2CO3), a basic building block for a number of ubiquitous products,
including flat glass, container glass, dry detergent and a variety of chemicals and other industrial products. Our Alkali business
has a diverse customer base in the United States, Canada, the European Community, the European Free Trade Area and the
South African Customs Union with many long-term relationships. It has been operating for almost 70 years and has an
estimated remaining reserve life (based on 2017 production) of over 100 years. Within our legacy midstream business, we have
two distinct, complementary types of operations-(i) our onshore-based refinery-centric operations located primarily in the Gulf
Coast region of the U.S., which focus on providing a suite of services primarily to refiners, which includes our sulfur removal,
transportation, storage, and other handling services and (ii) our offshore Gulf of Mexico crude oil and natural gas pipeline
transportation and handling operations, which focus on providing a suite of services primarily to integrated and large
independent energy companies who make intensive capital investments to develop numerous large-reservoir, long-lived crude
oil and natural gas properties. Our onshore-based operations occur upstream of, at, and downstream of refinery complexes.
Upstream of refineries, we aggregate, purchase, gather and transport crude oil, which we sell to refiners. Within refineries, we
provide services to assist in sulfur removal/balancing requirements. Downstream of refineries, we provide transportation
services as well as market outlets for finished refined petroleum products and certain refining by-products. In our offshore
crude oil and natural gas pipeline transportation and handling operations, we provide services to one of the most active drilling
and development regions in the U.S.-the Gulf of Mexico, a producing region representing approximately 18% of the crude oil
production in the U.S. in 2017. Our legacy midstream business has a diverse portfolio of customers, operations and assets,
including pipelines, offshore hub and junction platforms, refinery-related plants, storage tanks and terminals, railcars, rail
loading and unloading facilities, barges and other vessels, and trucks.
Included in Management’s Discussion and Analysis are the following sections:
•
•
•
•
•
•
•
•
•
Overview of 2017 Results
Acquisitions, Divestitures and Growth Initiatives
Results of Operations
Other Consolidated Results
Financial Measures
Liquidity and Capital Resources
Commitments and Off-Balance Sheet Arrangements
Critical Accounting Policies and Estimates
Recent Accounting Pronouncements
Overview of 2017 Results
We reported Net Income Attributable to Genesis Energy, L.P. of $82.6 million, or $0.50 per common unit, in 2017
compared to Net Income Attributable to Genesis Energy, L.P. of $113.2 million, or $1.00 per common unit, in 2016. The
decrease was principally due to an increase in transaction and financing expenses primarily related to the acquisition of our
54
Alkali Business, an increase in interest expense as driven in part by the financing of the acquisition of our Alkali Business, and
a non-cash provision relating to certain leased railcars no longer in use (included in Onshore facilities and transportation
operating costs in our Unaudited Condensed Consolidated Statements of Operations). These items were partially offset by
approximately $40.3 million of gains on sales of certain non-core assets during 2017.
In addition, we experienced increases in both Total Segment Margin and depreciation and amortization expense as a
result of the effect of recently acquired and constructed assets placed in service, in particular those associated with our Alkali
Business.
Cash flow from operating activities was $338.9 million for the 2017 period compared to $298.3 million for 2016.
Available Cash before Reserves (as defined below in "Financial Measures") increased $4.8 million in 2017 to $389.0
million as compared to 2016 Available Cash before Reserves of $384.2 million. See "Financial Measures" below for additional
information on Available Cash before Reserves.
Segment Margin (as defined below in "Financial Measures") was $594.5 million in 2017, an increase of $25.0 million,
or 4%, as compared to 2016. Consistent with net income, this increase resulted primarily from increases attributable to our
sodium minerals and sulfur services segment (principally due to the impact of our new Alkali Business) partially offset by
smaller decreases in our other segments.
We recently made the strategic decision to re-set our quarterly distribution and provided a plan for visible, achievable
long term distribution growth and a path forward to deleveraging. These steps, along with the future relatively stable cash flows
from our recently completed acquisition of our Alkali Business as well as the continued ramp up from our recent strategic
investments, we believe further enhance our financial flexibility to opportunistically pursue accretive organic projects and
acquisitions should they present themselves. Overall, we believe these actions to strengthen our balance sheet and enhance our
financial flexibility are the best actions we can take to allow us to generate strong optimal returns for our unitholders in the
years ahead.
Our 2017 results were negatively impacted by a number of events, such as Hurricane Harvey (a 1,000-year storm),
Hurricane Nate (which had an even bigger temporary impact than Hurricane Harvey on our offshore operations), the planned
regulatory dry-docking of our M/T American Phoenix (as required every five years), some extended turnarounds at several
offshore hubs, limited railroad capacity out of Canada to the Gulf Coast and operating issues on downstream facilities in Texas.
Notwithstanding these negatives, our legacy businesses are performing as expected, and we are seeing increased contributions
from our recently completed organic projects in the Baton Rouge corridor, in and around Texas City and in Wyoming.
Additionally, 2017 reflects only four months of contribution from our recently acquired Alkali Business operations.
We currently manage our businesses through four divisions that constitute our reportable segments - offshore pipeline
transportation, sodium minerals and sulfur services (which includes our sulfur removal business and our newly acquired Alkali
Business), onshore facilities and transportation and marine transportation. Our disclosures related to prior periods have been
recast to reflect our reorganized segments.
A more detailed discussion of our segment results and other costs is included below in "Results of Operations".
Distributions to Unitholders
In February 2018, we paid a distribution of $0.51 per unit related to the fourth quarter of 2017. With respect to our
Class A Convertible Preferred Units, we have declared a payment-in-kind or PIK of the quarterly distribution, which resulted in
the issuance of an additional 490,252 Class A Convertible Preferred Units. This PIK amount equates to a distribution of
$0.7374 per Class A Convertible Preferred Unit for the 2017 Quarter, or $2.9496 annualized. These distributions were paid on
February 14, 2018 to unitholders holders of record at the close of business January 31, 2018.
Acquisitions and Growth Initiatives
Alkali Business Acquisition
On September 1, 2017, we acquired our trona and trona-based exploring, mining, processing, producing, marketing
and selling business based in Wyoming (our “Alkali Business”) for approximately $1.325 billion in cash.
To finance that transaction and the related costs, we used proceeds from (i) a $550.0 million public offering
of 6.50% senior unsecured notes due 2025 in August 2017, generating net proceeds of $540.1 million after issuance discount
and underwriting fees, (ii) a $750 million private placement of Class A Convertible Preferred units in September 2017,
generating net proceeds of $726.2 million, (iii) borrowings under our revolving credit facility and (iv) cash on hand.
Baton Rouge Area Infrastructure Expansion
55
We are currently expanding our existing Baton Rouge area infrastructure to allow for greater capacity and flexibility in
servicing our major refinery customer in the region. This expansion includes the construction of an additional 500,000 barrels
of crude oil tankage at our existing Baton Rouge Terminal. Additionally, this expansion will include the upgrading of pumping
and other infrastructure capabilities in order to allow for the efficient handling of expected increases in crude oil volumes
received at our Baton Rouge area facilities. We expect these assets to become operational in the first quarter of 2018.
Wyoming Infrastructure Expansion
We have recently begun construction of a new gathering system to connect crude oil production to our existing Powder
River basin pipeline infrastructure. This new gathering system is supported by a new long-term contract with one of the leading
operators in the Powder River basin. The operator will dedicate approximately 300,000 acres to the gathering system and our
Powder River basin pipeline infrastructure for a period of ten years, including approximately 150,000 acres that had previously
been dedicated. We expect these assets to become operational in the second quarter of 2018.
Houston Area Crude Oil Pipeline and Terminal Infrastructure
We have constructed new, and expanded existing, crude oil pipeline and terminal facilities in Webster, Texas and Texas
City, Texas as a result of expanding our crude oil pipeline and terminal infrastructure in the Houston area. We have also
constructed a new crude oil pipeline that delivers crude oil received from upstream crude oil pipelines (including CHOPS,
which delivers crude oil originating in the deepwater Gulf of Mexico to the Texas City area) to our new Texas City Terminal,
which connects to our existing 18-inch Webster to Texas City crude oil pipeline. Our new Texas City Terminal includes
approximately 750,000 barrels of crude oil tankage. As a part of this project, we have also made the necessary upgrades on our
existing 18-inch Webster to Texas City crude oil pipeline to reverse the direction of flow. The result of this expanded crude oil
infrastructure allows additional optionality to Houston and Baytown area refineries, including the ExxonMobil Baytown
refinery, its largest refinery in the U.S.A., and provides additional delivery outlets for other crude oil pipelines. These assets
became operational in the second quarter of 2017.
Raceland Terminal and Crude Oil Pipeline
We have constructed a new crude oil terminal and pipeline in Raceland, Louisiana that connects to existing midstream
infrastructure to provide further distribution to the Louisiana refining markets. Our new Raceland Terminal consists of 515,000
barrels of crude oil tankage and unit train unloading facilities capable of unloading up to two unit trains per day. We have also
constructed a new crude oil pipeline that will deliver crude oil received from the Poseidon system, which currently delivers
crude oil originating in the deepwater Gulf of Mexico to the Houma, Louisiana area, to our new Raceland Terminal for further
distribution. These assets became fully operational at the end of the second quarter of 2017.
Inland Marine Barge Transportation Expansion
In 2016, we ordered 28 new-build barges and 18 new-build push boats for our inland marine barge transportation fleet.
Through December 31, 2017, we had periodically accepted delivery of all but two barges. We expect to take delivery of those
remaining vessels in 2018.
Results of Operations
In the discussions that follow, we will focus on our revenues, expenses and net income, as well as two measures that
we use to manage the business and to review the results of our operations-Segment Margin and Available Cash before Reserves.
Segment Margin and Available Cash before Reserves are defined in the "Financial Measures" section below.
Revenues, Costs and Expenses and Net Income Attributable to Genesis Energy L.P.
Our revenues for the year ended December 31, 2017 increased $315.9 million, or 18%, from the year ended December
31, 2016. Additionally, our costs and expenses increased $301.8 million, or 20%, between the two periods.
A substantial portion of our revenues and costs are derived from the purchase and sale of crude oil and petroleum
products through our onshore facilities and transportation segment. In addition, our revenues and costs between these two
periods have been impacted by increases in market prices associated with our crude oil and petroleum product sales as
discussed further below. In general, we do not expect fluctuations in prices for crude oil and natural gas to materially affect our
net income, Available Cash before Reserves or Segment Margin to the same extent they affect our revenues and costs. We have
limited our direct commodity price exposure in our crude oil and petroleum products operations through the broad use of fee-
based service contracts, back-to-back purchase and sale arrangements, and hedges. As a result, changes in the price of crude oil
would proportionately impact both our revenues and our costs, with a disproportionately smaller net impact on our Segment
Margin.
56
As discussed throughout this document, we have some indirect exposure to certain changes in prices for oil and
petroleum products, particularly if they are significant and extended. We tend to experience more demand for certain of our
services when prices increase significantly over extended periods of time, and we tend to experience less demand for certain of
our services when prices decrease significantly over extended periods of time. For additional information regarding certain of
our indirect exposure to commodity prices, see our segment-by-segment analysis below and the previous section entitled “Risks
Related to Our Business”.
Prices of crude oil have increased since December 31, 2016. The average closing prices for West Texas Intermediate
("WTI") crude oil on the New York Mercantile Exchange ("NYMEX") increased 18% to $50.95 per barrel in 2017, as
compared to $43.32 per barrel in 2016. We would expect changes in crude oil prices to continue to proportionately affect our
revenues and costs attributable to our purchase and sale of crude oil and petroleum products, producing minimal direct impact
on Segment Margin from those operations. However, due to the indirect exposure to changes in prices discussed above and in
the discussion surrounding our onshore facilities and transportation segment, crude oil and petroleum product sales volumes
decreased 17% in 2017 as compared to 2016.
The addition of our Alkali Business resulted in a large increase in revenues and costs relative to 2016 (as evident in our
sodium minerals and sulfur services segment). These fluctuations resulting from the Alkali Business are principally derived
from the activities surrounding the extraction of trona, as well as the activities surrounding the processing and sale of natural
soda ash. Natural soda ash has significant cost advantages over any synthetic production methods. We believe the significant
cost advantage in the production of natural soda ash compared to synthetically produced soda ash will remain for the
foreseeable future. Natural soda ash accounts for approximately 25% of the world's production and therefore given these facts,
we believe we are able to somewhat mitigate the effects of market specific factors on Net Income, Available Cash before
Reserves and Segment Margin in the soda ash market in which we operate.
In addition to our newly acquired Alkali Business, we continue to operate in our other legacy businesses including (i)
our offshore Gulf of Mexico crude oil and natural gas pipeline transportation and handling operations, which focus on
providing a suite of services primarily to integrated and large independent energy companies who make intensive capital
investments (often in excess of billions of dollars) to develop numerous large-reservoir, long-lived crude oil and natural gas
properties; and (ii) our onshore-based refinery-centric operations located primarily in the Gulf Coast region of the U.S., which
focus on providing a suite of services primarily to refiners. Refiners are the shippers of approximately 80% of the volumes
transported on our onshore crude pipelines, and refiners contract for over 80% of the use of our inland barges, which are used
primarily to transport intermediate refined products (not crude oil) between refining complexes. The shippers on our offshore
pipelines are mostly integrated and large independent energy companies who have developed, and continue to explore for,
numerous large-reservoir, long-lived crude oil properties 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. Those 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 a lower commodity price environment. Given these facts, we do not expect
changes in commodity prices to impact our net income, Available Cash before Reserves or Segment Margin in the same manner
in which they impact our revenues and costs derived from the purchase and sale of crude oil and petroleum products.
Additionally, changes in certain of our operating costs between the respective quarters, including those associated with
our offshore pipeline and marine transportation segments, are not directly correlated with commodity prices. We discuss certain
of those costs in further detail below in our segment-by-segment analysis.
Net Income Attributable to Genesis Energy L.P. decreased $30.6 million in 2017 from 2016. See "Overview of 2017
Results" above for additional discussion.
Revenues in 2016 decreased $534.0 million, or 24%, from 2015. Additionally, our costs and expenses decreased
$583.6 million, or 28%, between the two periods. The significant decrease in our revenues and costs between 2016 and 2015 is
primarily attributable to the decrease in market prices for crude oil and petroleum products between the two periods. The
average closing prices for WTI crude oil on the NYMEX decreased 11% to $43.32 per barrel in 2016, as compared to $48.79
per barrel in 2015. Net Income Attributable to Genesis Energy L.P. decreased $309.3 million in 2016 to $113.2 million from
$422.5 million in 2015. The decrease in net income during 2016 was primarily due to the $332.4 million non-cash gain we
recognized during 2015 resulting from a step up in basis to fair value of our historical interests in certain of our equity investees
(CHOPS and SEKCO) as a result of our acquiring the remaining interest in those equity investees when we completed our
Enterprise acquisition in July 2015.
Included below is additional detailed discussion of the results of our operations focusing on Segment Margin and other
costs including general and administrative expenses, depreciation and amortization, interest and income taxes.
Segment Margin
The contribution of each of our segments to total Segment Margin in each of the last three years was as follows:
57
Offshore pipeline transportation
Sodium minerals and sulfur services
Onshore facilities and transportation
Marine transportation
Total Segment Margin
Year Ended December 31,
2017
2016
2015
317,540
130,333
96,376
50,294
(in thousands)
336,620
79,508
83,364
70,079
$
594,543
$
569,571
$
197,723
80,246
95,394
103,222
476,585
Year Ended December 31, 2017 Compared with Year Ended December 31, 2016
Offshore Pipeline Transportation Segment
Operating results and volumetric data for our offshore pipeline transportation segment are presented below:
Offshore crude oil pipeline revenue
Offshore natural gas pipeline revenue
Offshore pipeline operating costs, excluding non-cash expenses
Distributions from equity investments
Other
Offshore pipeline transportation Segment Margin(1)
Volumetric Data 100% basis:
Crude oil pipelines (average barrels/day unless otherwise noted):
CHOPS
Poseidon
Odyssey
GOPL (2)
Total crude oil offshore pipelines
Year Ended December 31,
2017
2016
(in thousands)
$
267,658
$
270,454
50,582
(63,231)
80,639
(18,108)
317,540
$
64,225
(72,009)
84,321
(10,371)
336,620
$
213,527
253,547
116,408
8,185
591,667
204,533
262,829
106,933
7,468
581,763
Natural gas transportation volumes (MMBtus/d)
496,302
679,862
Volumetric Data net to our ownership interest (3):
Crude oil pipelines (average barrels/day unless otherwise noted):
CHOPS
Poseidon
Odyssey
GOPL (2)
Total crude oil offshore pipelines
213,527
162,270
33,758
8,185
417,740
204,533
168,211
31,011
7,468
411,223
Natural gas transportation volumes (MMBtus/d)
222,729
398,190
(1) Offshore pipeline transportation Segment Margin includes distributions received from our offshore pipeline joint ventures
accounted for under the equity method of accounting in 2017 and 2016, respectively.
(2) One of our wholly-owned subsidiaries (GEL Offshore Pipeline, LLC, or "GOPL") owns our undivided interest in the Eugene Island
pipeline system.
58
(3) Volumes are the product of our effective ownership interest throughout the year, including changes in ownership interest, multiplied
by the relevant throughput over the given year.
Offshore Pipeline Transportation Segment Margin for 2017 decreased $19 million, or 6%, from 2016. The year ended
December 31, 2017 was negatively impacted by both anticipated and unanticipated downtime at several major fields, including
weather related downtime, affecting certain of our deepwater Gulf of Mexico customers and thus certain of our key crude oil
and natural gas assets, including our Poseidon pipeline and certain associated laterals which we own. The 2017 period also
reflects the effects of a contractual adjustment to a lower rate for a lateral we own that will be in place going forward. In
addition, 2016 benefited from the temporary diversion of certain natural gas volumes from third party gas pipelines to one of
our gas pipelines and related facilities due to one-time disruptions at onshore processing facilities where such volumes typically
flow.
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) (1)
NaOH (caustic soda) volumes (dry short tons sold) (1)
Total
Revenues (in thousands):
NaHS revenues
NaOH (caustic soda) revenues
Revenues associated with Alkali Business
Other revenues
Total external segment revenues
Year Ended December 31,
2017
2016
133,404
1,398,000
84,816
1,616,220
125,766
—
80,021
205,787
$
149,392
$
136,240
42,725
273,288
5,384
39,413
—
5,012
$
470,789
$
180,665
Sodium minerals and sulfur services operating costs, excluding non-cash items
(340,456)
(101,157)
Segment Margin (in thousands)
Average index price for NaOH per DST (2)
$
$
130,333
635
$
$
79,508
480
(1) Includes sales volumes from September 1, 2017, the date on which we acquired our Alkali Business.
(2) Source: IHS Chemical
Sodium minerals and sulfur services Segment Margin for 2017 increased $50.8 million, or 64%, from 2016. This
increase is principally due to the inclusion of contributions from our Alkali Business since our acquisition date of September 1,
2017. The contributions thus far from our Alkali Business have exceeded our expectations and we expect continued strong
performance into 2018 as we continue to remain the global leader in natural soda ash production. Costs impacting the results of
our Alkali Business, many of which are similar in nature to costs related to our sulfur removal business, include costs associated
with processing and producing soda ash (and other Alkali products) and marketing and selling activities. In addition, costs
include activities associated with mining and extracting trona ore (including energy costs and employee compensation).
These contributions were partially offset by the results of our sulfur removal business and related NaHS and caustic
soda activities. Our 2017 results for these activities were in line with our expectations and include the effects of previously
disclosed commercial discussions with certain of our host refineries and several NaHS customers, which resulted in extending
the term and tenor of a large number of contractual relationships.
Onshore Facilities and Transportation Segment
59
Our onshore facilities and transportation segment utilizes an integrated set of pipelines and terminals, as well as trucks,
railcars, and barges to facilitate the movement of crude oil and refined products on behalf of producers, refiners and other
customers. This segment includes crude oil and refined products pipelines, terminals, rail facilities and CO2 pipelines operating
primarily within the United States Gulf Coast and Rocky Mountain crude oil markets. In addition, we utilize our railcar and
trucking fleets that support the purchase and sale of gathered and bulk purchased crude oil, as well as purchased and sold
refined products. This fleet includes approximately 200 trucks, 400 trailers, 504 railcars, and 4.6 million barrels of leased and
owned storage capacity. Through these assets we offer our customers a full suite of services, including the following:
•
•
•
•
•
•
•
facilitating the transportation of crude oil from producers to refineries and from owned and third party terminals to
refiners via pipelines;
transporting CO2 from natural and anthropogenic sources to crude oil fields owned by our customers;
shipping crude oil and refined products to and from producers and refiners via trucks, railcars and pipelines;
loading and unloading railcars at our crude-by-rail terminals;
storing and blending of crude oil and intermediate and finished refined products;
purchasing/selling and/or transporting crude oil from the wellhead to markets for ultimate use in refining; and
purchasing products from refiners, transporting those products to one of our terminals and blending those products to a
quality that meets the requirements of our customers and selling those products (primarily fuel oil, asphalt and other
heavy refined products) to wholesale markets;
We also may use our terminal facilities to take advantage of contango market conditions for crude oil gathering and
marketing and to capitalize on regional opportunities which arise from time to time for both crude oil and petroleum products.
Despite crude oil being considered a somewhat homogeneous commodity, many refiners are very particular about the
quality of crude oil feedstock they process. Many U.S. refineries have distinct configurations and product slates that require
crude oil with specific characteristics, such as gravity, sulfur content and metals content. The refineries evaluate the costs to
obtain, transport and process their preferred feedstocks. That particularity provides us with opportunities to help the refineries
in our areas of operation identify crude oil sources and transport crude oil meeting their requirements. The imbalances and
inefficiencies relative to meeting the refiners’ requirements may also provide opportunities for us to utilize our purchasing and
logistical skills to meet their demands. The pricing in the majority of our crude oil purchase contracts contains a market price
component and a deduction to cover the cost of transportation and to provide us with a margin. Contracts sometimes contain a
grade differential which considers the chemical composition of the crude oil and its appeal to different customers. Typically, the
pricing in a contract to sell crude oil will consist of the market price components and the grade differentials. The margin on
individual transactions is then dependent on our ability to manage our transportation costs and to capitalize on grade
differentials.
In our refined products marketing operations, we supply primarily fuel oil, asphalt and other heavy refined products to
wholesale markets and some end-users such as paper mills and utilities. We also provide a service to refineries by purchasing
“heavier” petroleum products that are the residual fuels from gasoline production, transporting them to one of our terminals and
blending them to a quality that meets the requirements of our customers.
60
Operating results for our onshore facilities and transportation segment were as follows:
Gathering, marketing, and logistics revenue
Crude oil and CO2 pipeline tariffs and revenues from direct financing leases of CO2
pipelines
Payments received under direct financing leases not included in income
Crude oil and products costs, excluding unrealized gains and losses from derivative
transactions
Operating costs, excluding non-cash charges for equity-based compensation and other non-
cash expenses
Other
Segment Margin
Volumetric Data (average barrels/day unless otherwise noted):
Onshore crude oil pipelines:
Texas
Jay
Mississippi
Louisiana (1)
Wyoming
Onshore crude oil pipelines total
CO2 pipeline (average Mcf/day):
Free State
Crude oil and petroleum products sales:
Total crude oil and petroleum products sales
Rail load/unload volumes (2)
Year Ended December 31,
2017
2016
(in thousands)
$
971,442
$
930,347
67,226
6,921
58,567
6,277
(866,239)
(823,780)
(87,007)
4,033
$
96,376
$
(94,592)
6,545
83,364
32,684
14,155
8,290
135,310
22,329
212,768
33,814
14,815
10,247
44,295
10,959
114,130
77,921
97,955
51,771
52,877
62,484
19,691
(1) Total daily volume for the years ended December 31, 2017 and December 31, 2016 includes 56,748 and 8,997 barrels per day
respectively of intermediate refined products associated with our Port of Baton Rouge Terminal pipelines which became operational
in the fourth quarter of 2016. Additionally, this includes 14,117 barrels per day for the year ended December 31, 2017 of crude oil
associated with our new Raceland Pipeline which became fully operational in the second quarter of 2017.
(2) Includes total barrels for either loading or unloading at all rail facilities.
Segment Margin for our onshore facilities and transportation segment increased $13.0 million, or 16% , in 2017 as
compared to 2016. The 2017 period includes the effects of the ramp up in volumes on our pipeline, rail and terminal
infrastructure on our recently completed infrastructure in the Baton Rouge corridor. This was principally offset by lower
demand for our services in our historical back-to-back, or buy/sell, crude oil marketing business associated with aggregating
and trucking crude oil from producers' leases to local or regional re-sale points. In addition, the 2017 period was negatively
impacted by lower volumes on our Texas pipeline system, as the repurposing of our Houston area crude oil pipeline and
expansion of our terminal infrastructure did not became operational until the second quarter of 2017 (while a large portion of
2016 included historical volumes on our legacy Texas pipeline system assets prior to the repurposing project).
61
Marine Transportation Segment
Within our marine transportation segment, we own a fleet of 89 barges (80 inland and 9 offshore) with a combined
transportation capacity of 3.1 million barrels, 42 push/tow boats (33 inland and 9 offshore), and a 330,000 barrel ocean going
tanker, the M/T American Phoenix. Operating results for our marine transportation segment were as follows:
Revenues (in thousands):
Inland freight revenues
Offshore freight revenues
Other rebill revenues (1)
Total segment revenues
Operating costs, excluding non-cash charges for equity-based compensation and
other non-cash expenses
Segment Margin (in thousands)
Fleet Utilization: (2)
Inland Barge Utilization
Offshore Barge Utilization
Year Ended December 31,
2017
2016
$
$
$
$
82,354
73,540
49,393
205,287
154,993
50,294
$
$
$
$
88,502
85,594
38,925
213,021
142,942
70,079
90.4%
98.2%
91.4%
90.5%
(1) Under certain of our marine contracts, we "rebill" our customers for a portion of our operating costs.
(2) Utilization rates are based on a 365 day year, as adjusted for planned downtime and drydocking.
Marine Transportation Segment Margin for 2017 decreased $19.8 million, or 28%, from 2016. The decrease in
Segment Margin is primarily due to lower day rates on our inland and offshore fleets (which offset higher utilization as adjusted
for planned dry docking time in our offshore fleet). The M/T American Phoenix was also undergoing planned regulatory dry
docking inspections for approximately one month during 2017, which negatively impacted Segment Margin. In our inland fleet,
weaker demand continued to apply pressure on our rates, which we expect to continue into 2018. In our offshore barge fleet, as
a number of our units have come off longer term contracts, we have continued to choose to primarily place them in spot service
or short-term (less than a year) service because we continue to believe the day rates currently being offered by the market are at,
or approaching, cyclical lows.
Other Costs and Interest
General and administrative expenses
General and administrative expenses not separately identified below:
Corporate
Segment
Equity-based compensation plan expense
Third party costs related to business development activities and growth projects
Total general and administrative expenses
Year Ended December 31,
2017
2016
(in thousands)
$
$
51,160
$
35,841
3,684
(2,272)
13,849
3,264
4,575
1,945
66,421
$
45,625
Total general and administrative expenses increased $21 million between 2017 and 2016. The increase is primarily
attributable to the third party financing, legal and accounting costs surrounding our acquisition of our Alkali Business in 2017,
as well as an increase in certain accruals made for a variety of items, including approximately $7.5 million relating to our
annual bonus program. This was partially offset by the effects of changes in assumptions used to value our equity based
compensation awards that are tied to our unit price.
62
Depreciation, depletion, and amortization expense
Depreciation and depletion expense
Amortization of intangible assets
Amortization of CO2 volumetric production payments
Total depreciation, depletion and amortization expense
Year Ended December 31,
2017
2016
(in thousands)
$
$
227,540
$
193,976
23,612
1,328
24,310
3,910
252,480
$
222,196
Total depreciation, depletion, and amortization expense increased $30 million between 2017 and 2016 primarily as a
result of placing additional assets into service, including those acquired as a part of our Alkali Business in 2017.
Interest expense, net
Interest expense, senior secured credit facility (including commitment fees)
Interest expense, senior unsecured notes
Amortization and write-off of debt issuance costs and discount
Capitalized interest
Net interest expense
Year Ended December 31,
2017
2016
(in thousands)
$
$
51,587
$
41,948
128,983
11,214
(15,022)
176,762
$
114,437
10,138
(26,576)
139,947
Net interest expense increased $37 million during 2017 primarily due to an increase in our average outstanding
indebtedness from acquired and constructed assets, including the financing of the acquisition of our Alkali Business in 2017. In
addition, capitalized interest decreased as result of certain of our large organic growth projects being completed and placed into
service throughout 2017.
Other Consolidated Results
Net income included an unrealized loss on derivative positions, excluding fair value hedges, of $10.9 million in 2017
and an unrealized loss of $1.3 million in 2016. Those amounts are included in onshore facilities and transportation product
costs in the Condensed Consolidated Statement of Operations and are not a component of Segment Margin. Net income for the
year ended December 31, 2017 also includes $40.3 million of gains resulting from the sale of certain non-core assets, as well as
a $12.6 million non-cash provision relating to certain leased railcars no longer in use.
Year Ended December 31, 2016 Compared with Year Ended December 31, 2015
Offshore Pipeline Transportation Segment
Operating results and volumetric data for our offshore pipeline transportation segment are presented below:
63
Offshore crude oil pipeline revenue
Offshore natural gas pipeline revenue
Offshore pipeline operating costs, excluding non-cash expenses
Distributions from equity investments
Other
Offshore Pipeline Transportation Segment Margin (1)
Volumetric Data 100% basis:
Offshore crude oil pipelines (average barrels/day unless otherwise noted):
CHOPS
Poseidon
Odyssey
GOPL(2)
Total crude oil offshore pipelines
Natural gas transportation volumes (MMBtus/d) (3)
Volumetric Data net to our ownership interest (4):
Offshore crude oil pipelines (average barrels/day unless otherwise noted):
CHOPS
Poseidon
Odyssey
GOPL(2)
Total crude oil offshore pipelines
Natural gas transportation volumes (MMBtus/d) (4)
Year Ended December 31,
2016
2015
(in thousands)
$
270,454
$
115,640
64,225
(72,009)
84,321
(10,371)
336,620
$
24,590
(39,685)
94,361
2,817
$
197,723
204,533
262,829
106,933
7,468
581,763
172,647
259,568
72,958
13,038
518,211
679,862
708,556
204,533
168,211
31,011
7,468
411,223
124,928
115,219
21,158
13,038
274,343
398,190
420,464
(1) Offshore Pipeline Transportation Segment Margin includes distributions received from our offshore pipeline joint ventures
accounted for under the equity method of accounting in 2016 and 2015, respectively.
(2) One of our wholly-owned subsidiaries (GEL Offshore Pipeline, LLC, or "GOPL") owns our undivided interest in the Eugene Island
pipeline system.
(3) Represents volumes per day from the period the pipelines and related assets were acquired in July 2015.
(4) Volumes are the product of our effective ownership interest throughout the year, including changes in ownership interest, multiplied
by the relevant throughput over the given year.
Offshore Pipeline Transportation Segment Margin for 2016 increased $138.9 million, or 70%, from 2015. This
increase is primarily due to our Enterprise acquisition, which closed in July 2015. As a result of our Enterprise acquisition, we
obtained interests in approximately 2,350 miles of offshore crude oil and natural gas pipelines (including increasing our
ownership interest in each of the Poseidon, SEKCO, and CHOPS pipelines) and six offshore hub platforms. The operating
results in 2016 of the offshore pipeline assets acquired from Enterprise continued to meet or exceed our expectations, with a net
increase in volumes (compared to the year ended December 31, 2015) for the most significant of those offshore crude oil
pipelines. In addition, this increase was partially the result of 2016 drilling activity which predominantly occurred near existing
infrastructure due to the attractive economics in current pricing conditions. Our extensive pipeline network benefited ratably
from this activity.
64
Sodium Minerals and Sulfur Services Segment
Operating results for our sodium minerals and sulfur services segment were as follows:
Volumes sold (in DST):
NaHS volumes
NaOH (caustic soda) volumes
Total
Revenues (in thousands):
NaHS revenues
NaOH (caustic soda) revenues
Other revenues
Total external segment revenues
Segment Margin (in thousands)
Average index price for NaOH per DST (1)
(1) Source: IHS Chemical
Year Ended December 31,
2016
2015
125,766
80,021
205,787
127,063
86,914
213,977
$
136,240
$
137,825
39,413
5,012
180,665
79,508
480
$
$
$
42,746
6,686
187,257
80,246
416
$
$
$
Sodium minerals and sulfur services Segment Margin for 2016 decreased $0.7 million, or 1%, from 2015. The
significant components of this fluctuation were as follows:
• During 2016, our NaHS business was able to realize more benefits from our favorable management of the purchasing
(including economies of scale) and utilization of caustic soda in our (and our customers') operations and our logistics
management capabilities, as compared to 2015. The fluctuation in NaHS revenues and volumes had a minimal impact
on Segment Margin.
• Caustic soda revenues decreased 8% due to a decrease in both caustic soda sales volumes and our sales price for
caustic soda. Although caustic sales volumes may fluctuate, the contribution to Segment Margin from these sales is
not a significant portion of our sodium minerals and sulfur services activities.
• Average index prices for caustic soda increased to $480 per DST during 2016 compared to $416 per DST during 2015.
Those price movements affect the revenues and costs related to our sulfur removal services as well as our caustic soda
sales activities. Typically, changes in caustic soda prices do not materially affect Segment Margin attributable to our
sulfur processing services because the pricing in many of our sales contracts for NaHS typically includes adjustments
for fluctuations in commodity benchmarks (primarily caustic soda), freight, labor, energy costs and government
indexes. The frequency at which those adjustments are applied varies by contract, geographic region and supply point.
The mix of NaHS sales volumes to which we are able to apply such adjustments may vary due to timing or other
factors such as competitive pressures. To the extent we are unable to pass these caustic soda price changes onto our
customers, Segment Margin may be impacted. Additionally, our bulk purchase and storage capabilities related to
caustic soda allow us to somewhat mitigate the effects of changes in index prices for caustic soda on our operating
costs.
65
Onshore Facilities and Transportation Segment
Operating results for our onshore facilities and transportation segment were as follows:
Gathering, marketing, and logistics revenue
Crude oil and CO2 tariffs and revenues from direct financing leases of CO2 pipelines
Payments received under direct financing leases not included in income
Crude oil and products costs, excluding unrealized gains and losses from derivative
transactions
Operating costs, excluding non-cash charges for equity-based compensation and other non-
cash expenses
Other
Segment Margin
Volumetric Data (average barrels/day unless otherwise noted):
Onshore crude oil pipelines:
Texas
Jay
Mississippi
Louisiana (1)
Wyoming (2)
Onshore crude oil pipelines total
CO2 pipeline (average Mcf/day):
Free State
Crude oil and petroleum products sales:
Total crude oil and petroleum products sales
Rail load/unload volumes (3)
Year Ended December 31,
2016
2015
(in thousands)
$
930,347
$ 1,612,570
58,567
6,277
68,265
5,685
(823,780)
(1,479,972)
(94,592)
6,545
(116,842)
5,688
$
83,364
$
95,394
33,814
14,815
10,247
44,295
10,959
71,906
16,828
15,472
32,481
7,397
114,130
144,084
97,955
161,409
62,484
19,691
91,074
27,044
(1) Total daily volume for the twelve months ended December 31, 2016, includes 8,997 barrels per day of refined products associated
with our Port of Baton Rouge Terminal pipelines which became operational in the fourth quarter of 2016.
(2) Represents volumes per day from the period the pipeline began operations in August of 2015.
(3) Indicates total barrels for which fees were charged for either loading or unloading at all rail facilities.
Segment Margin for our onshore facilities and transportation segment decreased $12 million, or 13%, in 2016 as
compared to 2015. The most significant components of this change are discussed below.
• With respect to our crude oil and CO2 pipelines, revenues decreased $9.7 million, or 14%, principally due to a net
decrease in throughput volumes of 29,954 barrels per day, or 21%. This was primarily the result of decreased volumes
on our Texas pipeline system, particularly delivery volumes to the Texas City refining market. We believe such lower
volumes to historical customers will last indefinitely as those customers have made alternative arrangements as a result
of our endeavors to expand, extend and repurpose our facilities into longer lived, higher value service. This decrease
was partially offset by an increase in volumes on our Louisiana system, as our new Port of Baton Rouge Terminal and
Anchorage Tank Farm crude oil and refined products pipelines began flowing volumes during the fourth quarter of
2016. Volume variances on our other onshore pipeline systems had a less significant impact on the decrease in tariff
revenues between the respective quarters due to a mix of tariff rates amongst these systems and less significant
decreases in volumes. Although volumes on our Free State CO2 pipeline system decreased, that decrease had a much
smaller effect on the contributions to Segment Margin by that pipeline given the “incentive” tariff on this system
which results in fluctuations in volumes above a base level on our Free State CO2 pipeline system having a limited
impact on Segment Margin.
66
• The decrease in our Segment Margin is also partially due to lower demand for our services in our historical back-to-
back, or buy/sell, crude oil marketing business associated with aggregating and trucking crude oil from producers'
leases to local or regional re-sale points. We have found it difficult to compete with certain participants in the market
who are willing to lose money on local gathering because they are attempting to minimize their losses from minimum
volume or take-or-pay commitments they previously made in anticipation of new production that has not yet and is
unlikely to come online.
• These decreases were partially offset by the improved performance of our now right-sized heavy fuel oil business after
reducing volumes and related infrastructure to match new market realities resulting from the general lightening of
refineries' crude slates which has resulted in a better supply/demand balance between heavy refined bottoms and
domestic coker and asphalt requirements.
• While rail volumes were down compared to 2015, these results had a less significant impact on Segment Margin due to
minimum volume commitments on certain of our facilities and our results reflect a ramp up in the fourth quarter of
2016 following the emergence from a refinery turnaround during the third quarter of 2016 by a major refinery
customer supported by our Baton Rouge facilities.
Marine Transportation Segment
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 equity-based compensation and
other non-cash expenses
Segment Margin (in thousands)
Fleet Utilization: (2)
Inland Barge Utilization
Offshore Barge Utilization
Year Ended December 31,
2016
2015
$
$
$
$
88,502
85,594
38,925
213,021
142,942
70,079
$
$
$
$
95,588
102,281
40,888
238,757
135,535
103,222
91.4%
90.5%
96.7%
98.7%
(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 2016 decreased $33.1 million, or 32% from 2015. The decrease in
Segment Margin is primarily due to a combination of lower utilization and lower day rates across our various marine asset
classes, excepting the M/T American Phoenix which is under long term contract through September 2020. In our offshore barge
fleet, as a number of our units have come off longer term contracts, we have chosen to primarily place them in spot service or
short-term (less than a year) service, as we believe the day rates currently being offered by the market are at, or approaching,
cyclical lows. In addition, our offshore barge fleet has experienced some volume cannibalization due to excess capacity issues
that have arisen as new tankers and barges have been placed into service in anticipation of domestic crude oil volumes that have
not yet and may not materialize. Such excess capacity may require a significant amount of time to resolve. In our inland fleet,
we saw somewhat of a strengthening in utilization and stabilization in spot day rates towards the end of the year, especially in
the black oil, or heavy, intermediate refined products trade, the trade to which we have almost exclusively committed our inland
barges.
67
Other Costs and Interest
General and administrative expenses
General and administrative expenses not separately identified below:
Corporate
Segment
Equity-based compensation plan expense
Third party costs related to business development activities and growth projects
Total general and administrative expenses
Year Ended December 31,
2016
2015
(in thousands)
$
$
35,841
$
37,922
3,264
4,575
1,945
45,625
$
3,608
4,564
18,901
64,995
Total general and administrative expenses decreased $19 million between 2016 and 2015. This decrease was
principally due to higher third party costs, primarily financing, legal and accounting, related to business development and
growth activities (primarily related to third party costs incurred for business development activities surrounding our Enterprise
acquisition) incurred during 2015.
Depreciation and amortization expense
Depreciation on fixed assets
Amortization of intangible assets
Amortization of CO2 volumetric production payments
Total depreciation and amortization expense
Year Ended December 31,
2016
2015
(in thousands)
$
$
193,976
$
124,207
24,310
3,910
20,044
5,889
222,196
$
150,140
Total depreciation and amortization expense increased $72 million between 2016 and 2015 primarily as a result of
acquiring assets and placing constructed assets' in service during calendar 2015 (including the offshore pipelines and services
assets acquired as a result of our Enterprise acquisition) and 2016.
Interest expense, net
Interest expense, senior secured credit facility (including commitment fees)
Interest expense, senior unsecured notes
Amortization and write-off of debt issuance costs and premium
Capitalized interest
Net interest expense
Year Ended December 31,
2016
2015
(in thousands)
41,948
$
114,437
10,138
(26,576)
139,947
$
23,072
87,326
7,266
(17,068)
100,596
$
$
Net interest expense increased $39 million during 2016 primarily due to an increase in our average outstanding
indebtedness from newly acquired and constructed assets, primarily related to additional debt outstanding as a result of
financing our Enterprise acquisition. In July 2015, we issued an additional $750 million of aggregate principal amount of
6.75% senior unsecured notes to fund a portion of the purchase price for our Enterprise acquisition. Capitalized interest costs
increased in 2016 due to our growth capital expenditures for projects when compared to the prior year.
Financial Measures
Overview
68
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 Segment Margin to
net income 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; 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.
In the fourth quarter of 2017, we revised portions of the format and definitions relating to our presentation of non-
GAAP financial measures. Amounts attributable to prior periods have been recast. We believe our revised presentation:
•
•
•
•
better aligns our non-GAAP financial measures with a broader array of criteria management uses to evaluate our
performance, liquidity and other activities and conditions in light of the increasing size, diversity and complexity of our
operations;
enhances transparency;
improves readability; and
provides a general format that is more consistent with many of our peers.
The primary substantive changes in our presentation are (i) to include "gains on asset sales" (approximately $40.3
million) in Available Cash before Reserves and (ii) to include the effects of a provision for certain leased assets no longer in use
(approximately $12.6 million). Some of our peers exclude "gains on asset sales" from some or all of their non-GAAP financial
measures and others include "proceeds from asset sales." For purposes of Available Cash before Reserves, we view that portion
of the cash proceeds from an asset sale that are in excess of the carrying value of our investment as cash generated by our
operating activities, which can be used for discretionary purposes, similar to operating income generated by an asset.
Segment Margin
We define Segment Margin as revenues less product costs, operating expenses, and segment general and administrative
expenses, after eliminating gain or loss on sale of assets, plus or minus applicable Select Items. Although, we do not
necessarily consider all of our Select Items to be non-recurring, infrequent or unusual, we believe that an understanding of these
Select Items is important to the evaluation of our core operating results. Our chief operating decision maker (our Chief
Executive Officer) evaluates segment performance based on a variety of measures including Segment Margin, segment volumes
where relevant and capital investment.
A reconciliation of Segment Margin to net income 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:
69
(1) the financial performance of our assets;
(2) our operating performance;
(3) the viability of potential projects, including our cash and overall return on alternative capital investments as
compared to those of other companies in the midstream energy industry;
(4) the ability of our assets to generate cash sufficient to satisfy certain non-discretionary cash requirements,
including interest payments and certain maintenance capital requirements; and
(5) our ability to make certain discretionary payments, such as distributions on our 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 before interest, taxes,
depreciation and amortization (including impairment, write-offs, accretion and similar items) after eliminating other non-cash
revenues, expenses, gains, losses and charges (including any loss on asset dispositions), plus or minus certain other select
items that we view as not indicative of our core operating results (collectively, “Select Items”), as adjusted for certain items,
the most significant of which in the relevant reporting periods have been the sum of maintenance capital utilized, net interest
expense and cash tax expense. Although, we do not necessarily consider all of our Select Items to be non-recurring, infrequent
or unusual, we believe that an understanding of these Select Items is important to the evaluation of our core operating results.
The most significant Select Items in the relevant reporting periods are set forth below.
I. Applicable to all Non-GAAP Measures
Differences in timing of cash receipts for certain contractual arrangements1
Adjustment regarding direct financing leases2
Revaluation of certain liabilities and assets3
Certain non-cash items:
Unrealized (gain) loss on derivative transactions excluding fair value hedges, net of
changes in inventory value
Loss on debt extinguishment
Adjustment regarding equity investees5
Other
Sub-total Select Items, net4
II. Applicable only to Available Cash before Reserves
Certain transaction costs6
Equity compensation adjustments
Other
Total Select Items, net7
Year Ended
December 31,
2017
2016
$(17,540) $ (13,253)
6,277
6,921
—
6,044
9,942
6,242
31,852
5,326
42,743
1,790
—
39,276
1,748
41,882
16,833
(1,227)
946
$ 59,295
1,945
(763)
2,064
$ 45,128
(1) Represents adjustments attributable to certain cash payments received from customers under certain of our minimum payment obligation contracts that are
not recognized as revenue under GAAP in the period in which such payments are received. For purposes of our Non-GAAP measures, we add those amounts
in the period of payment and deduct them in the period in which GAAP recognizes them.
(2) Represents the net effect of adding cash receipts from direct financing leases and deducting expenses relating to direct financing leases.
(3) Represents a valuation allowance related to the collectibility of certain disputed receivables and claims.
(4) Represents all Select Items applicable to Segment Margin.
(5) Represents the net effect of adding distributions from equity investees and deducting earnings of equity investees net to us.
(6) Represents transaction costs relating to certain merger and acquisition and financing transactions and certain interest payments on acquisition indebtedness
incurred in advance of acquisition.
(7) Represents Select Items applicable to Available Cash before Reserves.
Disclosure Format Relating to Maintenance Capital
70
We have implemented a modified format relating to maintenance capital requirements because our maintenance capital
expenditures have changed materially in nature (discretionary vs. non-discretionary), timing and amount from time to time. We
believe that, without such modified disclosure, such changes in our maintenance capital expenditures could be confusing and
potentially misleading to users of our financial information, particularly in the context of the nature and purposes of our
Available Cash before Reserves measure. Our modified disclosure format provides those users with information in the form of
our maintenance capital utilized measure (which we deduct to arrive at Available Cash before Reserves). Our maintenance
capital utilized measure constitutes a proxy for non-discretionary maintenance capital expenditures and it takes into
consideration the relationship among maintenance capital expenditures, operating expenses and depreciation from period to
period.
Maintenance Capital Requirements
MAINTENANCE CAPITAL EXPENDITURES
Maintenance capital expenditures are capitalized costs that are necessary to maintain the service capability of our
existing assets, including the replacement of any system component or equipment which is worn out or obsolete. Maintenance
capital expenditures can be discretionary or non-discretionary, depending on the facts and circumstances.
Prior to 2014, substantially all of our maintenance capital expenditures have been (a) related to our pipeline assets
and similar infrastructure, (b) non-discretionary in nature and (c) immaterial in amount as compared to our Available Cash
before Reserves measure. Those historical expenditures were non-discretionary (or mandatory) in nature because we had very
little (if any) discretion as to whether or when we incurred them. We had to incur them in order to continue to operate the
related pipelines in a safe and reliable manner and consistently with past practices. If we had not made those expenditures, we
would not have been able to continue to operate all or portions of those pipelines, which would not have been economically
feasible. An example of a non-discretionary (or mandatory) maintenance capital expenditure would be replacing a segment of
an old pipeline because one can no longer operate that pipeline safely, legally and/or economically in the absence of such
replacement.
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 future
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 new 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
71
utilized calculations will reflect the utilization of solely those maintenance capital expenditures incurred since December 31,
2013.
Available Cash before Reserves for the years ended December 31, 2017 and 2016 was as follows:
Net income attributable to Genesis Energy, L.P.
$
Income Tax expense
Depreciation, depletion, amortization, and accretion
Year Ended December 31,
2017
2016
(in thousands)
82,647
(3,959)
262,021
59,295
(13,020)
(100)
2,148
$
113,249
3,342
230,563
45,128
(7,696)
(1,200)
855
$
389,032
$
384,241
Plus (minus) Select Items, net
Maintenance capital utilized
Cash tax expense
Other
Available Cash before Reserves
Liquidity and Capital Resources
General
As of December 31, 2017, we believe our balance sheet and liquidity position remained strong, including $599.8
million of borrowing capacity available under our $1.7 billion senior secured revolving credit facility. We anticipate that our
future internally-generated funds and the funds available under our credit facility will allow us to meet our ordinary course
capital needs. Our primary sources of liquidity have been cash flows from operations, borrowing availability under our credit
facility and the proceeds from issuances of equity and senior unsecured notes.
Our primary cash requirements consist of:
• working capital, primarily inventories and trade receivables and payables;
•
•
•
•
•
routine operating expenses;
capital growth and maintenance projects;
acquisitions of assets or businesses;
interest payments related to outstanding debt; and
quarterly cash distributions to our unitholders.
Capital Resources
Our ability to satisfy future capital needs will depend on our ability to raise substantial amounts of additional capital
from time to time — including through equity and debt offerings (public and private), borrowings under our credit facility and
other financing transactions—and to implement our growth strategy successfully. No assurance can be made that we will be
able to raise necessary funds on satisfactory terms.
A large portion of our financing activities in 2017 related to financing considerations surrounding our acquisition of
our Alkali Business. To finance that transaction and the related costs, we used proceeds from (i) a $550.0 million public
offering of 6.50% senior unsecured notes due 2025 in August 2017, generating net proceeds of $540.1 million after issuance
discount and underwriting fees, (ii) a $750 million private placement of Class A Convertible Preferred units in September 2017,
generating net proceeds of $726.2 million, (iii) borrowings under our revolving credit facility and (iv) cash on hand. These
activities are discussed in detail below.
On March 24, 2017, we issued 4,600,000 Class A common units in a public offering at a price of $30.65 per unit,
which included the exercise by the underwriters of an option to purchase up to 600,000 additional common units from us. We
received proceeds, net of offering costs, of approximately $140.5 million from that offering. The proceeds were used for
general partnership purposes, including repaying a portion of the borrowings outstanding under our revolving credit facility.
On August 14, 2017, we issued $550 million in aggregate principal amount of 6.50% senior unsecured notes
due October 1, 2025. Interest payments are due April 1 and October 1 of each year with the initial interest payment due April 1,
72
2018. That issuance generated net proceeds of $540.1 million, net of issuance costs incurred. The net proceeds were used to
fund a portion of the purchase price for our acquisition of our Alkali Business.
In December 2017, we issued $450 million in aggregate principal amount of 6.25% senior unsecured notes due
May 15, 2026. 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 $442.0 million, net of issuance costs incurred. The net proceeds were used to
redeem a portion of our outstanding principal on the 5.75% senior unsecured notes due 2021. Of the net proceeds, $204.8
million were used to repurchase the notes that were validly tendered, and the remaining balance was used for repaying a portion
of the borrowings outstanding under our revolving credit facility. On January 16, 2018 we called for redemption on the
remaining balance of our 2021 Notes, and the redemption was completed on February 15, 2018.
In July 2017, we amended our credit agreement to, among other things, make certain technical amendments related to
the financing of our acquisition of our Alkali Business. The key terms for rates under our $1.7 billion senior secured credit
facility, which are dependent on our leverage ratio (as defined in the credit agreement), are as follows:
• The interest rate on borrowings may be based on an alternate base rate or a Eurodollar rate, at our option. The alternate
base rate is equal to the sum of (a) the greatest of (i) the prime rate as established by the administrative agent for the
credit facility, (ii) the federal funds effective rate plus 0.5% of 1% and (iii) the LIBOR rate for a one-month maturity
plus 1% and (b) the applicable margin. The Eurodollar rate is equal to the sum of (a) the LIBOR rate for the applicable
interest period multiplied by the statutory reserve rate and (b) the applicable margin. The applicable margin varies
from 1.50% to 3.00% on Eurodollar borrowings and from 0.50% to 2.00% on alternate base rate borrowings,
depending on our leverage ratio. Our leverage ratio is recalculated quarterly and in connection with each material
acquisition. At December 31, 2017, the applicable margins on our borrowings were 1.75% for alternate base rate
borrowings and 2.75% for Eurodollar rate borrowings.
• Letter of credit fees range from 1.50% to 3.00% based on our leverage ratio as computed under the credit facility. The
rate can fluctuate quarterly. At December 31, 2017, our letter of credit rate was 2.75%.
• We pay a commitment fee on the unused portion of the $1.7 billion maximum facility amount. The commitment fee on
the unused committed amount will range from 0.25% to 0.50% per annum depending on our leverage ratio (0.50% at
December 31, 2017).
• Our credit facility contains a $300 million accordion feature, giving us the ability to expand the size of the facility up
to $2.0 billion for acquisitions or growth projects, subject to lender consent.
At December 31, 2017, we had $1.1 billion borrowed under our credit facility, with $29.0 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 $1.0 million was outstanding at December 31, 2017. Due to the revolving nature of loans
under our credit facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date
of May 9, 2022. Our credit facility does not include a “borrowing base” limitation except with respect to our inventory loans.
The total amount available for borrowings under our credit facility at December 31, 2017 was $599.8 million.
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
2021 Notes
2022 Notes
2023 Notes
2024 Notes
2025 Notes
2026 Notes
February 15,
2017
August 1,
2018
May 15,
2018
June 15,
2019
October 1,
2020
February 15,
2021
February 15,
2017
August 1,
2018
May 15,
2018
June 15,
2019
October 1,
2020
February 15,
2021
At December 31, 2017, our long-term debt totaled $3.7 billion, consisting of $1.1 billion outstanding under our credit
facility (including $29.0 million borrowed under the inventory sublimit tranche), $145 million of our 2021 Notes, $450 million
of our 2026 Notes, $550 million of our 2025 Notes, $350 million of our 2024 Notes, $400 million of our 2023 Notes and $750
million of our 2022 Notes.
73
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 preferred units. Our preferred units are a new class of
security that ranks senior to all of our currently outstanding classes or series of limited partner interests with respect to
distribution and/or liquidation rights. Holders of our preferred units vote on an as-converted basis with holders of our common
units and have certain class voting rights, including with respect to any amendment to the partnership agreement that would
adversely affect the rights, preferences or privileges, or otherwise modify the terms, of those preferred units.
Each of our preferred units accumulate quarterly distribution amounts in arrears at an annual rate of 8.75% (or
$2.9496), yielding a quarterly rate of 2.1875% (or $0.7374), subject to certain adjustments. With respect to any quarter ending
on or prior to March 1, 2019, we have the option to pay to the holders of our preferred units the applicable distribution amount
in cash, preferred units, or any combination thereof. If we elect to pay all or any portion of a quarterly distribution amount in
preferred units, the number of such preferred units will equal the product of (i) the number of then outstanding preferred units
and (ii) the quarterly rate. We have elected to pay all distribution amounts attributable to 2017 in preferred units. For each
quarter ending after March 1, 2019, we must pay all distribution amounts in respect of our preferred units in cash.
For a period of 30 days following (i) September 1, 2022 and (ii) each subsequent anniversary thereof, the holders of
our preferred units may make a one-time election to reset the quarterly distribution amount (a “Rate Reset Election”) to a cash
amount per preferred unit equal to the amount that would be payable per quarter if a preferred unit accrued interest on the Issue
Price at an annualized rate equal to three-month LIBOR plus 750 basis points; provided, however, that such reset rate shall be
equal to 10.75% if (i) such alternative rate is higher than the LIBOR-based rate and (ii) the then market price for our common
units is then less than 10% of the Issue Price. To become effective, the Rate Reset Election requires approval of holders of at
least a majority of our then outstanding preferred units and such majority must include each of our initial purchasers (or any
affiliate to whom they have transferred their preferred units) if such initial purchaser (including its affiliates) holds at least 25%
of the then outstanding preferred units.
Upon the occurrence of a Rate Reset Election, we may redeem our preferred units for cash, in whole or in part (subject
to certain minimum value limitations) for an amount per preferred unit equal to such preferred unit’s liquidation value (equal to
the Issue Price plus any accrued and accumulated but unpaid distributions, plus a prorated portion of certain unpaid partial
distributions in respect of the immediately preceding quarter and the current quarter) multiplied by (i) 110%, prior to
September 1, 2024, and (ii) 105% thereafter. Each holder of our preferred units may elect to convert all or any portion of its
preferred units into common units initially on a one-for-one basis (subject to customary adjustments and an adjustment for
accrued and accumulated but unpaid distributions and limitations) at any time after September 1, 2019 (or earlier upon a change
of control, liquidation, dissolution or winding up), provided that any conversion is for at least $50 million or such lesser amount
if such conversion relates to all of a holder’s remaining preferred units or has otherwise been approved by us.
The Rate Reset Election of these preferred units represents and embedded derivative that must be bifurcated from the
related host contract and recorded at fair value on our Consolidated Balance Sheet. See further information in Note 19. The
preferred units themselves are classified as mezzanine capital on our Consolidated Balance Sheet.
See Note 11 for additional information regarding our preferred units.
Equity Distribution Program and Shelf Registration Statements
We have the capacity to issue additional equity and debt securities to assist us in meeting our future liquidity
requirements, including those related to opportunistically acquiring assets and businesses and constructing new facilities.
In 2016, we implemented an equity distribution program that will allow us to consummate "at the market" offerings of
common units from time to time through brokered transactions, which should help mitigate certain adverse consequences of
underwritten offerings, including the downward pressure on the market price of our common units and the expensive fees and
other costs associated with such public offerings. We entered into an equity distribution agreement with a group of banks who
will act as sales agents or principals for up to $400.0 million of our common units, if and when we should elect to issue
additional common units from time to time, although there are limits to the amount of our "at the market" offerings the market
can absorb from time to time. In connection, with implementing our equity distribution program, we filed a universal shelf
registration statement (our "EDP Shelf") with the SEC. Our EDP Shelf allows us to issue up to $1.0 billion of equity and debt
securities, whether pursuant to our equity distribution program or otherwise. Our EDP Shelf will expire in October 2020. As of
December 31, 2017, we have issued no additional units under this program.
74
We have another universal shelf registration statement (our "2015 Shelf") on file with the SEC. Our 2015 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 2015 Shelf will expire in April 2018. We expect to file a replacement universal shelf registration statement
before our 2015 Shelf expires.
Cash Flows from Operations
We generally utilize the cash flows we generate from our operations to fund our distributions and working capital
needs. Excess funds that are generated are used to repay borrowings under our credit facility and/or to fund a portion of our
capital expenditures. Our operating cash flows can be impacted by changes in items of working capital, primarily variances in
the carrying amount of inventory and the timing of payment of accounts payable and accrued liabilities related to capital
expenditures.
We typically sell our crude oil in the same month in which we purchase it, so we do not need to rely on borrowings
under our credit facility to pay for such crude oil purchases, other than inventory. During such periods, our accounts receivable
and accounts payable generally move in tandem as we make payments and receive payments for the purchase and sale of crude
oil.
In our petroleum products activities, we buy products and typically either move those products to one of our storage
facilities for further blending or sell those products within days of our purchase. The cash requirements for these activities can
result in short term increases and decreases in our borrowings under our credit facility.
In our Alkali Business, we typically extract trona from our mining facilities, process into soda ash and other alkali
products, and deliver and sell to our customers all within a relatively short time frame. If we did experience any differences in
timing of extraction, processing and sales of this trona or Alkali products, this could impact the cash requirements for these
activities in the short term.
The storage of our inventory of crude oil, petroleum products and alkali products can have a material impact on our
cash flows from operating activities. In the month we pay for the stored crude oil or petroleum products (or pay for extraction
and processing activities in the case of alkali products), we borrow under our credit facility (or use cash on hand) to pay for the
crude oil or petroleum products (or extraction/processing of alkali products), utilizing a portion of our operating cash flows.
Conversely, cash flow from operating activities increases during the period in which we collect the cash from the sale of the
stored crude oil, petroleum products or alkali products. Additionally, we may be required to deposit margin funds with the
NYMEX when commodity prices increase as the value of the derivatives utilized to hedge the price risk in our inventory
fluctuates. These deposits also impact our operating cash flows as we borrow under our credit facility or use cash on hand to
fund the deposits.
Net cash flows provided by our operating activities were $338.9 million and $298.3 million for 2017 and 2016,
respectively. As discussed above, changes in the cash requirements related to payment for petroleum products or collection of
receivables from the sale of inventory impact the cash provided by operating activities. Additionally, changes in the market
prices for crude oil, petroleum products and alkali products can result in fluctuations in our working capital and, therefore, our
operating cash flows between periods as the cost to acquire a barrel of crude oil or petroleum products (or the cost to extract/
process in the case alkali products) will require more or less cash. The increase in operating cash flow for 2017 compared to
2016 was primarily due to a decrease in working capital needs.
Net cash flows provided by our operating activities were $298.3 million and $289.5 million for 2016 and 2015,
respectively. The decrease in operating cash flow for 2016 compared to 2015 was primarily due to an increase in cash earnings,
as partially offset by an increase in working capital needs.
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 unitholders. We finance maintenance capital expenditures and smaller internal
growth projects and distributions primarily with cash generated by our operations. We have historically funded material growth
capital projects (including acquisitions and internal growth projects) with borrowings under our credit facility, equity issuances
and/or the issuance of senior unsecured notes.
75
Capital Expenditures and Business and Asset Acquisitions
The following table summarizes our expenditures for fixed assets, business and other asset acquisitions in the periods
indicated:
Capital expenditures for fixed and intangible assets:
Maintenance capital expenditures:
Offshore pipeline transportation assets
Sodium mineral and sulfur services assets
Marine transportation assets
Onshore facilities and transportation assets
Information technology systems
Total maintenance capital expenditures
Growth capital expenditures:
Offshore pipeline transportation assets
Sodium minerals and sulfur services assets
Marine transportation assets
Onshore facilities and transportation assets
Information technology systems
Total growth capital expenditures
Total capital expenditures for fixed and intangible assets
Capital expenditures for business combinations, net of liabilities
assumed:
Acquisition of Alkali Business
Acquisition of remaining interest in equity investment
Acquisition of offshore pipelines (1)
Total business combinations capital expenditures
Capital expenditures related to equity investees (1)
Total capital expenditures
Years Ended December 31,
2017
2016
2015
(in thousands)
$
5,037
$
3,530
$
24,045
27,295
5,381
286
62,044
2,274
14,007
10,563
547
30,921
$
3,778
$
7,657
$
5,424
41,119
143,742
266
194,329
256,373
1,325,000
—
—
1,325,000
—
—
64,797
306,075
7,056
385,585
416,506
—
35,090
—
35,090
—
1,888
1,555
26,124
15,106
515
45,188
963
40
42,885
394,581
2,243
440,712
485,900
—
—
1,521,569
1,521,569
2,900
$ 1,581,373
$
451,596
$ 2,010,369
(1) Amount represents our investment in the SEKCO pipeline equity investee prior to our Enterprise acquisition.
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
We anticipate spending approximately $100 million, inclusive of capitalized interest, during 2018 for projects
currently under construction. The most significant of our projects are described below.
Baton Rouge Area Infrastructure Expansion
We are currently expanding our existing Baton Rouge area infrastructure to allow for greater capacity and flexibility in
servicing our major refinery customer in the region. This expansion includes the construction of an additional 500,000 barrels
of crude oil tankage at our existing Baton Rouge Terminal. Additionally, this expansion will include the upgrading of pumping
and other infrastructure capabilities in order to allow for the efficient handling of expected increases in crude oil volumes
received at our Baton Rouge area facilities. We expect these assets to become operational in the first half of 2018.
Wyoming Infrastructure Expansion
76
We have recently begun construction of a new gathering system to connect crude oil production to our existing Powder
River basin pipeline infrastructure. This new gathering system is supported by a new long-term contract with one of the leading
operators in the Powder River basin. The operator will dedicate approximately 150,000 acres to the new gathering system and a
total of 300,000 acres to our Powder River basin pipeline infrastructure for a period of ten years, including approximately
150,000 acres that had previously been dedicated. We expect the new gathering system to become operational throughout 2018
depending on the pace of upstream activity.
Inland Marine Barge Transportation Expansion
We ordered 28 new-build barges and 18 new-build push boats for our inland marine barge transportation fleet. We
have accepted delivery of 26 of those barges and 18 of those push boats through December 31, 2017. We took delivery of those
remaining vessels in January 2018.
Maintenance Capital Expenditures
Maintenance capital expenditures have annually ranged between $15 million and $65 million. We expect a large
portion of our maintenance capital expenditures incurred to be related to our Alkali Business going forward, given the nature of
its operations. See previous discussion under "Available Cash before Reserves" for how such maintenance capital utilization is
reflected in our calculation of Available Cash before Reserves.
Distributions to Unitholders
Our partnership agreement requires us to distribute 100% of our available cash (as defined therein) within 45 days
after the end of each quarter to unitholders of record. Available cash generally means, for each fiscal quarter, all cash on hand
at the end of the quarter:
•
less the amount of cash reserves that our general partner determines in its reasonable discretion is necessary or
appropriate to:
•
•
•
provide for the proper conduct of our business;
comply with applicable law, any of our debt instruments, or other agreements; or
provide funds for distributions to our unitholders for any one or more of the next four quarters;
•
plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital
borrowings. Working capital borrowings are generally borrowings that are made under our credit facility and in all
cases are used solely for working capital purposes or to pay distributions to partners.
In February 2018, we paid a distribution of $0.51 per unit related to the fourth quarter of 2017. With respect to our
Class A Convertible Preferred Units, we have declared a payment-in-kind ("PIK") of the quarterly distribution, which resulted
in the issuance of an additional 490,252 Class A Convertible Preferred Units. This PIK amount equates to a distribution of
$0.7374 per Class A Convertible Preferred Unit for the 2017 Quarter, or $2.9496 annualized. These distributions were paid on
February 14, 2018 to unitholders holders of record at the close of business January 31, 2018.
Our historical distributions to common unitholders are shown in the table below (in thousands, except per unit
amounts).
77
Distribution For
2015
4th Quarter
2016
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
2017
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
Date Paid
Per Unit
Amount
Total
Amount
February 12, 2016
May 13, 2016
August 12, 2016
November 14, 2016
February 14, 2017
May 15, 2017
August 14, 2017
$
$
$
$
$
$
$
November 14, 2017
February 14, 2018
$
(1) $
0.6550
0.6725
0.6900
0.7000
0.7100
0.7200
0.7225
0.5000
0.5100
$
$
$
$
$
$
$
$
$
72,036
73,961
81,406
82,585
83,765
88,257
88,563
61,290
62,515
(1) This distribution was paid on February 14, 2018 to unitholders of record as of January 31, 2018.
Commitments and Off-Balance Sheet Arrangements
Contractual Obligations and Commercial Commitments
In addition to our credit facility discussed above, we have contractual obligations under operating leases as well as
commitments to purchase crude oil and petroleum products. The table below summarizes our obligations and commitments at
December 31, 2017.
Commercial Cash Obligations and
Commitments
Less than
one year
Payments Due by Period
1 - 3 years
3 - 5 Years
(in thousands)
More than
5 years
Total
Contractual Obligations:
Long-term debt (1)
Estimated interest payable on long-
term debt (2)
Operating lease obligations
Unconditional purchase obligations (3)
Other Cash Commitments:
Capital expenditure commitments(4)
Asset retirement obligations (5)
$
— $
— $
1,976,990
$
1,721,128
$
3,698,118
235,235
44,580
297,355
7,100
20,377
470,470
77,973
80,404
—
28,947
389,446
51,360
8,100
—
—
231,045
115,937
16,200
—
148,863
1,326,196
289,850
402,059
7,100
198,187
Total
$
604,647
$
657,794
$
2,425,896
$
2,233,173
$
5,921,510
(1) Our credit facility allows us to repay and re-borrow funds at any time through the maturity date of May 9, 2022. We have $145
million in aggregate principal amount of senior unsecured notes that mature on February 15, 2021(the "2021 Notes"), $750 million
in aggregate principal amount of senior unsecured notes that mature on August 1, 2022 (the "2022 Notes"), $400 million in
aggregate principal amount of senior unsecured notes that mature on May 15, 2023 (the "2023 Notes"), $350 million in aggregate
principal amount of senior unsecured notes that mature on June 15, 2024 (the "2024 Notes"), $550 million in aggregate principal
amount of senior unsecured notes that mature on October 1, 2025 (the"2025 Notes"), and $450 million in aggregate principal
amount of senior unsecured notes that mature on May 15, 2026 (the "2026 Notes").
(2) Interest on our long-term debt under our credit facility is at market-based rates. The interest rates on our 2021, 2022, 2023, 2024,
2025, and 2026 Notes are 5.75%, 6.75%. 6.00%, 5.625%, 6.50%, and 6.25%, respectively. The amount shown for interest payments
represents the amount that would be paid if the debt outstanding at December 31, 2017 under our credit facility remained
outstanding through the final maturity date of May 9, 2022 and interest rates remained at the December 31, 2017 market levels
through the final maturity date. Also included is the interest on our senior unsecured notes through their respective maturity dates.
(3) Unconditional purchase obligations include agreements to purchase goods and services that are enforceable and legally binding and
specify all significant terms. Contracts to purchase crude oil and petroleum products are generally at market-based prices. For
purposes of this table, estimated volumes and market prices at December 31, 2017 were used to value those obligations. The actual
78
physical volumes and settlement prices may vary from the assumptions used in the table. Uncertainties involved in these estimates
include levels of production at the wellhead, changes in market prices and other conditions beyond our control.
(4) Represents unconditional payment obligations for services to be rendered or products to be delivered in connection with our capital
spending program.
(5) Represents the estimated future asset retirement obligations on a discounted basis. The recorded asset retirement obligation on our
balance sheet at December 31, 2017 was $198.2 million and is further discussed in Note 6 to our Consolidated Financial
Statements.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements, special purpose entities, or financing partnerships, other than as disclosed
under “Contractual Obligations and Commercial Commitments” above.
Critical Accounting Policies and Estimates
The preparation of our consolidated financial statements in conformity with accounting principles generally accepted
in the United States requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported
amounts of revenues and expenses during the reporting period. We base these estimates and assumptions on historical
experience and other information that are believed to be reasonable under the circumstances. Estimates and assumptions about
future events and their effects cannot be determined with certainty, and, accordingly, these estimates may change as new events
occur, as more experience is acquired, as additional information is obtained and as the business environment in which we
operate changes. Significant accounting policies that we employ are presented in the Notes to our Consolidated Financial
Statements in Item 8 (see Note 2 “Summary of Significant Accounting Policies”).
We have defined critical accounting policies and estimates as those that are most important to the portrayal of our
financial results and positions. These policies require management’s judgment and often employ the use of information that is
inherently uncertain. Our most critical accounting policies pertain to measurement of the fair value of assets and liabilities in
business acquisitions, depreciation, amortization and impairment of long-lived assets, deferred maintenance on marine fixed
assets, equity plan compensation accruals and contingent and environmental liabilities. We discuss these policies below.
Fair Value of Assets and Liabilities Acquired and Identification of Associated Goodwill and Intangible Assets
In conjunction with each acquisition we make, we must allocate the cost of the acquired entity to the assets and
liabilities assumed based on their estimated fair values at the date of acquisition. As additional information becomes available,
we may adjust the original estimates within a short time period subsequent to the acquisition. In addition, we are required to
recognize intangible assets separately from goodwill. Determining the fair value of assets and liabilities acquired, as well as
intangible assets that relate to such items as customer relationships, contracts, trade names and non-compete agreements
involves professional judgment and is ultimately based on acquisition models and management’s assessment of the value of the
assets acquired, and to the extent available, third party assessments. Intangible assets with finite lives are amortized over their
estimated useful life as determined by management. Goodwill is not amortized but instead is periodically assessed for
impairment. Uncertainties associated with these estimates include fluctuations in economic obsolescence factors in the area and
potential future sources of cash flow. We cannot provide assurance that actual amounts will not vary significantly from
estimated amounts. See Note 3 to our Consolidated Financial Statements in Item 8 regarding further discussion regarding our
acquisitions.
Depreciation, Amortization and Depletion of Long-Lived Assets and Intangibles
In order to calculate depreciation, depletion and amortization we must estimate the useful lives of our fixed assets
(including the reserve life of our mineral leaseholds) at the time the assets are placed in service. We compute depreciation using
the straight-line method based on these estimated useful lives. The actual period over which we will use the asset may differ
from the assumptions we have made about the estimated useful life. We adjust the remaining useful life as we become aware of
such circumstances.
Intangible assets with finite useful lives are required to be amortized over their respective estimated useful lives. If an
intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset shall be amortized
over the best estimate of its useful life. At a minimum, we will assess the useful lives and residual values of all intangible assets
on an annual basis to determine if adjustments are required. We are recording amortization of our customer and supplier
relationships, licensing agreements and trade names based on the period over which the asset is expected to contribute to our
future cash flows. Generally, the contribution of these assets to our cash flows is expected to decline over time, such that greater
value is attributable to the periods shortly after the acquisition was made. Our favorable lease and other intangible assets are
being amortized on a straight-line basis over their expected useful lives.
79
We compute depletion using the units of production method using actual production and our estimated reserve life.
The actual reserve life may differ from the assumptions we have made about the estimated reserve life.
Impairment of Long-Lived Assets including Intangibles and Goodwill
When events or changes in circumstances indicate that the carrying amount of a fixed asset or intangible asset with
finite lives may not be recoverable, we review our assets for impairment. We compare the carrying value of the fixed asset to
the estimated undiscounted future cash flows expected to be generated from that asset. Estimates of future net cash flows
include estimating future volumes, future margins or tariff rates, future operating costs and other estimates and assumptions
consistent with our business plans. If we determine that an asset’s unamortized cost may not be recoverable due to impairment;
we may be required to reduce the carrying value and the subsequent useful life of the asset. Any such write-down of the value
and unfavorable change in the useful life of an intangible asset would increase costs and expenses at that time. Goodwill
represents the excess of the purchase prices we paid for certain businesses over their respective fair values. We do not amortize
goodwill; however, we evaluate, and test if necessary, our goodwill (at the reporting unit level) for impairment on October 1 of
each fiscal year, and more frequently, if indicators of impairment are present.
We may perform a qualitative assessment of relevant events and circumstances about the likelihood of goodwill
impairment. If it is deemed more likely than not the fair value of the reporting unit is less than its carrying amount, we calculate
the fair value of the reporting unit. Otherwise, further testing is not required. We may also elect to exercise our unconditional
option to bypass this qualitative assessment, in which case we would also calculate the fair value of the reporting unit. The
qualitative assessment is based on reviewing the totality of several factors, including macroeconomic conditions, industry and
market considerations, cost factors, overall financial performance, other entity specific events (for example, changes in
management) or other events such as selling or disposing of a reporting unit. The determination of a reporting unit’s fair value
is predicated on our assumptions regarding the future economic prospects of the reporting unit. Such assumptions include
(i) discrete financial forecasts for the assets contained within the reporting unit, which rely on management’s estimates of
operating margins, (ii) long-term growth rates for cash flows beyond the discrete forecast period, (iii) appropriate discount rates
and (iv) estimates of the cash flow multiples to apply in estimating the market value of our reporting units. If the fair value of
the reporting unit (including its inherent goodwill) is less than its carrying value, a charge to earnings may be required to reduce
the carrying value of goodwill to its implied fair value. If future results are not consistent with our estimates, we could be
exposed to future impairment losses that could be material to our results of operations. We monitor the markets for our products
and services, in addition to the overall market, to determine if a triggering event occurs that would indicate that the fair value of
a reporting unit is less than its carrying value. One of our monitoring procedures is the comparison of our market capitalization
to our book equity on a quarterly basis to determine if there is an indicator of impairment. As of December 31, 2017, our market
capitalization exceeded the book value of our equity (partner's capital); therefore, since there were no events or changes in
circumstances indicating impairment issues, we determined that it was not necessary to perform an interim assessment as of
December 31, 2017. We did not have any goodwill impairments in 2017, 2016 or 2015.
For additional information regarding our goodwill, see Note 9 to our Consolidated Financial Statements in Item 8.
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 expense routine repairs and maintenance as they
are incurred. For the major replacements and improvements we defer and amortize the costs over the length of time that the
certification is supposed to last, which is generally the 5 year (60 month) internal inspection regulated by the US Coast Guard.
Inherent in this process are judgments we make regarding whether the specific cost incurred is capitalizable and the period that
the incurred cost will benefit.
Equity Compensation Plan Accrual
Our 2010 Long-Term Incentive Plan provides for grantees, which may include key employees and directors, to receive
cash at the vesting of the phantom units equal to the average of the closing market price of our common units for the twenty
trading days prior to the vesting date. Our phantom units are comprised of both service-based and performance-based awards.
Until the vesting date, we calculate estimates of the fair value of the awards and record that value as compensation expense
during the vesting period on a straight-line basis. These estimates are based on the current trading price of our common units
and an estimate of the forfeiture rate we expect may occur. For our performance-based awards, our fair value estimates are
weighted based on probabilities for each performance condition applicable to the award. At December 31, 2017, we had
822,212 phantom units outstanding and recorded a credit to expense of $3.4 million of expense during 2017. The liability
recorded for phantom units expected to vest fluctuates with the market price of our common units. At the date of vesting, any
80
difference between the estimates recorded and the actual cash paid to the grantee will be charged to expense. At December 31,
2017, we estimated approximately $2.1 million of remaining compensation costs to be recognized over a weighted average
period of approximately one and a half years for these awards. Changes in our assumptions may impact our liabilities and
expenses related to these awards.
See Note 16 to our Consolidated Financial Statements in Item 8 for further discussion regarding our equity
compensation plans.
Fair Value of Derivatives
The fair value of a derivative at a particular period end does not reflect the end results of a particular transaction, and
will most likely not reflect the gain or loss at the conclusion of a transaction. We reflect estimates for these items based on our
internal records and information from third parties. We have commodity and other derivatives that are accounted for as assets
and liabilities at fair value in our Consolidated Balance Sheets. The valuations of our derivatives that are exchange traded are
based on market prices on the applicable exchange on the last day of the period. For our derivatives that are not exchange
traded, the estimates we use are based on indicative broker quotations or an internal valuation model. Our valuation models
utilize market observable inputs such as price, volatility, correlation and other factors and may not be reflective of the price at
which they can be settled due to the lack of a liquid market.
We also have embedded derivatives in our Class A Convertible preferred units that are accounted for as liabilities at
fair value in our Consolidated Balance Sheet as of December 31, 2017. Derivatives related to the embedded derivatives in our
preferred units are valued using a model that contains inputs, including our common unit price, 30-year U.S. Treasury rates,
default probabilities and timing estimates, which involve management judgment.
Liability and Contingency Accruals
We accrue reserves for contingent liabilities including environmental remediation and potential legal claims. When our
assessment indicates that it is probable that a liability has occurred and the amount of the liability can be reasonably estimated,
we make accruals. We base our estimates on all known facts at the time and our assessment of the ultimate outcome, including
consultation with external experts and counsel. We revise these estimates as additional information is obtained or resolution is
achieved.
We also make estimates related to future payments for environmental costs to remediate existing conditions
attributable to past operations. Environmental costs include costs for studies and testing as well as remediation and restoration.
We sometimes make these estimates with the assistance of third parties involved in monitoring the remediation effort.
At December 31, 2017, we were not aware of any contingencies or liabilities that would have a material effect on our
financial position, results of operations or cash flows.
Recent Accounting Pronouncements
Recently Issued and Recently Adopted
In May 2014, the FASB issued revised guidance on revenue from contracts with customers that will supersede most
current revenue recognition guidance, including industry-specific guidance. The core principle of the revenue model is that an
entity will recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the
consideration to which the entity expects to be entitled in exchange for those goods or services. The new standard provides a
five-step analysis for transactions to determine when and how revenue is recognized. The guidance permits the use of either a
full retrospective or a modified retrospective transition method. In July 2015, the FASB approved a one year deferral of the
effective date of this standard to December 15, 2017 for annual reporting periods beginning after that date. The FASB also
approved early adoption of the standard, but not before the original effective date of December 15, 2016. As a result of our
process of evaluating the impact of this guidance on each type of revenue contract entered into with customers, we have
determined that the adoption of this guidance will have an immaterial impact on revenues and costs in certain of our revenue
streams including our legacy sulfur removal operations relating to our NaHS business. We expect these items to have an even
less significant impact on net income on a go forward basis. As relating to the adoption of this guidance, we will apply the
modified retrospective transition approach.
In July 2015, the FASB issued guidance modifying the accounting for inventory. Under this guidance, the
measurement principle for inventory will change from lower of cost or market value to lower of cost and net realizable value.
The guidance defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably
predictable costs of completion, disposal, and transportation. The guidance is effective for reporting periods after December 15,
2016, with early adoption permitted. We have adopted this guidance as of January 1, 2017 with no material impact on our
consolidated financial statements.
81
In February 2016, the FASB issued guidance to improve the transparency and comparability among companies by
requiring lessees to recognize a lease liability and a corresponding lease asset for virtually all lease contracts. The guidance also
requires additional disclosure about leasing arrangements. The guidance is effective for interim and annual periods beginning
after December 15, 2018 and requires a modified retrospective approach to adoption. Early adoption is permitted. We are
currently evaluating this guidance.
In August 2016, the FASB issued guidance that addresses how certain cash receipts and payments are presented and
classified in the statement of cash flows under Topic 230, Statement of Cash flow, and other Topics. The guidance is effective
for annual reporting periods, and interim periods therein, beginning after December 15, 2017. We expect this guidance to have
an impact on how we report our operating and investing cash flows from certain cash receipts and payments, particularly
relating to cash distributions received from certain of our equity investees.
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 do not expect the adoption of this guidance to have a material
impact on our consolidated financial statements.
Item 7a. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to various market risks, primarily related to volatility in crude oil and petroleum products prices, soda
ash prices, NaHS and NaOH prices and interest rates. Our policy is to purchase only commodity products for which we have a
market, and to structure our sales contracts so that price fluctuations for those products do not materially affect the Segment
Margin we receive. We do not acquire and hold futures contracts or other derivative products for the purpose of speculating on
price changes.
Our primary price risk relates to the effect of crude oil and petroleum products price fluctuations on our inventories
and the fluctuations each month in grade and location differentials and their effect on future contractual commitments. Our risk
management policies are designed to monitor our physical volumes, grades and delivery schedules to ensure our hedging
activities address the market risks that are inherent in our gathering and marketing activities. We believe our hedging activities
have been successful in helping to mitigate these risks.
We utilize NYMEX commodity based futures contracts and option contracts to hedge our exposure to these market
price fluctuations as needed. All of our open commodity price risk derivatives at December 31, 2017 were categorized as non-
trading. On December 31, 2017 we had entered into NYMEX future contracts that will settle between February and March
2018 and NYMEX options contracts that will settle during February and May 2018. This accounting treatment is discussed
further in Note 18 to our Consolidated Financial Statements.
The table below presents information about our open commodity derivative contracts at December 31, 2017. Notional
amounts in barrels or gallons, the weighted average contract price, total contract amount and total fair value amount in U.S.
dollars of our open positions are presented below. Fair values were determined by using the notional amount in barrels or
gallons multiplied by the December 31, 2017 quoted market prices on the NYMEX. All of the hedge positions offset physical
exposures to the cash market; none of these offsetting physical exposures are included in the table below.
82
Unit of
Measure
for Volume
Contract
Volumes
(in 000’s)
Unit of
Measure
for Price
Weighed
Average
Market
Price
Contract
Value
(in 000’s)
Mark-to
Market
Change
(in 000’s)
Settlement
Value
(in 000’s)
NYMEX Futures Contracts
Sell (Short) Contracts:
Crude Oil
#6 Fuel Oil
Buy (Long) Contracts:
Crude Oil
#6 Fuel Oil
NYMEX Option Contracts (2)
Written Contracts:
Crude Oil
Purchased Contracts:
Crude Oil
Bbl
Bbl
Bbl
Bbl
Bbl
Bbl
520
260
152
20
80
45
Bbl
Bbl
Bbl
Bbl
Bbl
Bbl
$
$
$
$
$
$
57.28
$ 29,817
55.01
$ 14,302
57.30
53.20
$
$
8,709
1,064
$
$
$
$
1,602
369
475
64
$
$
$
$
31,419
14,671
9,184
1,128
0.85
$
68
$
21
$
89
0.24
$
11
$
3
$
14
(1) Prices and volumes as presented as quoted on the NYMEX. To calculate the total contract value the price per unit in gallons should
be multiplied by 42 gallons to convert into a price per barrel.
(2) Weighted average premium received/paid.
We manage our risks of volatility in NaOH prices by indexing prices for the sale of NaHS to the market price for
NaOH in most of our contracts. Given the competitive advantages associated with our naturally produced soda ash as
previously discussed (relative to that which is synthetically produced), we believe this somewhat mitigates market risk within
our Alkali Business.
We are also exposed to market risks due to the floating interest rates on our credit facility. Obligations under our senior
secured credit facility bear interest at the LIBOR rate or alternate base rate (which approximates the prime rate), at our option,
plus the applicable margin. We have not historically hedged our interest rates. On December 31, 2017, we had $1.1 billion of
debt outstanding under our credit facility. For the year ended December 31, 2017, a 10% change in LIBOR would have resulted
in approximately a $4.9 million change in net income.
The 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 11 to our Consolidated Financial
Statements for a discussion of embedded derivatives.
Item 8. Financial Statements and Supplementary Data
The information required hereunder is included in this report as set forth in the “Index to Consolidated Financial
Statements.”
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
We maintain disclosure controls and procedures and internal controls designed to ensure that information required to
be disclosed in our filings under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within
the time periods specified in the Securities and Exchange Commission’s rules and forms. Our chief executive officer and chief
financial officer, with the participation of our management, have evaluated our disclosure controls and procedures as of the end
83
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.
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, 2017. 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, 2017, the Partnership’s internal control over financial reporting is effective
based on those criteria.
In September 2017, we acquired our Alkali Business for approximately $1.325 billion in cash. Due to the recent nature
and scale of this business combination, it was not practical from a timing or resource standpoint for us to conduct a thorough
assessment of the internal control over financial reporting prior to December 31, 2017 as relating to our acquisition of this
business. As a result, we excluded our Alkali Business acquisition from the scope of our management's assessment of the
effectiveness of our internal control over financial reporting as of December 31, 2017. We are in the process of implementing
our internal control structure over the operations surrounding our Alkali Business acquired and expect that this effort will be
completed in 2018. Our Alkali Business accounted for approximately 14% of our consolidated revenues for the year ended
December 31, 2017 and approximately 20% of our total consolidated assets at December 31, 2017.
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, 2017. 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.”
84
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 Genesis
Alkali, LLC, a wholly-owned subsidiary.
The board of directors of our general partner (which we refer to as “our board of directors”) must approve significant
matters (such as material business strategies, mergers, business combinations, acquisitions or dispositions of assets, issuances
of common units, incurrences of debt or other financings and the payments of distributions). The holders of our Class B
Common Units are entitled to (i) vote in the election of our board of directors, subject to the Davison family’s rights under its
unitholder rights agreement (described below), as well as (ii) vote on substantially all other matters on which our Class A
holders are entitled to vote. The holders of our Class A Common Units are not entitled to vote in the election of directors, but
they are entitled to vote in a very limited number of other circumstances, including our merger with another company. As is
common with MLPs, our partnership structure does not grant our unitholders (in such capacity) the right to directly or
indirectly participate in our management or operations other than through the exercise of their limited voting rights.
Collectively, members of the Davison family own approximately 10.1% of our Class A Common Units and 76.9% of
our Class B Common Units, for a combined ownership percentage of 10.2% of total Common Units. Pursuant to its unitholder
rights agreement, the Davison family is entitled to elect up to three of our directors based on its members’ collective ownership
percentage of our outstanding common units: (i) with 15% or more ownership, they have the right to appoint three directors,
(ii) with less than 15% ownership but more than 10%, they have the right to appoint two directors, and (iii) with less than 10%
ownership, they have the right to appoint one director. That unitholder rights agreement also provides that, so long as the
Davison family has the right to elect three directors thereunder, our board of directors cannot have more than 11 directors
without the Davison family’s consent. In addition to their rights under that unitholder rights agreement, if the members of the
Davison family act as a group, they have the ability to elect at least a majority of our directors because they own a majority of
our Class B units.
Under our limited partnership agreement, the organizational documents of our general partner and indemnification
agreements with our directors, subject to specified limitations, we will indemnify to the fullest extent permitted by Delaware
law, from and against all losses, claims, damages or similar events, any director or officer, or while serving as director or
officer, any person who is or was serving as a tax matters member or as a director, officer, tax matters member, employee,
partner, manager, fiduciary or trustee of our partnership or any of our affiliates. Additionally, we will indemnify to the fullest
extent permitted by law, from and against all losses, claims, damages or similar events, any person who is or was an employee
(other than an officer) or agent of our general partner.
Our board of directors currently consists of Sharilyn S. Gasaway, James E. Davison, James E. Davison, Jr., Kenneth
M. Jastrow II, Conrad P. Albert, Jack T. Taylor and Mr. Sims. Our board of directors has determined that each of Ms. Gasaway
and Messrs. Jastrow, Albert and Taylor is an independent director under the NYSE rules.
Board Leadership Structure and Risk Oversight
Board Leadership Structure
Our board of directors has no policy that requires the positions of the Chairman of the Board and the Chief Executive
Officer to be held by the same or different persons or that we designate a lead or presiding independent director. Our board of
directors believes it is important to retain the flexibility to make those determinations based on an assessment of the
circumstances existing from time to time, including the composition, skills and experience of our board of directors and its
members, specific challenges faced by the company or the industry in which it operates, and governance efficiency.
Presently, our board of directors believes that, because Mr. Sims is the director most familiar with our business and
industry and the most capable of leading the discussion of, and executing on, our business strategy, he is best situated to serve
as Chairman, regardless of the fact that he is the Chief Executive Officer of our general partner. Our board of directors also
believes that the appointment of a lead independent director, who will preside over executive sessions of non-management
directors of our board of directors, will facilitate teamwork and communication between the non-management directors and
85
management. Our board of directors appointed Mr. Jastrow as our lead independent director because of his executive
experience and service as a director of other companies. Our board of directors believes that the combined role of Chairman
and Chief Executive Officer working with the lead independent director is currently in the best interest of unitholders,
providing the appropriate balance between developing our strategy and overseeing management.
On September 1, 2017, we sold $750 million of Class A convertible preferred units in a private placement, comprised
of 22,249,494 units for a cash purchase price per unit of $33.71 (subject to certain adjustments, the “Issue Price”) to two initial
purchasers. In connection with the private placement, we have granted each initial purchaser (including its applicable affiliate
transferees) certain rights, including (i) the right to appoint an observer, who shall have the right to attend our board meetings
for so long as an initial purchaser (including its affiliates) owns at least $200 million of our preferred units and (ii) the right to
appoint two directors to our general partner’s board of directors if (and so long as) we fail to pay in full any three quarterly
distribution amounts, whether or not consecutive, attributable to any quarter ending after March 1, 2019.
We are committed to sound principles of governance. Such principles are critical for us to achieve our performance
goals and maintain the trust and confidence of investors, personnel, suppliers, business partners and stakeholders. We believe
independent directors are a key element for strong governance, although we have reserved or exercised our right as a limited
partnership under the listing standards of the NYSE not to comply with certain requirements of the NYSE. For example,
although at least a majority of the members of our board of directors is independent under the NYSE rules, we reserve the right
not to comply with Section 303A.01 of the NYSE Listed Company Manual in the future, which would require that our board of
directors be comprised of at least a majority of independent directors. In addition, among other things, we have elected not to
comply with Sections 303A.04 and 303A.05 of the NYSE Listed Company Manual, which would require our board of directors
to maintain a nominating/corporate governance committee and a compensation committee, each consisting entirely of
independent directors. Our corporate governance guidelines are available on our website (www.genesisenergy.com) free of
charge. For further discussion of director independence, please see Item 13. "Certain Relationships and Related Transactions,
and Director Independence—Director Independence."
Risk Oversight
We face a number of risks, including exposure to matters relating to the environment, regulation, competition,
fluctuations in commodity prices and interest rates and severe weather. Management is responsible for the day-to-day
management of the risks our company faces, although our board of directors, as a whole and through its committees, has
responsibility for the oversight of risk management. In fulfilling its risk oversight role, our board of directors must determine
whether risk management processes designed and implemented by our management are adequate and functioning as designed.
Senior management regularly delivers presentations to our board of directors on strategic matters, operations, risk management
and other matters, and are available to address any questions or concerns raised by our board of directors. Board of directors
meetings also regularly include discussions with senior management regarding strategies, key challenges and risks and
opportunities for our company.
Our board committees assist our board of directors in fulfilling its oversight responsibilities in certain areas of risk.
For example, the audit committee assists with risk management oversight in the areas of financial reporting, internal controls
and compliance with legal and regulatory requirements and our risk management policy relating to our hedging program. The
governance, compensation and business development committee assists our board of directors with risk management relating to
our compensation policies and programs.
Our board of directors believes that it is important to align (when practical) the interests of the members of our board
of directors and certain of our officers with the interests of our long-term stakeholders. Our board of directors has adopted
certain policies to further promote that alignment of interests. For example, among other things, our policies prohibit our
directors and officers from (i) buying, selling or engaging in transactions with respect to our common units while they are
aware of material non-public information and (ii) engaging in short sales of our securities. Certain of our directors and/or
officers own substantial amounts of our units, some of which are pledged, including being held in broker margin accounts. See
Item 12. "Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters."
Audit Committee
The audit committee of our board of directors generally oversees our accounting policies and financial reporting and
the audit of our financial statements. The audit committee assists our board of directors in its oversight of the quality and
integrity of our financial statements and our compliance with legal and regulatory requirements. Our independent registered
public accounting firm is given unrestricted access to the audit committee. Our board of directors has determined that the
members of the audit committee meet the independence and experience standards established by NYSE and the Securities
Exchange Act of 1934, as amended. In accordance with the NYSE rules and the Securities Exchange Act of 1934, as amended,
our board of directors has named three of its members to serve on the audit committee—Sharilyn S. Gasaway, Conrad P. Albert
and Jack T. Taylor. Ms. Gasaway is the chairperson. Our board of directors believes that Ms. Gasaway and Mr. Taylor qualify
86
as audit committee financial experts as such term is used in the rules and regulations of the SEC. The charter of the audit
committee is available on our website (www.genesisenergy.com) free of charge. Each member of the audit committee is an
independent director under NYSE rules.
Governance, Compensation and Business Development Committee
The governance, compensation and business development committee, or G&C Committee, of our board of directors
generally (i) monitors compliance with corporate governance guidelines, (ii) reviews and makes recommendations regarding
board and committee composition, structure, size, compensation and related matters, and (iii) oversees compensation plans and
compensation decisions for our employees. All the members of our board of directors, other than our CEO, serve as members
of the G&C Committee. Mr. Jastrow is the chairperson. The charter of the G&C Committee is available on our website
(www.genesisenergy.com) free of charge.
Conflicts Committee
To the extent requested by our board of directors, a conflicts committee of our board of directors would be appointed
to review specific matters in connection with the resolution of conflicts of interest and potential conflicts of interest between
any of our affiliates and us. If a specific review is requested by our board of directors, our conflicts committee would be formed
by our Board and would be comprised solely of independent directors. See Item 13. “Certain Relationships and Related
Transactions, and Director Independence—Review or Special Approval of Material Transactions with Related Persons.”
Executive Sessions of Non-Management Directors
Our board of directors holds executive sessions in which non-management directors meet without any members of
management present in connection with regular board meetings. The purpose of these executive sessions is to promote open
and candid discussion among the non-management directors. Mr. Jastrow, as the lead independent director, serves as the
presiding director at those executive sessions. In accordance with NYSE rules, interested parties can communicate directly with
non-management directors by mail in care of the General Counsel and Secretary or in care of the chairperson of the audit
committee at 919 Milam, Suite 2100, Houston, TX 77002. Such communications should specify the intended recipient or
recipients. Commercial solicitations or communications will not be forwarded. We have established a toll-free, confidential
telephone hotline so that interested parties may communicate with the chairperson of the audit committee or with all the non-
management directors as a group. All calls to this hotline are reported to the chairperson of the audit committee who is
responsible for communicating any necessary information to the other non-management directors. The number of our
confidential hotline is (800) 826-6762.
Directors and Executive Officers
Set forth below is certain information concerning our directors and executive officers, effective as of February 26,
2018.
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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
62
71
80
51
49
70
66
63
59
42
59
48
57
63
54
34
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
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 is a director of one other public company,
WildHorse Resources Development Corporation. 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
Origin Bancorp, Inc. and serves on its nominating and corporate governance, finance, and compensation 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. She served as Controller of Alltel Corporation from
2002 through 2006. Ms. Gasaway is a director of two other public companies, JB Hunt Transport Services, Inc. and Waddell
and Reed Financial, Inc., serving on the audit committee of each company. Additionally, Ms. Gasaway serves on the
compensation and nominating committees of JB Hunt and the nominating and corporate governance committee of Waddell and
Reed. Ms. Gasaway provides our board of directors valuable management and financial expertise, including an understanding
of the accounting 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
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and Chief Financial Officer. Mr. Jastrow is also a director and serves on the compensation committee of KB Home and MGIC
Investment Corporation. Mr. Jastrow formerly served as Non-Executive Chairman of Forestar Group, Inc. Mr. Jastrow’s
executive experience and service as director of other companies enable him to make valuable contributions to our board of
directors and particularly well suited to be the lead independent director.
Jack T. Taylor has served as a director of our general partner since July 2013. Mr. Taylor is currently a director of
Sempra Energy and Murphy USA Inc. Additionally, Mr. Taylor currently serves on the audit committee of Sempra Energy and
Murphy USA Inc. Mr. Taylor was a partner of KPMG LLP for 29 years, where from 2005 to 2010 he served as KPMG's Chief
Operating Officer-Americas and Executive Vice Chair of U.S. Operations and from 2001 to 2005 he served as the Vice
Chairman of U.S. Audit and Risk Advisory Services. Mr. Taylor’s extensive experience with financial and public accounting
issues, his various leadership roles at KPMG LLP and his extensive knowledge of the energy industry make him a valuable
resource to our board of directors.
Robert V. Deere has served as Chief Financial Officer of our general partner since October 2008. Mr. Deere served as
Vice President, Accounting and Reporting at Royal Dutch Shell (Shell) from 2003 through 2008.
Edward T. Flynn has served as Executive Vice President of our general partner and President, Genesis Alkali since we
acquired that business from Tronox Ltd. in September 2017 (where he also previously served as Executive Vice President).
Prior to joining Tronox, Mr. Flynn served as President FMC Minerals. He was previously President of FMC’s Industrial
Chemicals Group. Mr. Flynn is a member of the Board of Directors for ANSAC and a member of the Board of Directors of the
Industrial Minerals Association of North America (IMA-NA).
Richard R. Alexander has served as Vice President of our general partner since November 2014. Mr. Alexander is
responsible for the commercial aspects of our marine transportation segment. Since 2008, Mr. Alexander has served in various
capacities within our marine operations.
Karen N. Pape has served as Senior Vice President and Controller of our general partner since July 2007 and served as
Vice President and Controller from May 2002 until July 2007.
Kristen O. Jesulaitis has served as an executive officer of our general partner since January 2017. Ms. Jesulaitis has
served as our General Counsel since July 2011. She is responsible for all legal functions of Genesis, including acquisitions and
commercial transactions, compliance and regulatory affairs, corporate governance, securities, and finance. Prior to joining
Genesis, Ms. Jesulaitis was a partner at the law firm Akin Gump Strauss Hauer & Feld LLP principally engaged in the areas of
corporate and securities law, with primary focus in the midstream energy sector.
William S. Goloway has served as Vice President of our general partner since January 2017. Mr. Goloway has been
responsible for the commercial aspects of our offshore Gulf of Mexico assets from the time we acquired these offshore assets
from Enterprise Products in 2015. Prior to this acquisition, Mr. Goloway served in various roles within the offshore group at
Enterprise Products since 2005.
Garland G. Gaspard has served as Senior Vice President of our general partner since January 2017 and is responsible
for the operational aspects of our onshore and offshore pipelines, rail facilities, terminals, offshore facilities and assets,
engineering, trucking and health, safety, security and environmental compliance. Mr. Gaspard joined Genesis in 2015 as a
result of our acquisition of the offshore Gulf of Mexico assets from Enterprise Products and has had responsibility for the
operational aspects of our offshore assets since that time. Prior to this acquisition, Mr. Gaspard served in various capacities
within Enterprise Products' operations including underground gas storage, natural gas liquids, natural gas pipelines and offshore
operations.
Chad A. Landry has served as Vice President of our general partner since January 2017. Mr. Landry joined Genesis in
2013 and since that time has been responsible for all operational and commercial aspects of our sodium minerals and sulfur
services segment. Prior to joining Genesis, he spent 14 years at Axiall Corporation (Georgia Gulf), most recently as Vice
President - Chlor-Alkali & Vinyls.
Ryan S. Sims has served as Vice President of our general partner since January 2017. Mr. Sims joined Genesis in
2011 and is responsible for our finance, planning and corporate development 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.
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
89
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.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires our officers and directors of our general partner and
persons who own more than ten percent of a registered class of our equity securities to file reports of ownership and changes in
ownership with the SEC and the NYSE. Based solely on our review of the copies of such reports received by us, or written
representations from certain reporting persons to us, we are aware of no filings that were not timely made, except for the
following: Messrs. Goloway, Gaspard, Sims and Ms. Pape and Ms. Jesulaitis each filed a Form 4 on May 16, 2017 for the
issuance of phantom units on April, 11, 2017. In addition, Mr. Flynn filed a Form 3 on September 12, 2017 for the purchase of
common units on September 1, 2017.
Item 11. Executive Compensation
The Compensation Discussion and Analysis below discusses our compensation process, objectives and philosophy
with respect to our Named Executive Officers (“NEOs”), for the fiscal year ended December 31, 2017.
Compensation Discussion and Analysis
Named Executive Officers
Our NEOs for 2017 were:
•
•
•
•
•
Grant E. Sims, Chief Executive Officer;
Robert V. Deere, Chief Financial Officer;
Stephen M. Smith, Formerly Vice President;
Richard R. Alexander, Vice President;
Chad A. Landry, Vice President.
Board and Governance, Compensation and Business Development Committee
Our board of directors is responsible for, and effectively determines, compensation programs applicable to our NEOs
and to the board itself. Our board of directors has delegated to the G&C Committee, of which a majority of the members are
"independent," according to NYSE listing standards, the authority and responsibility to regularly analyze and evaluate our
compensation policies, to determine the annual compensation of our NEOs, and to make recommendations to our board of
directors with respect to such matters. As described in more detail below, the G&C Committee engaged BDO USA, LLP, or
BDO, as its independent compensation adviser. We also utilize committees comprised solely of certain of our independent
directors (i.e., the audit committee or special committees) to review and make recommendations with respect to certain
matters such as obtaining exemptions from the “insider trading” rules under Section 16 of the Exchange Act in connection
with certain acquisitions. Because the G&C Committee is comprised of all the members of our board of directors, excluding
our CEO, determinations and recommendations by the G&C Committee are effectively determinations by our board of
directors, which has approval authority for all such compensation matters. For a more detailed discussion regarding the
purposes and composition of board committees, please see Item 10. “Directors, Executive Officers and Corporate
Governance.”
Committee/Board Process
Following the end of each calendar year, our CEO reviews the compensation of all the other NEOs and makes a
proposal to the G&C Committee regarding their compensation. The CEO's proposal is based on (among other things) our
financial results for the prior year, the relevant executive’s areas of responsibility, market data provided by our independent
compensation adviser and recommendations from the relevant executive’s supervisor (if other than our CEO). The G&C
Committee reviews the compensation of our CEO and the proposal of our CEO regarding the compensation of the other NEOs
and makes a final determination (and a recommendation to our board of directors) regarding the compensation of our NEOs.
Depending on the nature and quantity of changes made to that proposal, there may be additional G&C Committee meetings
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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
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 the Committee 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 2017, the G&C Committee engaged BDO,
an independent compensation consultant, to assist the Committee in assessing and structuring competitive compensation
packages for the executive officers that are consistent with our compensation philosophy. The G&C Committee assessed the
independence of BDO pursuant to current exchange listing requirements and SEC guidance and concluded that no conflict of
interest exists that would prevent BDO from serving as an independent consultant to the G&C Committee.
At the request of the G&C Committee, BDO reviewed and provided input on the compensation of our NEOs, trends
in executive compensation, meeting materials circulated to the G&C Committee, and management’s recommendations
regarding executive compensation plans. BDO also developed assessments of market levels of compensation through an
analysis of peer data and information disclosed in our peer companies’ public filings, but did not determine or recommend the
amount of compensation.
The peer group used for this market analysis in 2017 consisted of the following 15 companies in the energy industry:
Buckeye Partners, Calumet Specialty Products Partners, Plains All American Pipeline, Enlink Midstream Partners, DCP
Midstream, HollyFrontier Corporation, Magellan Midstream Partners, Delek US Holdings, NuStar Energy, NGL Energy
Partners, Sunoco Logistics Partners, Targa Resources Partners, Spectra Energy Partners, Western Refining and Summit
Midstream Partners. 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 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 2017 peer group remains the same as the 2016
group.
The information that BDO compiled included compensation trends for MLPs and levels of compensation for
similarly-situated executive officers of companies within this peer group. We believe that compensation levels of executive
officers in our peer group are relevant to our compensation decisions because we compete with those companies for executive
management talent.
Compensation Objectives and Philosophy
The primary objectives of our compensation program are to:
• encourage our executives to build and operate the partnership in a way that is aligned with our common
unitholders’ interests, focusing on growing total unitholder returns and growing the asset base with an emphasis
on maintaining a focus on the long-term stability of the enterprise so as to not promote inappropriate risk taking;
• offer near-term and long-term compensation opportunities that are consistent with industry norms; and
• provide appropriate levels of retention to the executive team to ensure long-term continuity and stability for the
successful execution of key growth initiatives and projects.
We strive to accomplish these objectives by providing all employees, including our NEOs, with a total compensation
package that is market competitive and performance-based. In our assessment of the market competitiveness of compensation,
we take into consideration the compensation offered by companies in our peer group described above, but we have not
identified a specific percentile of peer company pay as a target. Rather, we use market information as one consideration in
setting compensation along with individual performance, our financial and operational performance and our safety
performance.
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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
incentive plans provide an appropriate balance of short and long-term incentives, cash and non-cash based compensation and
alignment of the incentives for our executives, including our NEOs, with the interests of our common unitholders.
The amount of compensation contingent on performance is a significant percentage of total compensation, therefore
ensuring 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 (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 linked primarily to increases in the distribution rate on our common units and appreciation in our
common unit price.
Elements of Our Compensation Program and Compensation Decisions for 2017
The primary elements of our compensation program are a combination of annual cash and long-term equity-based
incentive compensation. For the year ended December 31, 2017, the elements of our compensation program for the NEOs
consisted of the following:
•
•
•
annual base salary
discretionary annual cash and bonus awards
annual grants under long-term incentive arrangements
Additionally, in order to attract qualified executive personnel, we may make one-time new-hire awards of equity.
Base Salaries
We believe that base salaries should provide a fixed level of competitive pay that reflects the executive officer’s
primary duties and responsibilities, and which provides a foundation for incentive opportunities and benefit levels. As
discussed above, the base salaries of our NEOs are reviewed annually by the G&C Committee, taking into account
recommendations from our CEO regarding NEOs other than himself. We pay base salaries at a level that we feel is appropriate
for the skills and qualities of the individual NEOs based on their past performance, current scope of responsibilities and future
potential. Base salaries may be adjusted to achieve what is determined to be a reasonably competitive level or to reflect
promotions, the assignment of additional responsibilities, individual performance or company performance. Salaries are also
periodically adjusted based on analysis of peer group practices as described above.
In April 2017, the G&C Committee reviewed the assessments of market levels of compensation developed by BDO
in conjunction with a discussion of individual performance and responsibilities. As a result of and taking into account current
market conditions, the base salaries of Messrs. Sims, Deere, Smith and Alexander were not increased from 2016 and remained
unchanged in the amounts of $600,000, $450,000, $325,000 and $325,000 respectively. The base salary of Mr. Landry was
increased to $312,500, representing an increase from 2016 of 4%.
Bonuses
Our NEOs typically participate in a bonus program, or the Bonus Plan, in which substantially all company employees
participate. As designed by the G&C Committee, each NEO has an annual bonus target based on a stated percentage of his
base salary. The targeted amount for the NEOs is established based on the analysis of market practices of the peer group and
consideration of the level of salary and targeted long-term incentives for each NEO. Based on the G&C Committee's
subjective review of 2017 operational and financial performance, in the context of total NEO compensation, no performance-
based awards were earned by NEOs and it was determined by the G&C Committee that each NEO would instead be
considered for a retention bonus for 2017, 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 2017, Messrs. Smith, Alexander and Landry were granted retention bonuses of $150,000,
$400,000 and $275,000 respectively, to be paid in installments in October 2017, October 2018 and October 2019 contingent
upon continued employment at those dates. Mr. Smith has since foregone his retention bonus given his January 10, 2018
resignation. In addition, Messrs. Alexander and Landry were granted 2017 discretionary bonuses of $60,000 and $80,000
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respectively, in recognition of their leadership of their respective areas of responsibility and their individual contribution to the
company’s continued performance. These bonuses will be paid in March 2018, contingent upon their continued employment
at that date. 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 provide equity-based, long-term compensation for our officers, directors and certain employees through our 2010
Long-Term Incentive Plan, or the 2010 LTIP. The 2010 LTIP is designed to promote a sense of proprietorship and personal
involvement in our development and financial success among our employees and directors through awards of phantom units
and distribution equivalent rights, or DERs. The 2010 LTIP also allows for providing flexible incentives to employees and
directors. Prior to vesting or termination of the applicable restricted period, our officers cannot transfer (including sell, pledge
or hedge) any of their LTIP Awards.
All long-term objectives for payments to participants in the 2010 LTIP are based upon measurable performance
targets. These targets are based on specific increases in the distributions paid to unitholders. As a result, we believe that the
2010 Long-Term Incentive Plan strongly aligns the interests of management with those of our unitholders.
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.
The G&C Committee administers the 2010 LTIP, and has the authority to determine the terms and conditions of any
awards granted under the 2010 LTIP and to adopt, alter and repeal rules, guidelines and practices relating to the 2010 LTIP.
The G&C Committee has full discretion to administer and interpret the 2010 LTIP and to establish such rules and regulations
as it deems appropriate and to determine, among other things, the time or times at which the awards may be exercised and
whether and under what circumstances an award may be exercised. The G&C Committee designates participants in the 2010
LTIP, determines the types of awards to grant to participants and determines the number of units to be covered by any award.
Our board of directors can terminate the 2010 LTIP at any time.
Targeted grant values for the NEOs are established based on the analysis of market practices of the peer group and
consideration of the level of salary and targeted bonus for each NEO. For 2017, the G&C Committee established the following
long-term incentive target grant values for each of our NEOs:
Name
Grant E. Sims
Robert V. Deere
Stephen M. Smith
Richard R. Alexander
Chad A. Landry
2017
Long-Term Incentive Target
Grant Value
$
$
$
$
$
600,000
450,000
400,000
750,000
315,000
In April 2017, phantom units were granted to each of our NEOs and certain employees under the 2010 LTIP. The
number of units granted was determined by dividing the closing market price of our common units on the date of grant by the
long-term incentive target amount. The 2017 LTIP awards will vest on the third anniversary of issuance, contingent on
continued employment at those dates, and th phantom units will be paid in cash upon vesting based on the average closing
price of the common units for the 20 trading days immediately prior to the date of vesting. The phantom units granted to our
NEOs in April 2017 were all performance-based awards, with the exception of Mr. Landry whose awards were 60%
performance based and 40% service based awards. For the minimum, target and maximum number of units awarded to our
NEO’s for 2017, please refer to the table below entitled “Grants of Plan-Based Awards for Fiscal Year 2017.
For 2017, the performance-based LTIP awards granted to our NEOs and certain other employees will vest as follows:
(i) if the quarterly cash distribution on the common units for the fourth quarter of 2019 is $0.75 per unit, 50% of the
target number of phantom units granted will vest, and the remainder will be forfeited;
(ii) if the quarterly cash distribution on the common units is $0.80 per unit, 100% of the target number of phantom
units granted will vest; or
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(iii) if the quarterly cash distribution on the common units is $0.85 per unit or greater, 150% of the target number of
phantom units granted will vest.
If the quarterly cash distribution on the common units falls between the above ranges of $0.75 per unit and $0.85 per
unit, the phantom units will vest on a proportionately adjusted basis (for example, if the quarterly cash distribution on the
common units is $0.775 per unit, 75% of the phantom units targeted will vest or if the quarterly cash distribution on the
common units is $0.825 per unit, 125% of the phantom units targeted will vest). If the quarterly cash distribution is below
$0.75 per unit for the fourth quarter of 2019, all of the performance-based phantom units granted will be forfeited.
The phantom units also include distribution equivalent rights, or DERs, which are granted in tandem with all
phantom units. DERs on all performance-based awards to our NEOs are paid quarterly based on the number of units
corresponding to the number of units in the initial grant.
In October 2017, our management completed a strategic review and analysis of our capital allocation program and
decided that, due to dramatic changes in how the market values MLP units, it was in the best long-term interest of our
unitholders to further strengthen our balance sheet and enhance our financial flexibility. Management, then, implemented a
strategy to re-allocate capital by, among other things, resetting our quarterly distribution rate per unit to $0.50 (from $0.71),
with a visible path to sustainable quarterly distribution increases thereafter. See Item 7 for a more detailed discussion. That
distribution reset immediately resulted in all outstanding LTIP performance based awards effectively becoming worthless
given the high unlikelihood of achieving the minimum quarterly cash distribution targets required for vesting. As a result,
management and the G&C committee, in light of changes in how the market values MLP units, are evaluating changes in the
long-term compensation program to more fully align the interests of the program’s participants and those of the unitholders.
As a retention device for our current NEOs and other key employees, the G&C Committee implemented for 2017 a special
retention program, which is designed to incentivize and retain certain of our key performers so that we maintain the benefit of
their leadership going forward. Messrs. Sims, Deere, Alexander, and Landry were granted $1,400,000, $450,000, $400,000,
and $240,000 respectively under this program. These awards will be paid in April 2018, contingent upon their continued
employment at that date.
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
Because we are a partnership and not a corporation for federal income tax purposes, we are not subject to the
limitations of Internal Revenue Code Section 162(m) with respect to tax-deductible executive compensation. However, if such
tax laws related to executive compensation change in the future, the G&C Committee will consider the implication of such
changes to us.
For our equity-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
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.
94
Compensation Risk Assessment
Our board of directors does not believe that our compensation policies and practices for employees are reasonably
likely to have a material adverse effect on us. We compensate all employees with a combination of competitive base salary
and incentive compensation. Our board of directors believes that the mix and design of the elements of employee
compensation do not encourage employees to assume excessive or inappropriate risk taking.
Our board of directors concluded that the following risk oversight and compensation design features guard against
excessive risk-taking:
•
•
•
•
•
•
•
the company has strong internal financial controls;
base salaries are consistent with employees’ responsibilities so that they are not motivated to take excessive
risks to achieve a reasonable level of financial security;
the determination of incentive awards is based on a review of a variety of indicators of performance as well
as a meaningful subjective assessment of personal performance, thus diversifying the risk associated with
any single indicator of performance;
goals are appropriately set to avoid targets that, if not achieved, result in a large percentage loss of
compensation;
incentive awards are capped by the G&C Committee;
compensation decisions include discretionary authority to adjust annual awards and payments, which further
reduces any business risk associated with our plans; and
long-term incentive awards are designed to provide appropriate awards for dedication to a corporate strategy
that delivers long-term returns to unitholders.
Summary Compensation Table
The following Summary Compensation Table summarizes the total compensation paid or accrued to our NEOs in
2017, 2016 and 2015.
Name & Principal Position
Grant E. Sims
Chief Executive Officer
(Principal Executive Officer)
Robert V. Deere
Chief Financial Officer
(Principal Financial Officer)
Stephen M. Smith (1)
formerly Vice President
Richard R. Alexander
Vice President
Chad A. Landry
Vice President
Year
2017
2016
2015
2017
2016
2015
2017
2016
2015
2017
2016
2015
2017
2016
2015
Salary ($)
Bonus ($) (2)
Stock
Awards ($) (3)
All Other
Compensation ($) (4)
Total ($)
$ 600,000
$ 1,400,000
$
593,428
$
309,287
$ 2,902,715
600,000
576,923
450,000
450,000
450,000
325,000
325,000
317,308
325,000
325,000
317,308
312,500
300,000
300,000
— 1,744,069
— 1,755,771
450,000
445,063
— 1,017,376
—
67,500
—
225,000
640,000
—
300,000
443,750
157,500
295,000
658,448
395,619
581,367
438,966
741,761
726,693
585,287
311,560
290,683
292,644
274,531
190,851
187,018
162,940
108,449
133,439
117,999
2,618,600
2,523,545
1,532,081
1,630,316
1,216,897
921,558
1,024,366
85,268
1,066,542
212,304
154,883
112,299
85,770
47,811
37,342
1,919,065
1,206,576
1,314,894
1,153,580
795,994
924,986
(1) Mr. Smith resigned his position effective January 10, 2018.
(2) The amounts shown represent any retention bonuses vested and paid during 2017, as well as any cash or retention bonuses or
special retention program awards earned relative to 2017 but paid subsequent to December 31, 2017.
(3) The amounts shown in this column represent the aggregate grant date fair value for each NEO’s phantom units granted under our
2010 Long-Term Incentive Plan. The grant date fair value of each award was determined in accordance with accounting guidance
for equity-based compensation and is based on the probable outcome of any underlying performance conditions. Assumptions
used in the calculation of these amounts are included in Note 16 to our Consolidated Financial Statements in Item 8.
(4) The following table presents the components of "All Other Compensation" for each NEO for the year ended December 31, 2017.
95
Name
Grant E. Sims
Robert V. Deere
Stephen M. Smith
Richard R. Alexander
Chad A. Landry
401(k) Matching
and Profit
Sharing
Contributions (a)
Insurance
Premiums
(b)
Other
Compensation
(c)
$
$
$
$
$
13,500
27,000
27,000
29,700
26,997
$
$
$
$
$
1,458
1,458
1,458
1,458
1,458
$
$
$
$
$
294,329
158,560
104,981
181,146
57,315
$
$
$
$
$
Totals
309,287
187,018
133,439
212,304
85,770
The amounts in this table represent:
(a) Contributions by us to our 401(k) plan on each NEO’s behalf.
(b) Term life insurance premiums paid by us on each NEO’s behalf.
(c) This column includes cash distributions paid in connection with granted DERs.
Grants of Plan-Based Awards in Fiscal Year 2017
The following table shows equity incentive plan awards granted to our NEOs in 2017.
Estimated Future Payouts Under
Equity Incentive Plan Awards (1)
Name
Grant Date
Threshold
Target
Maximum
Market Price of
Common Units on
Award Date (2)
Grant Date Fair
Value of Stock
and Option
Awards (3)
Grant E. Sims
Robert V. Deere
Stephen M. Smith
Richard R. Alexander
Chad A. Landry
4/11/2017
4/11/2017
4/11/2017
4/11/2017
4/11/2017
9,164
6,873
6,109
11,454
6,735
18,327
13,745
12,218
22,908
9,622
27,491
20,618
18,327
34,362
12,509
$
$
$
$
$
32.74
32.74
32.74
32.74
32.74
$
$
$
$
$
593,428
445,063
395,619
741,761
311,560
(1) Represents the number of phantom units that each NEO can earn of grant awarded on April 11, 2017, if the company meets certain
performance conditions (threshold, target and maximum) during the fourth quarter of 2019. See additional discussion in "Long-
Term Incentive Compensation" above.
(2) Represents the closing market price of our common units on the date of the phantom unit award on April 11, 2017.
(3) The amounts in this column for each NEO represent the fair value of the award on the date of the grant (as computed in
accordance with accounting guidance for equity-based compensation) assuming no forfeitures and using the twenty day average
closing price of our common units through the date of grant ($32.38) multiplied by the target number of units awarded.
Employment Agreements
Richard R. Alexander
Mr. Alexander entered into an employment agreement in July 2008 relating to his employment and providing for a
base salary which is subject to discretionary upward adjustments. Currently, the annual base salary of Mr. Alexander is
$325,000. That agreement provides that Mr. Alexander is eligible to participate in all other benefit programs (e.g. health,
dental, disability, life and/or other insurance plans) for which executive officers are generally eligible and severance benefits
as disclosed in "Potential Payments upon Termination or Change of Control" below.
96
Outstanding Equity Awards at December 31, 2017
The following table presents the information regarding the outstanding equity awards to our NEOs at December 31,
2017.
Stock Awards
Name
Grant Date
Equity Incentive
Plan Awards:
Number of Unearned
Phantom Units That
Have Not Vested (#)
(1)
Equity Incentive
Plan Awards: Market
Value of Unearned
Phantom Units That
Have Not Vested ($)
(2)
Grant E. Sims
Robert V. Deere
Stephen M. Smith (4)
Richard R. Alexander
Chad A. Landry (3)
4/11/2017
4/12/2016
4/14/2015
4/11/2017
4/12/2016
4/14/2015
4/11/2017
4/12/2016
4/14/2015
4/11/2017
4/12/2016
4/14/2015
4/11/2017
4/12/2016
4/14/2015
27,491 $
85,634 $
57,705 $
20,618 $
49,953 $
21,641 $
18,327 $
28,545 $
14,427 $
34,362 $
35,681 $
19,236 $
12,509 $
12,370 $
8,336 $
616,623
1,920,771
1,294,323
462,462
1,120,446
485,408
411,075
640,264
323,598
770,740
800,325
431,463
280,577
277,459
186,976
(1) The number of performance units reflected in the table assumes a maximum performance payout based upon past achievement
levels from the previous vesting period. Service based units held by Mr. Landry do not specify threshold, target and maximum
payouts levels. For additional information regarding Mr. Landry's units, please see note 3 below.
(2) The amounts in this column were calculated by multiplying the closing market price of our units using the twenty day average at
year-end by the number of applicable units outstanding.
(3) Phantom units outstanding for Mr. Landry include 2,565, 3,806 and 3,848 service based units for 2015, 2016 and 2017
respectively. The remainder of the outstanding units held by Mr. Landry and represented above are performance based units.
(4) Mr. Smith resigned his position effective January 10, 2018 and thus forfeited all of the outstanding units above at that time.
97
Phantom Units Vested
The following table presents the information regarding the vesting of phantom units during the year ended
December 31, 2017 with respect to our NEOs.
Name
Grant E. Sims
Robert V. Deere
Stephen M. Smith
Richard R. Alexander
Chad A. Landry
Phantom Unit Awards
Number of Phantom Units
Vested (#)
Value Realized on Vesting ($)
11,111
11,111
11,111
7,222
6,018
$
$
$
$
$
361,313
361,313
361,313
234,843
195,685
The phantom unit awards granted to our NEOs in 2014 vested on April 8, 2017 and, pursuant to our 2010 Long Term
Incentive Plan, the value realized upon vesting was computed by multiplying the average closing price of our common units
for the 20 trading days immediately prior to the date of vesting by the number of units that vested. We achieved the maximum
target for 2014 award grants of a quarterly distribution to common unitholders of $0.70 per unit; therefore the number of
phantom units vested in the table above represents 150% of the initial award. Those phantom unit awards were paid in cash.
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. The employment agreement for Mr. Alexander
provides certain compensation and benefits as an incentive to remain in our employ, enhancing our ability to call on and rely
upon him in the event of a change of control. Mr. Alexander would not be entitled to severance benefits if terminated for
cause. In extending these benefits, we considered a number of factors, including the prevalence of similar benefits adopted by
other publicly traded MLPs. See “Potential Payments Upon Termination or Change of Control” below for further discussion of
these benefits, including the definitions of certain terms such as change of control and cause.
We believe that the interests of unitholders will best be served if the interests of our management and unitholders are
aligned. We believe the termination and change of control benefits described above strike an appropriate balance between the
potential compensation payable and the objectives described above.
Potential Payments upon Termination or Change of Control
Mr. Alexander is entitled under his employment agreement to specified severance benefits under certain
circumstances as discussed above.
Under a change of control and certain termination circumstances, each of our NEOs also will vest in any outstanding
awards under our 2010 LTIP. Under the 2010 LTIP, a change of control occurs upon, in general, any sale of substantially all of
the assets of us or our general partner or a merger, conversion, consolidation of us or our general partner or any other
transaction resulting in a change in the beneficial ownership of more than 50% of the voting equity interests in our general
partner.
If Mr. Alexander terminates his employment for good reason or we terminate his employment without cause, he
would be entitled to (i) company payment of his COBRA health benefits for 12 months and (ii) monthly payments of his
annual base salary due for the remainder of the renewal term of his employment agreement.
As used in Mr. Alexander’s employment agreement, the terms “cause”, “change of control”, “good reason” and
"renewal term" are generally described below:
•
“Cause” means, in general, if the executive commits theft, embezzlement, forgery, any other act of dishonesty
relating the executive’s employment or violates our policies or any law, rule, or regulation applicable to us, is
convicted of a felony or lesser crime having as its predicate element fraud, dishonesty, or misappropriation, fails
to perform his duties under the employment agreement or commits an act or intentionally fails to act, which act
or failure to act amounts to gross negligence or willful misconduct.
98
•
•
•
“Good Reason” means, in general, following a change of control which results in a substantial diminution of the
executive’s duties, compensation, or benefits; executive’s removal from position as Vice President (other than for
cause, death or disability, or being offered an equivalent position); or our failure to make any payment to the
executive required under the terms of his employment agreement.
“Change of control” means, in general, any sale of equity in us or our general partner or sale of substantially all
of our assets; any merger, conversion or consolidation of us or our general partner; or any other event that, in
each of the foregoing cases, results in any persons or entities having the ability to elect a majority of the
members of our board of directors (other than one or more of our executive officers or affiliates).
“Renewal term” means, in general, each one-year term of employment beginning on July 18 of each year, absent
either the Company or the executive giving the other party at least 90 days advance written notice of its intent
not to renew the employment agreement between them.
Based upon a hypothetical termination date of December 31, 2017, the termination benefits for Messrs. Sims, Deere,
Smith and Alexander for voluntary termination or termination for cause would be zero.
Based upon a hypothetical termination date of December 31, 2017, the termination benefits for Mr. Alexander for
termination without cause (other than as a result of death or disability) or for good reason would have been:
Severance pursuant to employment agreement
Healthcare
Total
Richard R. Alexander
325,000
$
24,039
349,039
$
If termination occurs due to death or disability, Messrs. Sims, Deere, Alexander and Landry would vest in
outstanding phantom unit awards under our 2010 LTIP. Utilizing the closing price of our common units for the twenty trading
days prior to December 31, 2017 would result in payments under the 2010 LTIP of the following amounts upon death or
disability:
Grant E. Sims
Robert V. Deere
Richard A. Alexander
Chad A. Landry
$
$
$
$
2,570,613
1,378,862
1,335,011
573,064
Based on a hypothetical simultaneous change of control and termination date of December 31, 2017, the change of
control termination benefits for Messrs. Sims, Deere, Alexander and Landry would have been as follows:
Severance pursuant to employment agreement
$
Healthcare
Grant E.
Sims
Robert V.
Deere
Richard R.
Alexander
Chad A.
Landry
— $
—
— $ 325,000
$
—
24,039
—
—
Cash payment for vested phantom units under 2010 LTIP
2,570,613
1,378,862
1,335,011
573,064
Total
$ 2,570,613
$ 1,378,862
$ 1,684,050
$ 573,064
Director Compensation in Fiscal Year 2017
The table below reflects compensation for our non-employee directors. Mr. Sims does not receive any compensation
attributable to his status as a director.
99
Name
James E. Davison
James E. Davison, Jr.
Sharilyn S. Gasaway
Kenneth M. Jastrow II
Corbin J. Robertson III (5)
Conrad P. Albert
Jack T. Taylor
Fees Earned or
Paid in Cash
($) (1)
Stock
Awards
($) (2) (3)
All Other
Compensation
($) (4)
$
$
$
$
$
$
$
80,000
80,000
107,000
92,500
60,000
96,500
97,000
$
$
$
$
$
$
$
100,000
100,000
112,500
112,500
75,000
102,500
102,500
$
$
$
$
$
$
$
20,222
20,222
22,750
22,750
19,745
20,728
20,728
$
$
$
$
$
$
$
Total
200,222
200,222
242,250
227,750
154,745
219,728
220,228
(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, 2017 consist of phantom units granted under our 2010 LTIP and stock
appreciation rights pursuant to our Stock Appreciation Rights Plan. Messrs. James Davison and James Davison, Jr. each hold
8,275 outstanding phantom units and 1,000 stock appreciation rights. Messrs. Jastrow, Albert, Taylor and Ms. Gasaway hold
9,308, 8,482, 8,482 and 9,308 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.
(5) Mr. Robertson resigned his position as a director in August 2017.
Directors who are not officers of our general partner are entitled to a base compensation of $180,000 per year, with
$80,000 paid in cash and $100,000 paid in phantom units. Cash is paid, and phantom units are awarded, on the first day of
each calendar quarter. The number of phantom units awarded is determined by dividing the closing market price of our units
on the date of the award into the amount to be paid in phantom units. So long as he or she is a director on the relevant date of
determination, each director will receive: (i) a quarterly distribution equal to the number of phantom units held by such
director multiplied by the quarterly distribution amount we will pay in respect of each of our outstanding common units on
such distribution date, and (ii) on the third anniversary of each award date for such director, an amount equal to the number of
phantom units granted to such director on such award date multiplied by the average closing price of our common units for the
20 trading days ending on the day immediately preceding such anniversary date.
The lead director and chairpersons of the audit committee and G&C Committee receive an additional amount of base
compensation split equally between cash and phantom units, which cash compensation is paid in equal quarterly installments.
Such additional amount is $10,000 for the lead director, $25,000 for the chair of the audit committee and $15,000 for the chair
of the G&C Committee.
In addition, each non-employee director receives additional cash compensation for each “Additional Meeting” (board
and/or committee) in which he or she participates. Participation by a director in-person will entitle her/him to additional
compensation of $2,500 per meeting, and participation by a director by means of telecommunication will entitle her/him to
additional compensation of $2,000 per meeting. Such payments are made in conjunction with the quarterly payments of base
compensation. Additional Meetings consist of (i) with respect to our board of directors any meetings (in-person or by
telecommunication) other than (x) the four pre-set meetings of our board of directors for each calendar year and (y) brief
follow-up telecommunication conferences relating to the Annual Report on Form 10-K or any Quarterly Report on Form 10-Q
the company files with the SEC, and (ii) any committee meeting.
Compensation Changes Subsequent to December 31, 2017
Mr. Smith, our Vice President responsible for our onshore facilities and transportation segment, resigned his position
effective January 10, 2018 for personal reasons. There were no disagreements between Mr. Smith and our management or board
of directors that influenced his decision to resign.
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 by examining the 2017 total cash compensation for all individuals, excluding our CEO, who
were employed by us on December 31, 2017. As of December 31, 2017, the company had 2,142 employees, including 2,118
full-time employees, and 24 part-time and seasonal employees. Consistent with Item 402(u), we have excluded from our
100
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, 2017, which is within the last three months of 2017, 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 2017. We believe the use of total cash
compensation for all employees is a consistently applied compensation measure because we do not widely distribute annual
equity awards to employees. Since all of our employees are located in the United States, including the Commonwealth of
Puerto Rico, and paid in U.S. dollars, we did not make any cost-of-living adjustments in identifying the median employee.
After identifying the median employee based on total cash compensation, we calculated the annual total compensation
for that employee using the same methodology we use for our named executive officers as set forth in the 2017 Summary
Compensation Table above in this 10-K filing. Mr. Sims, our CEO had 2017 annual total compensation of $2,902,715, as reflected
in the Summary Compensation Table. Our median employee’s annual total compensation for 2017 was $116,085. Based on this
information, Mr. Sims’ total annual compensation was approximately thirteen times that of our median employee in 2017 or 25:1.
101
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
Beneficial Ownership of Partnership Units
The following table sets forth certain information as of February 26, 2018, regarding the beneficial ownership of our
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 persons named.
Class A Common Units
Class B Common Units
Name and Address of Beneficial Owner
Amount and Nature of
Beneficial Ownership
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
(1)
(2)
(3)
5,000
3,476,282
5,323,932
279,445
50,000
12,865
*
2.8%
4.3%
*
*
*
3,000,000
(4)
2.4%
829,987
15,691
15,500
(5)
152,131
—
4,300
2,400
—
10,000
*
*
*
*
*
*
*
*
*
—
—
9,453
23.6%
13,648
34.1%
1,081
2.7%
—
—
7,087
1,052
—
—
17.7%
2.6%
—
—
—
—
—
—
—
—
All directors and executive officers as a group (16 in total)
13,177,533
10.7%
32,321
80.8%
Steven K. Davison
Salient Capital Advisors, LLC
Chickasaw Capital Management, LLC
Tortoise Capital Advisors, L.L.C
OppenheimerFunds, Inc.
Alerian MLP ETF
Clearbridge Investments, LLC
*
Less than 1%
1,980,339
(6)
6,359,030
10,353,825
4,969,012
15,839,475
8,885,681
9,868,337
1.6%
5.2%
8.4%
4.1%
12.9%
7.3%
8.1%
7,676
19.2%
—
(1) The Class B Common Units, which also are included in the Class A Common Unit total, are identical in most respects to the Class
A Common Units and have voting and distribution rights equivalent to those of the Class A Common Units. In addition, the Class
B Common Units have the right to elect all of our board of directors and are convertible into Class A Common Units under certain
circumstances, subject to certain exceptions.
(2) Mr. Davison pledged 1,049,406 of these Class A Common Units as collateral for a loan from a bank. In addition to his direct
ownership interests, Mr. Davison is the sole stockholder of Terminal Services, Inc., which owns 1,010,835 Class A Common Units.
(3) Mr. Davison, Jr. pledged 1,164,370 of these Class A Common Units as collateral for a loan from a bank. 1,339,383 of these Class A
Common Units are held by trusts for Mr. Davison's children. 187,856 of these Class A Common Units are held by the James E. and
Margaret A. B. Davison Special Trust.
(4) Mr. Sims pledged 1,450,000 of these Class A Common Units as collateral for loans from a bank.
(5) Mr. 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.
102
With regards to our Class A Convertible Preferred Units, beneficial owners include Rodeo Finance Aggregator LLC
and GSO Rodeo Holdings LP, each of whom beneficially owns 11,450,990 Class A Convertible Preferred Units as of February
26, 2018.
The mailing address for Genesis Energy, LLC and all officers and directors is 919 Milam, Suite 2100, Houston, Texas,
77002.
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.
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 2017. 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 2017, Mr.
Sims (our CEO and a director) had two sons that worked - one as vice president of finance, planning and corporate
development and the other as vice president and general manager of refined products. Mr. James Davison, Sr. (a director) had
one son (who is also a brother of James E. Davison, Jr., a director), that worked as a director in our onshore facilities and
transportation department in 2017. In the aggregate, these family members received total W-2 compensation of less than
$1,000,000.
Director Independence
Because we are a limited partnership, the listing standards of the NYSE do not require that we have a majority of
independent directors (although at least a majority of the members of our board of directors is independent,as defined by the
NYSE rules) or that we have either a nominating committee or a compensation committee of our board of directors. We are,
however, required to have an audit committee consisting of at least three members, all of whom are required to be
“independent” as defined by the NYSE.
Under NYSE rules, to be considered independent, our board of directors must determine that a director has no material
relationship with us other than as a director. The rules specify the criteria by which the independence of directors will be
determined, including guidelines for directors and their immediate family members with respect to employment or affiliation
with us or with our independent public accountants. Our board of directors has determined that each of Ms. Gasaway and
Messrs. Jastrow, Albert and Taylor is an independent director under the NYSE rules. See Item 10. “Directors, Executive
Officers and Corporate Governance” for additional discussion relating to our directors and director independence.
Item 14. Principal Accounting Fees and Services
The following table summarizes the fees for professional services rendered by Ernst & Young and Deloitte & Touche
LLP for the years ended December 31, 2017 and 2016.
Audit Fees (1)
Tax Fees (2)
All Other Fees (3)
Total
2017
2016
(in thousands)
2,867
$
1,308
4
4,179
$
2,441
1,432
8
3,881
$
$
(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. In addition, this includes fees paid to both Ernst & Young and Deloitte, as effective June 2017 we changed our registered
independent public accounting firm from Deloitte to Ernst & Young.
(2) Includes fees for tax return preparation and tax consultations.
103
(3) Includes fees associated with licenses for accounting research software.
Pre-Approval Policy
The services by Ernst & Young and Deloitte in 2017 and 2016 were pre-approved in accordance with the pre-approval
policy and procedures adopted by the audit committee. This policy describes the permitted audit, audit-related, tax and other
services, which we refer to collectively as the Disclosure Categories that the independent auditor may perform. The policy
requires that each fiscal year, a description of the services, or the Service List expected to be performed by the independent
auditor in each of the Disclosure Categories in the following fiscal year be presented to the audit committee for approval.
Any requests for audit, audit-related, tax and other services not contemplated on the Service List must be submitted to
the audit committee for specific pre-approval and cannot commence until such approval has been granted. Normally, pre-
approval is provided at regularly scheduled meetings.
In considering the nature of the non-audit services provided by Ernst & Young and Deloitte in 2017 and 2016, 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, Deloitte 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.
104
Item 15. Exhibits and Financial Statement Schedules
(a)(1) Financial Statements
See “Index to Consolidated Financial Statements and Financial Statement Schedules”.
(a)(2) Financial Statement Schedules.
See “Index to Consolidated Financial Statements and Financial Statement Schedules”.
(a)(3) Exhibits
2.1
2.2
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
Purchase and Sale Agreement, dated July 16, 2015, by and between Genesis Energy L.P. and Enterprise
Products Operating, LLC (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on
Form 8-K/A dated July 16 2015, File No. 001-12295).
Stock Purchase Agreement, dated August 2, 2017, by and among Genesis Energy, L.P., Tronox US
Holdings, Inc., Tronox Alkali Corporation and, for the purposes set forth therein, Tronox Limited
(incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K dated August
7, 2017, File No. 001-12295).
Certificate of Limited Partnership of Genesis Energy, L.P. (incorporated by reference to Exhibit 3.1 to
Amendment No. 2 of the Registration Statement on Form S-1, 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 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 dated 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 dated 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 dated 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 Form 8-K dated
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 Form 8-K dated 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 Form 8-K dated January 3, 2011, File
No. 001-12295).
Certificate of Incorporation of Genesis Energy Finance Corporation, dated as of November 26, 2006
(incorporated by reference to Exhibit 3.7 to 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
Registration Statement on Form S-4 filed on September 26, 2011, File No. 333-177012).
Form of Unit Certificate of Genesis Energy, L.P. (incorporated by reference to Exhibit 4.1 to the
Company’s Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-12295).
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 dated 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 dated 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 dated 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 dated July 31, 2007, File No. 001-12295).
105
4.6
4.7
4.8
4.9
4.10
4.11
4.12
4.13
4.14
4.15
4.16
4.17
4.18
4.19
4.20
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 dated
November 16, 2007, File No. 001-12295).
Amendment No. 2 to the Davison Registration Rights Agreement, dated December 6, 2007
(incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K dated
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 dated 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 dated 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 for 7.875% Senior Subordinated Notes due 2018, dated November 18, 2010 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 dated November 23, 2010, File No. 001-12295).
Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of November 24,
2010, 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 4.2 to the
Company’s Registration Statement on Form S-4 dated September 26, 2011, File No. 333-177012).
Second Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of
December 27, 2010, 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 4.3 to the Company’s Registration Statement on Form S-4 dated September 26, 2011, File No.
333-177012).
Third Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of
February 28, 2011, 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 4.4 to the Company’s Registration Statement on Form S-4 dated September 26, 2011, File No.
333-177012).
Fourth Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of June 30,
2011, 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 4.5 to the
Company’s Registration Statement on Form S-4 dated September 26, 2011, File No. 333-177012).
Fifth Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of
September 13, 2011, 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 4.6 to the Company’s Registration Statement on Form S-4 dated September 26, 2011, File No.
333-177012).
Sixth Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of
September 22, 2011, 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 4.7 to the Company’s Registration Statement on Form S-4 dated September 26, 2011, File No.
333-177012).
Seventh Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of
December 5, 2011, 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 4.9 to Form 10-K filed on February 29, 2012, File No. 001-12295).
Eighth Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of January 3,
2012, 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 4.10 to
Form 10-K filed on February 29, 2012, File No. 001-12295).
Ninth Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of January 27,
2012, 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 4.11 to
Form 10-K filed on February 29, 2012, File No. 001-12295).
106
4.21
4.22
4.23
4.24
4.25
4.26
4.27
4.28
4.29
4.30
4.31
4.32
4.33
4.34
4.35
Tenth Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of December
6, 2012, 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
4.12 to Form 10-K filed on February 26, 2013, File No. 001-12295).
Eleventh Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of
January 28, 2013, 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 4.13 to Form 10-K filed on February 26, 2013, File No. 001-12295).
Twelfth Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of February
19, 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
4.14 to Form 10-K filed on February 27, 2014, File No. 001-12295).
Thirteenth Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of May 7,
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 4.19 to
Form 10-K filed on February 27, 2015, File No. 001-12295).
Fourteenth Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, 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 4.20 to Form 10-K filed on February 27, 2015, File No. 001-12295).
Fifteenth Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, 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 4.21 to Form 10-K filed on February 27, 2015, File No. 001-12295).
Sixteenth Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, 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
4.22 to Form 10-K filed on February 27, 2015, File No. 001-12295).
Seventeenth Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, 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 4.23 to Form 10-K filed on February 27, 2015, File No. 001-12295).
Eighteenth Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, 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 4.24 to Form 10-K filed on February 27, 2015, File No. 001-12295).
Indenture for 5.75% Senior Subordinated Notes due 2021, dated February 8, 2013 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 dated February 11, 2013, File No. 001-12295).
First Supplemental Indenture for 5.75% Senior Subordinated Notes due 2021, dated as of February 19,
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 4.14 to
Form 10-K filed on February 27, 2014, File No. 001-12295).
Second Supplemental Indenture for 5.75% Senior Subordinated Notes due 2021, dated as of May 7,
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 4.27 to
Form 10-K filed on February 27, 2015, File No. 001-12295).
Third Supplemental Indenture for 5.75% Senior Subordinated Notes due 2021, 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 4.28 to
Form 10-K filed on February 27, 2015, File No. 001-12295).
Fourth Supplemental Indenture for 5.75% Senior Subordinated Notes due 2021, 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
4.29 to Form 10-K filed on February 27, 2015, File No. 001-12295).
Fifth Supplemental Indenture for 5.75% Senior Subordinated Notes due 2021, 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 4.30 to
Form 10-K filed on February 27, 2015, File No. 001-12295).
107
4.36
4.37
4.38
4.39
4.40
4.41
4.42
*
4.43
*
4.44
4.45
4.46
4.47
4.48
4.49
4.50
4.51
Sixth Supplemental Indenture for 5.75% Senior Subordinated Notes due 2021, 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 4.31 to
Form 10-K filed on February 27, 2015, File No. 001-12295).
Seventh Supplemental Indenture for 5.75% Senior Subordinated Notes due 2021, 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
4.32 to Form 10-K filed on February 27, 2015, File No. 001-12295).
Eighth Supplemental Indenture for 5.75% Senior Notes due 2021, 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 4.8 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 5.75% Senior Notes due 2021, 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 4.9 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, File No. 001-12295).
Tenth Supplemental Indenture for 5.75% Senior Notes due 2021, 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 4.4 to the Company's
Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, File No. 001-12295).
Eleventh Supplemental Indenture for 5.75% Senior Notes due 2021, 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 4.41 to Form 10-K filed
on February 26, 2016, File No. 001-12295).
Twelfth Supplemental Indenture for 5.75% Senior Notes due 2021, 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 4.4 to the Company's
Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, File No. 001-12295).
Thirteenth Supplemental Indenture for 5.75% Senior Notes due 2021, 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.
Fourteenth Supplemental Indenture for 5.75% Senior Notes due 2021, 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.
Indenture for 5.625% Senior Notes due 2024, 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 dated May 15, 2014, File No. 001-12295).
Supplemental Indenture for the Issuer's 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
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 Form 10-K
filed on February 27, 2015, 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 Form 10-K
filed on February 27, 2015, 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 Form 10-K
filed on February 27, 2015, 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 Form 10-K
filed on February 27, 2015, 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 Form 10-K
filed on February 27, 2015, File No. 001-12295).
108
4.52
4.53
4.54
4.55
4.56
*
4.57
*
4.58
4.59
4.60
4.61
4.62
4.63
4.64
4.65
4.66
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 Form 10-K
filed on February 26, 2016, 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).
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.
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.
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 dated 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 dated 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 to the Indenture dated as of May 21, 2015, 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 dated 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 Form 10-K filed on February 26, 2016, 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).
109
*
4.67
4.68
*
4.69
4.70
10.1
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
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.
Ninth Supplemental Indenture for 6.50% Senior Notes due 2025, dated as of August 14, 2017, among
Genesis Energy, L.P., Genesis Energy Finance Corporation, the subsidiary guarantors named therein
and U.S. Bank National Association, as trustee (incorporated by reference from Exhibit 4.2 to the
Company’s Current Report on Form 8-K filed on August 14, 2017, File No. 001-12295).
Tenth Supplemental Indenture for 6.000% Senior Notes due 2023, 6.75% Senior Notes due 2022 and
6.50% Senior Notes due 2025, dated as of November 13, 2017, among Genesis Energy, L.P., Genesis
Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as
trustee.
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 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 December 11, 2017, 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 Form 8-K dated 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 Form
8-K dated 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 Form 10-K filed on February 26, 2016, 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 Form 8-K dated September 23, 2015, File No. 001-12295).
Fourth Amendment to Fourth Amended and Restated Credit Agreement and Joinder Agreement dated as
of April 27, 2016 among Genesis Energy, L.P., as the borrower, Wells Fargo Bank, National
Association, as administrative agent and issuing bank, Bank of America, N.A. and Bank of Montreal, as
co-syndication agents, U.S. Bank National Association, as documentation agent, and the lenders party
thereto. (incorporated by reference to Exhibit 10.1 to Form 8-K dated 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 (incorporated by reference to
Exhibit 10.1 to the Company’s Current Report on Form 8-K dated 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 dated August 7, 2017, File No. 001-12295).
Form of Indemnity Agreement, among Genesis Energy, L.P., Genesis Energy, LLC and each of the
Directors of Genesis Energy, LLC (incorporated by reference to Exhibit 10.1 to the Company’s Current
Report on Form 8-K dated March 5, 2010, File No. 001-12295).
Equity Distribution Agreement, dated June 27, 2016, among Genesis Energy, L.P., RBC Capital
Markets, LLC, BNP Paribas Securities Corp., Capital One Securities, Inc., Deutsche Bank Securities
Inc., DNB Markets, Inc., Fifth Third Securities, Inc., Scotia Capital (USA) Inc. and SMBC Nikko
Securities America, Inc. (incorporated by reference to Exhibit 1.1 to Form 8-K dated June 27, 2016,
File No. 001-12295).
110
10.10
+ Genesis Energy, LLC First Amended and Restated Stock Appreciation Rights Plan (incorporated by
reference to Exhibit 10.24 to the Company’s Annual Report on Form 10-K for the year ended
December 31, 2008, File No. 001-12295).
10.11
+ Form of Stock Appreciation Rights Plan Grant Notice (incorporated by reference to Exhibit 10.25 to the
Company’s Annual Report on Form 10-K for the year ended December 31, 2008, File No. 001-12295).
10.12
+ Genesis Energy, L.P. 2010 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the
Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No.
001-12295).
10.13
+ 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).
10.14
+ 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).
10.15
+ 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).
10.16
10.17
10.18
10.19
11.1
21.1
23.1
23.2
23.3
23.4
31.1
31.2
32.1
32.2
95
+ Employment Agreement by and between Genesis Energy, LLC and Paul A. Davis, dated March 5, 2012
(incorporated by reference to Exhibit 10.17 to the Company’s Annual Report on Form 10-K dated
February 26, 2013, File No. 001-12295).
+ Employment Agreement by and between DG Marine Transportation, LLC and Richard Alexander dated
July 18, 2008 ((incorporated by reference to Exhibit 10.22 to the Company's Annual Report on Form
10-K dated February 27, 2015, File No. 001-12295).
Class A Convertible Preferred Unit Purchase Agreement, dated August 2, 2017, by and between Genesis
Energy, L.P., and the purchasers named on Schedule A thereto (incorporated by reference to Exhibit
10.1 to the Company’s Current Report on Form 8-K dated August 7, 2017, 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).
Statement Regarding Computation of Per Share Earnings (See Notes 2 and 11 of the Notes to the
Consolidated Financial Statements).
Subsidiaries of the Registrant.
Consent of Ernst & Young LLP.
Consent of Ernst & Young LLP.
Consent of Deloitte & Touche LLP.
Consent of Deloitte & Touche 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.
Mine Safety Disclosure Exhibit
101.INS
XBRL Instance Document.
101.SCH
XBRL Schema Document.
101.CAL
XBRL Calculation Linkbase Document.
101.LAB
XBRL Label Linkbase Document.
101.PRE
XBRL Presentation Linkbase Document.
111
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
101.DEF
XBRL Definition Linkbase Document.
*
+
Filed herewith
A management contract or compensation plan or arrangement.
Item 16. Form 10-K Summary
Not Applicable
112
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.
SIGNATURES
Date: February 26, 2018
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 26, 2018
February 26, 2018
February 26, 2018
February 26, 2018
February 26, 2018
February 26, 2018
February 26, 2018
February 26, 2018
February 26, 2018
113
Item 8. Financial Statements and Supplementary Data
GENESIS ENERGY, L.P.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULES
Financial Statements of Genesis Energy, L.P.
Report of Independent Registered Public Accounting Firm
Report of Independent Registered Public Accounting Firm on Internal Controls Over Financial
Reporting
Report of Independent Registered Public Accounting Firm
Page
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. Acquisitions
4. Receivables
5. Inventories
6. Fixed Assets, Mineral Leaseholds and Asset Retirement Obligations
7. Net Investment in Direct Financing Leases
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
23. Quarterly Financial Data (Unaudited)
24. Condensed Consolidating Financial Information
25. Subsequent Events
Financial Statements of Significant Equity Investee — Poseidon Oil Pipeline Company, L.L.C.
Independent Auditor's Report
Balance Sheet
Statement of Operations
Statement of Cash Flows
Statement of Members' Equity
Notes to Financial Statements
114
F-1
F-2
F-3
F-4
F-5
F-6
F-7
F-8
F-9
F-9
F-9
F-14
F-18
F-18
F-19
F-20
F-21
F-23
F-24
F-26
F-31
F-31
F-33
F-34
F-35
F-36
F-37
F-40
F-42
F-44
F-45
F-47
F-47
F-56
F-58
F-59
F-60
F-61
F-62
F-63
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 sheet of Genesis Energy, L.P. (the Partnership) as of December 31, 2017, and the
related consolidated statement of operations, partners’ capital and cash flows for the year ended December 31, 2017, and the related notes
(collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the
consolidated financial position of the Partnership at December 31, 2017, and the consolidated results of its operations and its cash flows for
the year ended December 31, 2017, 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, 2017, 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 26, 2018 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 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 the financial statements are free of material misstatement, whether due to error or fraud. Our audit
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 audit 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 audit provides a reasonable basis
for our opinion.
/s/ Ernst & Young LLP
We have served as the Partnership's auditor since 2017.
Houston, Texas
February 26, 2018
F-1
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, 2017, 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, 2017, based on the COSO criteria.
As indicated in the accompanying Management's Report on Internal Control over Financial Reporting, management’s assessment of and
conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of the Alkali Business, which
is included in the 2017 consolidated financial statements of the Partnership and constituted 20% and 2% of total and net assets, respectively,
as of December 31, 2017 and 14% and 53% of revenues and net income, respectively, for the year then ended. Our audit of internal control
over financial reporting of the Partnership also did not include an evaluation of the internal control over financial reporting of the Alkali
Business.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the
consolidated balance sheet of Genesis Energy, L.P. as of December 31, 2017, and the related consolidated statement of operations, partners’
capital and cash flows for the year ended December 31, 2017, and the related notes of the Partnership and our report dated February 26, 2018
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 [title of management’s report]. Our responsibility is to
express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered
with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and
the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit
included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and
evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we
considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting
principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of
records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide
reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally
accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of
management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or
that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young LLP
Houston, TX
February 26, 2018
F-2
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Genesis Energy, LLC and Unitholders of
Genesis Energy, L.P.
Houston, Texas
We have audited the accompanying consolidated balance sheets of Genesis Energy, L.P. and subsidiaries (the "Partnership") as of December
31, 2016, and the related consolidated statements of operations, partners’ capital, and cash flows for each of the two years in the period ended
December 31, 2016. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an
opinion on the financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards
require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinions.
In our opinion, such consolidated financial statements referred to above present fairly, in all material respects, the financial position of
Genesis Energy, L.P. and subsidiaries as of December 31, 2016, and the results of their operations and their cash flows for each of the two
years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 27, 2017
F-3
GENESIS ENERGY, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
Accounts receivable—trade, net
Inventories
Other
Total current assets
FIXED ASSETS, at cost
Less: Accumulated depreciation
Net fixed assets
MINERALS LEASEHOLDS, net of accumulated depletion
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income
EQUITY INVESTEES
INTANGIBLE ASSETS, net of amortization
GOODWILL
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,
2017
December 31,
2016
$
9,041
$
495,449
88,653
42,890
636,033
5,601,015
(734,986)
4,866,029
564,506
125,283
381,550
182,406
325,046
56,628
7,029
224,682
98,587
29,271
359,569
4,763,396
(548,532)
4,214,864
—
132,859
408,756
204,887
325,046
56,611
$
7,137,481
$
5,702,592
$
270,855
$
185,409
456,264
1,099,200
2,598,918
11,913
256,571
119,841
140,962
260,803
1,278,200
1,813,169
25,889
204,481
4,422,866
3,582,542
Class A Convertible Preferred Units, 22,411,728 issued and outstanding at
December 31, 2017
697,151
—
COMMITMENTS AND CONTINGENCIES (Note 21)
PARTNERS’ CAPITAL:
Common unitholders, 122,579,218 and 117,979,218 units issued and outstanding at
December 31, 2017 and 2016, respectively
Accumulated other comprehensive loss
Noncontrolling interests
Total partners' capital
2,026,147
(604)
(8,079)
2,017,464
2,130,331
—
(10,281)
2,120,050
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL
$
7,137,481
$
5,702,592
The accompanying notes are an integral part of these consolidated financial statements.
F-4
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
Year Ended December 31,
2017
2016
2015
$
318,239
$
334,679
$
REVENUES:
Offshore pipeline transportation services
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
Gain on sale of assets
Total costs and expenses
OPERATING INCOME
Equity in earnings of equity investees
Interest expense
Gain on basis step up on historical interest
Other expense, net
Income from operations before income taxes
Income tax benefit (expense)
NET INCOME
Net loss attributable to noncontrolling interests
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.
Less: Accumulated distributions attributable to Class A Convertible
Preferred Units
NET INCOME AVAILABLE TO COMMON UNITHOLDERS
BASIC AND DILUTED NET INCOME PER COMMON UNIT:
Basic and Diluted
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
Basic and Diluted
`
462,622
205,287
1,042,229
2,028,377
866,458
102,189
154,606
333,918
72,065
66,421
252,480
(40,311)
1,807,826
220,551
51,046
(176,762)
—
(16,715)
78,120
3,959
82,079
568
171,503
213,021
993,290
1,712,493
823,524
101,103
142,551
91,443
79,624
45,625
222,196
—
140,230
177,880
238,757
1,689,662
2,246,529
1,481,619
121,189
135,200
96,806
39,713
64,995
150,140
—
1,506,066
2,089,662
206,427
47,944
(139,947)
—
—
114,424
(3,342)
111,082
2,167
156,867
54,450
(100,596)
332,380
(17,529)
425,572
(3,987)
421,585
943
$
$
$
82,647
$
113,249
$
422,528
(21,995)
60,652
0.50
$
$
—
113,249
1.00
$
$
—
422,528
4.10
121,546
113,433
103,004
The accompanying notes are an integral part of these consolidated financial statements.
F-5
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
Net income
Other comprehensive loss:
Increase in benefit plan liability
Total Comprehensive loss
Comprehensive income attributable to non-controlling interests
Comprehensive income attributable to Genesis Energy, L.P.
Year Ended December 31,
2017
2016
2015
82,079
111,082
421,585
(604)
81,475
568
82,043
—
111,082
2,167
113,249
—
421,585
943
422,528
The accompanying notes are an integral part of these consolidated financial statements.
F-6
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(In thousands)
Number of
Common
Units
Partners'
Capital
Noncontrolling
Interest
Accumulated
Other
Comprehensive
Loss
Total
95,029
$ 1,229,203
$
— $
— $1,229,203
December 31, 2014
Net income (loss)
Noncontrolling interest from acquisition
Cash distributions to partners, net
Cash distributions to noncontrolling interests
Issuance of units for cash, net (Note 11)
December 31, 2015
Net income (loss)
Cash distributions to partners, net
Cash contributions from noncontrolling interests
Issuance of units for cash, net (Note 11)
December 31, 2016
Net income (loss)(1)
Cash distributions to partners, net
Cash contributions from noncontrolling interests
—
—
—
—
422,528
—
(256,389)
—
14,950
633,759
109,979
2,029,101
—
—
—
8,000
113,249
(310,039)
—
298,020
117,979
2,130,331
—
—
—
82,647
(321,875)
—
Issuance of common units for cash, net (Note 11)
4,600
140,513
Other comprehensive loss
Distributions to preferred unitholders
December 31, 2017
—
—
122,579
—
(5,469)
$ 2,026,147
$
(943)
(6,447)
—
(960)
—
(8,350)
(2,167)
—
236
—
(10,281)
(568)
—
2,770
—
—
—
(8,079) $
—
421,585
(6,447)
—
— (256,389)
(960)
—
633,759
—
— 2,020,751
—
111,082
— (310,039)
236
—
298,020
—
— 2,120,050
82,079
—
— (321,875)
2,770
—
—
(604)
—
140,513
(604)
(5,469)
(604) $2,017,464
(1) Net income (loss) includes $22 million attributable to preferred unitholders accumulated as of December 31, 2017.
The accompanying notes are an integral part of these consolidated financial statements.
F-7
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income
Adjustments to reconcile net income to net cash provided by
operating activities -
Depreciation, depletion and amortization
Provision for leased items no longer in use
Gain on sale of assets
Gain on basis step up on historical interest
Amortization and write-off of debt issuance costs and premium or
discount
Amortization of unearned income and initial direct costs on direct
financing leases
Payments received under direct financing leases
Equity in earnings of investments in equity investees
Cash distributions of earnings of equity investees
Non-cash effect of equity-based compensation plans
Deferred and other tax benefits
Unrealized (gains) losses on derivative transactions
Other, net
Net changes in components of operating assets and liabilities, net
of acquisitions (See Note 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
Acquisitions
Contributions in aid of construction costs
Proceeds from asset sales
Other, net
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
Proceeds from issuance of Class A convertible preferred units, net
Repayment of senior unsecured notes
Debt issuance costs
Issuance of common units for cash, net
Contributions (distributions) from (to) noncontrolling interests
Distributions to common unitholders
Other, net
Net cash provided by financing activities
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
2017
Year Ended December 31,
2016
2015
$
82,079
$
111,082
$
421,585
252,480
12,589
(40,311)
—
222,196
—
—
—
150,140
—
—
(332,380)
13,103
10,138
10,881
(13,747)
20,668
(51,046)
62,618
(5,775)
(4,060)
10,943
(10,839)
10,156
338,858
(14,395)
20,672
(47,944)
65,867
6,558
2,142
1,287
11,385
(90,650)
298,338
(14,979)
20,664
(54,450)
71,823
5,014
2,960
(1,009)
3,915
5,372
289,536
(250,593)
(463,100)
(495,774)
20,280
(4,647)
(1,325,759)
124
85,722
—
(1,474,873)
1,458,700
(1,637,700)
1,000,000
726,419
(204,830)
(25,913)
140,513
2,770
(321,875)
(57)
1,138,027
2,012
7,029
21,353
—
(25,394)
13,374
3,609
(151)
(450,309)
1,115,800
(952,600)
—
—
—
(1,578)
298,020
236
(310,039)
(1,734)
148,105
(3,866)
10,895
25,645
(3,045)
(1,520,299)
3,179
2,811
(1,976)
(1,989,459)
1,525,050
(960,450)
1,139,718
—
(350,000)
(28,901)
633,759
(960)
(256,389)
(471)
1,701,356
1,433
9,462
$
9,041
$
7,029
$
10,895
The accompanying notes are an integral part of these consolidated financial statements.
F-8
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization
We are a growth-oriented master limited partnership focused on the midstream segment of the crude oil and natural
gas industry, as well as sodium minerals and sulfur services, in the Gulf Coast region of the United States, Wyoming and the
Gulf of Mexico. We have a diverse portfolio of assets, including pipelines, offshore hub and junction platforms, Alkali
Business, refinery-related plants, storage tanks and terminals, railcars, rail loading and unloading facilities, barges and other
vessels, and trucks. We were formed in 1996 and 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.
On September 1, 2017, we acquired our trona and trona-based exploring, mining, processing, soda ash production,
marketing and selling business (the "Alkali Business") for approximately $1.325 billion in cash. We funded that acquisition
and the related transaction costs with proceeds from a $750 million private placement of convertible preferred units, a $550
million public offering of notes, our revolving credit facility, and cash on hand. At the closing, we entered into transition
service agreements to facilitate the transition of operations and uninterrupted services for both employees and customers. We
report the results of our Alkali Business in our renamed sodium minerals and sulfur services segment, which includes our
Alkali Business as well as our legacy refinery services operations.
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. Our
disclosures related to prior periods have been recast to reflect our reorganized segments.
These four divisions that constitute our reportable segments consist of the following:
• Offshore pipeline transportation and processing of crude oil and natural gas in the Gulf of Mexico;
•
Sodium minerals and sulfur services involving trona and trona-based exploring, mining, processing, soda ash
production, marketing and selling activities, as well as processing of high sulfur (or “sour”) gas streams for
refineries to remove the sulfur, and selling the related by-product, sodium hydrosulfide (or “NaHS,” commonly
pronounced "nash");
• Onshore facilities and transportation, which include terminaling, blending, storing, marketing, and transporting
crude oil, petroleum products, and CO2; and
• Marine transportation to provide waterborne transportation of petroleum products and crude oil throughout North
America
2. Summary of Significant Accounting Policies
Basis of Consolidation and Presentation
The accompanying financial statements and related notes present our consolidated financial position as of
December 31, 2017 and 2016 and our results of operations, statements of comprehensive income, changes in partners’ capital
and cash flows for the years ended December 31, 2017, 2016 and 2015. All intercompany balances and transactions have been
eliminated. The accompanying Consolidated Financial Statements include Genesis Energy, L.P. and its subsidiaries.
Except per unit amounts, or as noted within the context of each footnote disclosure, the dollar amounts presented in
the tabular data within these footnote disclosures are stated in thousands of dollars.
Joint Ventures
We participate in several joint ventures, including a 64% interest in Poseidon Oil Pipeline Company, L.L.C. (or
"Poseidon"), a 25.7% interest in Neptune Pipeline Company, LLC and a 29% interest in Odyssey Pipeline L.L.C. (or
"Odyssey"). We account for our investments in these joint ventures by the equity method of accounting. See Notes 3 and 8.
F-9
Use of Estimates
The preparation of our Consolidated Financial Statements requires us to make estimates and assumptions that affect
the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the
Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. We based
these estimates and assumptions on historical experience and other information that we believed to be reasonable under the
circumstances. Significant estimates that we make include: (1) liability and contingency accruals, (2) estimated fair value of
assets and liabilities acquired and identification of associated goodwill and intangible assets, (3) estimates of future net cash
flows from assets for purposes of determining whether impairment of those assets has occurred, and (4) estimates of future
asset retirement obligations. Additionally, for purposes of the calculation of the fair value of awards under equity-based
compensation plans, we make estimates regarding expected forfeiture rates of the rights and expected future distribution yield
on our units. While we believe these estimates are reasonable, actual results could differ from these estimates. Changes in facts
and circumstances may result in revised estimates.
Cash and Cash Equivalents
Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original
maturities of three months or less. We have no requirement for compensating balances or restrictions on cash. We periodically
assess the financial condition of the institutions where these funds are held and believe that our credit risk is minimal.
Accounts Receivable
We review our outstanding accounts receivable balances on a regular basis and record an allowance for amounts that
we expect will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection
efforts have been exhausted.
Inventories
Our inventories are valued at the lower of cost or net realizable value. With the exception of our Alkali Business, cost
is determined principally under the average cost method within specific inventory pools.
Within our Alkali Business, the cost of inventories are determined using the FIFO, except for materials and supplies
which are recorded at average cost, and raw materials which are recorded at standard cost.
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, 5 to 30 years for machinery and equipment, 3 to 7 years for transportation equipment, and 3 to
10 years for buildings and improvements, office equipment, furniture and fixtures and other equipment.
Interest is capitalized in connection with the construction of major facilities. The capitalized interest is recorded as part
of the asset to which it relates and is amortized over the asset’s estimated useful life.
Maintenance and repair costs are charged to expense as incurred. Costs incurred for major replacements and upgrades
are capitalized and depreciated over the remaining useful life of the asset. Certain volumes of crude oil and refined products are
classified in fixed assets, as they are necessary to ensure efficient and uninterrupted operations of the gathering businesses.
These crude oil and refined products volumes are carried at their weighted average cost.
Long-lived assets are reviewed for impairment. An asset is tested for impairment when events or circumstances
indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds
the sum of the undiscounted cash flows expected to be generated from the use and ultimate disposal of the asset. If the carrying
value is determined to not be recoverable under this method, an impairment charge equal to the amount the carrying value
exceeds the fair value is recognized. Fair value is generally determined from estimated discounted future net cash flows.
Mineral leaseholds are depleted over their useful lives as determined under the units of production method. When it
has been determined that a mineral property can be economically developed as a result of establishing proven and probable
reserves, the costs incurred to develop such property through the commencement of production are capitalized.
Deferred Charges on Marine Transportation Assets
Our marine vessels are required by US Coast Guard regulations to be re-certified after a certain period of time, usually
every five years. The US Coast Guard states that vessels must meet specified "seaworthiness" standards to maintain required
operating certificates. To meet such standards, vessels must undergo regular inspection, monitoring, and maintenance, referred
to as "dry-docking." Typical dry-docking costs include costs incurred to comply with regulatory and vessel classification
inspection requirements, blasting and steel coating, and steel replacement. We defer and amortize these costs to maintenance
and repair expense over the length of time that the certification is supposed to last.
F-10
Asset Retirement Obligations
Some of our assets have contractual or regulatory obligations to perform dismantlement and removal activities, and in
some instances remediation, when the assets are abandoned. In general, our asset retirement obligations relate to future costs
associated with the disconnecting or removing of our crude oil and natural gas pipelines and platforms, CO2 pipelines, barge
decommissioning, removal of equipment and facilities from leased acreage and land restoration. The fair value of a liability for
an asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using our credit
adjusted risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-
lived asset. The capitalized cost is depreciated over the useful life of the related asset. Accretion of the discount increases the
liability and is recorded to expense. See Note 6.
Direct Financing Leasing Arrangements
For our direct financing 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 and is included in onshore facilities and transportation revenue in the Consolidated Statements of Operations.
The pipeline cost is not included in fixed assets.
We review our direct financing lease arrangements for credit risk. Such review includes consideration of the credit
rating and financial position of the lessee. See Note 7.
Intangible and Other Assets
Intangible assets with finite useful lives are amortized over their respective estimated useful lives. If an intangible
asset has a finite useful life, but the precise length of that life is not known, that intangible asset shall be amortized over the best
estimate of its useful life. At a minimum, we will assess the useful lives and residual values of all intangible assets on an annual
basis to determine if adjustments are required. We are amortizing our customer and supplier relationships, contract agreements,
licensing agreements and trade name based on the period over which the asset is expected to contribute to our future cash
flows. Generally, the contribution of these assets to our cash flows is expected to decline over time, such that greater value is
attributable to the periods shortly after the acquisition was made. Intangible assets associated with lease or other items are
being amortized on a straight-line basis.
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 the issuance of long-term debt and certain amendments to our credit facilities have
historically been capitalized and amortized using the straight-line method over the term of the related debt. Use of the straight-
line method does not differ materially from the “effective interest” method of amortization. Certain of our capitalized debt
issuance costs related to our respective issuances of notes are classified as reductions in long-term debt.
Goodwill
Goodwill represents the excess of purchase price over fair value of net assets acquired. We evaluate, and test if
necessary, goodwill for impairment annually at October 1, and more frequently if indicators of impairment are present. During
the evaluation, we may perform a qualitative assessment of relevant events and circumstances to determine the likelihood of
goodwill impairment. If it is deemed more likely than not that the fair value of the reporting unit is less than its carrying
amount, we calculate the fair value of the reporting unit. Otherwise, further testing is not necessary. We may also elect to
exercise our unconditional option to bypass this qualitative assessment, in which case we would also calculate the fair value of
the reporting unit. If the calculated fair value of the reporting unit exceeds its book value including associated goodwill
amounts, the goodwill is considered to be unimpaired and no impairment charge is required. If the fair value of the reporting
unit is less than its book value including associated goodwill amounts, a charge to earnings may be necessary to reduce the
carrying value of the goodwill to its implied fair value. In the event that we determine that goodwill has become impaired, we
will incur a charge for the amount of impairment during the period in which the determination is made. No goodwill
impairment has occurred in any of the periods presented. 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
Our phantom units issued under our 2010 Long-Term Incentive Plan result in the payment of cash to our employees or
directors of our general partner upon exercise or vesting of the related award. The fair value of our phantom units is equal to the
F-11
market price of our common units. Our phantom units include both service-based and performance-based awards. For our
performance-based awards, our fair value estimates are weighted based on probabilities for each performance condition
applicable to the award. See Note 16 for more information on these plans.
Revenue Recognition
Offshore Pipeline Transportation—Revenue from our offshore pipelines is generally based upon a fixed fee per unit of
volume gathered or transported multiplied by the volume delivered. Transportation fees are based either on contractual
arrangements or tariffs regulated by the FERC. Revenue associated with these fee-based contracts and tariffs is recognized
when volumes have been delivered. Revenues from offshore platform services are primarily dependent upon the level of
commodity charges and/or demand-type fees billable to customers. Revenues from offshore platform services are recognized in
the period the services are provided. Revenue from commodity charges is based on a fee per unit of volume (typically per
MMcf of natural gas or per barrel of crude oil) delivered to the platform multiplied by the total volume of each product
delivered. Demand-type fees are similar to firm capacity reservation agreements for a pipeline in that they are charged to a
customer regardless of the volume the customer actually delivers to the platform. Contracts for platform services often include
both demand-type fees and commodity charges, but demand-type fees generally expire after a contractually fixed period of time
and in some instances may be subject to cancellation by customers.
Product Sales—Revenues from the sale of crude oil, petroleum products and CO2 by our onshore facilities and
transportation segment, and caustic soda, NaHS, soda ash and other alkali products by our sodium minerals and sulfur services
segment are recognized when title to the inventory is transferred to the customer, pricing is fixed and determinable,
collectability is reasonably assured and there are no further significant obligations for future performance by us. Most
frequently, title transfers upon our delivery of the inventory to the customer at a location designated by the customer, although
in certain situations, title transfers when the inventory is loaded for transportation to the customer. Our crude oil and petroleum
products are typically sold at prices based off daily or monthly published prices. Many of our contracts for sales of NaHS
incorporate the price of caustic soda in the pricing formulas. When necessary, accruals are made for sales returns, rebates and
other allowances.
Rail Facility Loading and Unloading Revenues—Revenues based on a per barrel fee from the loading and/or
unloading of crude oil at our rail facilities is recognized as the crude oil enters or exits the railcars.
Onshore Pipeline Transportation—Revenues from transportation of crude oil by our pipelines are based on actual
volumes at a published tariff. Tariff revenues are recognized either at the point of delivery or at the point of receipt pursuant to
the specifications outlined in our regulated tariffs. Income from direct financing leases is being recognized ratably over the
term of the leases and is included in pipeline revenues.
In order to compensate us for bearing the risk of volumetric losses in volumes that occur to crude oil in our pipelines
(onshore and offshore) due to temperature, crude quality and the inherent difficulties of measurement of liquids in a pipeline,
our tariffs and agreements include the right for us to make volumetric deductions from the shippers for quality and volumetric
fluctuations. We refer to these deductions as pipeline loss allowances.
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, based on prevailing market prices at that time. 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 that we must make to replace the lost volumes. We reflect inventories in the Consolidated Financial Statements at the
lower of the recorded value or the market value at the balance sheet date. We value liabilities to replace crude oil at current
market prices. The crude oil in inventory can then be sold, resulting in additional revenue if the sales price exceeds the
inventory value.
Marine Transportation—Revenues from the inland and offshore marine transportation of heavy refined petroleum
products, including asphalt and crude oil, via our barges or vessels are recognized over the transit time of individual shipments
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 other specified operational costs are directly reimbursed by the customer under most of
these contracts.
Cost of Sales and Operating Expenses
Onshore facilities and transportation operating 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.
F-12
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 plants located at various refineries, caustic soda used in the
process of processing the refiner’s sour gas, and costs to transport the soda ash, other alkali products, NaHS and caustic soda.
Pipeline operating costs consist primarily of power costs to operate pumping and platform equipment, personnel costs
to operate the pipelines and platforms, insurance costs and costs associated with maintaining the integrity of our pipelines.
Income Taxes
We are a limited partnership, organized as a pass-through entity for federal income tax purposes. As such, we do not
directly pay federal income tax. Our taxable income or loss, which may vary substantially from the net income or net loss we
report in our Consolidated Statements of Operations, is included in the federal income tax returns of each partner.
Some of our corporate subsidiaries pay U.S. federal, state, and foreign income taxes. Deferred income tax assets and
liabilities for certain operations conducted through corporations are recognized for temporary differences between the assets
and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in
the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance for the amount of any
tax benefit not expected to be realized. Penalties and interest related to income taxes will be included in income tax expense in
the Consolidated Statements of Operations.
As further discussed in Note 22, "Income Taxes," on December 22, 2017, the Tax Cuts and Jobs Act (“Act”) was
signed into law which enacts significant changes to U.S. tax and related laws. U.S. state or other regulatory bodies have not
finalized potential changes to existing laws and regulations which may result from the new U.S. tax and related laws. In
accordance with the Securities and Exchange Commission’s Staff Accounting Bulletin No. 118 (“SAB No. 118”), the Company
has recorded provisional estimates to reflect the effect of the provisions of the recently enacted U.S. tax and related laws on the
Partnership’s income tax assets and liabilities as of December 31, 2017.
Derivative Instruments and Hedging Activities
When we hold inventory positions in crude oil and petroleum products, we use derivative instruments to hedge
exposure to price risk. Derivative transactions, which can include forward contracts and futures positions on the NYMEX, are
recorded in the Consolidated Balance Sheets as assets and liabilities based on the derivative’s fair value. Changes in the fair
value of derivative contracts are recognized currently in earnings unless specific hedge accounting criteria are met. We must
formally designate the derivative as a hedge and document and assess the effectiveness of derivatives associated with
transactions that receive hedge accounting. Accordingly, changes in the fair value of derivatives are included in earnings in the
current period for (i) derivatives accounted for as fair value hedges; (ii) derivatives that do not qualify for hedge accounting and
(iii) the portion of cash flow hedges that is not highly effective in offsetting changes in cash flows of hedged items. Changes in
the fair value of cash flow hedges are deferred in Accumulated Other Comprehensive Income (“AOCI”) and reclassified into
earnings when the underlying position affects earnings.
In addition, we have determined that certain provisions in our Class A Convertible Preferred units represent an
embedded derivative which must be bifurcated and recorded at fair value, with changes in fair value in respective periods being
recorded in our Consolidated Statements of Operations. See Note 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
As a result of our acquisition of our Alkali Business, we now sponsor a defined benefit plan. 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 or loss.
F-13
Business Acquisitions
For acquired businesses, we apply the acquisition method and generally recognize the identifiable assets acquired, the
liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the date of acquisition. See
Note 3 for more information regarding our acquisition accounting and recording of acquisition costs.
Recent and Proposed Accounting Pronouncements
In May 2014, the FASB issued revised guidance on revenue from contracts with customers that will supersede most
current revenue recognition guidance, including industry-specific guidance. The core principle of the revenue model is that an
entity will recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the
consideration to which the entity expects to be entitled in exchange for those goods or services. The new standard provides a
five-step analysis for transactions to determine when and how revenue is recognized. The guidance permits the use of either a
full retrospective or a modified retrospective transition method. In July 2015, the FASB approved a one year deferral of the
effective date of this standard to December 15, 2017 for annual reporting periods beginning after that date. The FASB also
approved early adoption of the standard, but not before the original effective date of December 15, 2016. As a result of our
process of evaluating the impact of this guidance on each type of revenue contract entered into with customers, we have
determined that the adoption of this guidance will have an immaterial impact on revenues and costs in certain of our revenue
streams including our legacy sulfur removal operations relating to our NaHS business. We expect these items to have an even
less significant impact on net income on a go forward basis. We have also identified certain contracts or elements of contracts
for product loss allowances and tiered pricing that will be impacted. These items will not have a material impact on our
financial statements. We are adopting this guidance by using the modified retrospective approach, effective January 1, 2018, by
recognizing the cumulative effect of applying the guidance for periods prior to January 1, 2018 to the opening balance of
Partner’s Capital. Management has concluded the estimated cumulative effect to be recorded is not material.
In July 2015, the FASB issued guidance modifying the accounting for inventory. Under this guidance, the
measurement principle for inventory will change from lower of cost or market value to lower of cost and net realizable value.
The guidance defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably
predictable costs of completion, disposal, and transportation. The guidance is effective for reporting periods after December 15,
2016, with early adoption permitted. We have adopted this guidance as of January 1, 2017 with no material impact on our
consolidated financial statements.
In February 2016, the FASB issued guidance to improve the transparency and comparability among companies by
requiring lessees to recognize a lease liability and a corresponding lease asset for virtually all lease contracts. The guidance also
requires additional disclosure about leasing arrangements. The guidance is effective for interim and annual periods beginning
after December 15, 2018 and requires a modified retrospective approach to adoption. Early adoption is permitted. We are
currently evaluating this guidance.
In August 2016, the FASB issued guidance that addresses how certain cash receipts and payments are presented and
classified in the statement of cash flows under Topic 230, Statement of Cash flow, and other Topics. The guidance is effective
for annual reporting periods, and interim periods therein, beginning after December 15, 2017. We expect this guidance to have
an impact on how we report our operating and investing cash flows from certain cash receipts and payments, particularly
relating to cash distributions received from certain of our equity investees.
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 adopted this guidance and it did not have an impact on our
consolidated financial statements.
3. Acquisitions
F-14
Alkali Business
On September 1, 2017, we acquired our Alkali Business for approximately $1.325 billion (inclusive of approximately
$105 million in working capital). Our Alkali Business mines and processes trona from which it produces natural soda ash, also
known as sodium carbonate (Na2CO3), as basic building block for a number of ubiquitous products, including flat glass,
container glass, dry detergent and a variety of chemicals and other industrial products. To finance that transaction and the related
costs, we used proceeds from (i) a $550 million public offering of 6.50% senior unsecured notes due 2025 in August 2017,
generating net proceeds of $540.1 million after issuance and underwriting fees, (ii) a $750 million private placement of Class A
Convertible Preferred units in September 2017, generating net proceeds of $726.4 million, (iii) borrowings under our revolving
credit facility and (iv) cash on hand.
We have reflected the financial results of our Alkali Business in our sodium minerals and sulfur services segment from
the date of acquisition. The purchase price has been allocated to the assets acquired and liabilities assumed based on estimated
preliminary fair values. Those preliminary fair values were developed by management with the assistance of a third-party
valuation firm and are subject to change pending a final valuation report and final determination of any other purchase price
adjustments. Certain changes were made in our preliminary purchase price allocation at December 31, 2017, as compared to
what we had previously disclosed in our third quarter 2017 Form 10-Q. These changes principally relate to reclassifications
made between mineral leaseholds and fixed assets as a result of further progress in our valuation process. We expect to finalize
the purchase price allocation for this transaction during the first half of 2018.
The preliminary allocation of the purchase price, as presented on our Consolidated Balance Sheet, is summarized as
follows:
Accounts receivable
Inventories
Other current assets
Fixed assets
Mineral leaseholds
Intangible assets
Other assets
Accounts payable
Accrued Liabilities
Other long-term liabilities
Total Purchase Price
138,258
34,929
13,254
663,217
566,019
800
3,612
(44,547)
(36,884)
(13,658)
1,325,000
$
Fixed assets identified in connection with our valuation and preliminary purchase price allocation include the related
facilities, machinery and equipment associated with our Alkali Business, principally at our Green River, Wyoming operations.
These assets will be depreciated under the straight line method and have useful lives ranging from 2 to 30 years. Mineral
leaseholds include the trona reserves at our Green River, Wyoming facility and are depleted over their useful lives as determined
by the units of production method. Other long-term liabilities contains various items including assumed employee benefit plan
obligations. Other items principally consist of working capital items of our Alkali Business as acquired on September 1, 2017.
Our Consolidated Financial Statements include the results of our Alkali Business since September 1, 2017, the closing
date of the acquisition. The following table presents selected financial information included in our Consolidated Financial
Statements for the periods presented:
Revenues
Net income
Year Ended
December 31,
2017
277,011
42,014
F-15
The table below presents selected unaudited pro forma financial information incorporating the historical results of our
Alkali Business. The pro forma financial information below has been prepared as if the acquisition had been completed on
January 1, 2015 and is based upon assumptions deemed appropriate by us and may not be indicative of actual results. This pro
forma information was prepared using historical financial data of our trona and trona-based exploring, mining, processing,
producing, marketing and selling business and reflects certain estimates and assumptions made by our management. Our
unaudited pro forma financial information is not necessarily indicative of what our consolidated financial results would have
been had our Alkali Business acquisition been completed on January 1, 2015. Pro forma net income includes the effects of
distributions on preferred units and interest expense on incremental borrowings. The dilutive effect of Class A Preferred Units is
calculated using the if-converted method.
Pro forma consolidated financial operating results:
Revenues
Net Income Attributable to Genesis Energy, L.P.
Net Income Available to Common Unitholders
Basic and diluted earnings per common unit:
As reported net income per common unit
Pro forma net income per common unit, basic
Pro forma net income per common unit, dilutive
Year Ended
December 31,
2017
2016
2015
$ 2,549,438
$ 2,498,293
$ 3,043,529
84,010
18,953
120,515
57,057
416,118
351,436
$
$
$
0.50
0.16
0.16
$
$
$
1.00
0.50
0.50
$
$
$
4.10
3.41
3.33
As relating to our Alkali Business acquisition, we have incurred approximately $12.0 million in acquisition related costs
through December 31, 2017. Such costs are included as "General and Administrative costs" on our Consolidated Statement of
Operations.
Enterprise Offshore
On July 24, 2015, we acquired the offshore pipeline and services business of Enterprise Products Partners, L.P. and its
affiliates for approximately $1.5 billion, subject to certain adjustments. That business includes interests in offshore crude oil and
natural gas pipelines and six offshore hub platforms, including a 36% interest in the Poseidon Oil Pipeline System, a 50%
interest in the Southeast Keathley Canyon Oil Pipeline System, and a 50% interest in the Cameron Highway Oil Pipeline
System. To finance that transaction, in July 2015, we issued 10,350,000 common units in a public offering that generated
proceeds of $437.2 million net of underwriter discounts and $750 million aggregate principal amount of 6.75% senior unsecured
notes due 2022 that generated net proceeds of $728.6 million net of issuance discount and underwriting fees. The remainder of
that transaction was financed with borrowings under our senior secured credit facility.
We have reflected the financial results of the acquired business in our offshore pipeline transportation segment from the date
of acquisition. The purchase price has been allocated to the assets acquired and liabilities assumed based on estimated
preliminary fair values. Those fair values were developed by management with the assistance of a third-party valuation firm.
The purchase price allocation for this transaction has been finalized. Our finalized purchase price allocation remains unchanged
from what was disclosed in the financial statements included in our Annual Report on Form 10-K for the year ended December
31, 2016.
F-16
The allocation of the purchase price, as presented on our Consolidated Balance Sheet, is summarized as follows:
Cash
Accounts receivable
Inventories
Other current assets
Fixed assets
Intangible assets
Equity investees
Other assets
Accounts payable
Accrued liabilities
Other long-term liabilities
Noncontrolling interest
Total purchase price
$
1,270
29,768
600
10,432
1,225,685
79,050
352,535
1,966
(6,110)
(18,662)
(161,412)
6,447
$
1,521,569
Fixed assets identified in connection with our valuation and purchase price allocation includes crude oil pipelines,
natural gas pipelines and related assets. We will depreciate these assets on a straight line basis over estimated useful lives
ranging from 2 to 35 years depending on the nature of each asset.
Intangible assets identified in connection with our valuation and purchase price allocation 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 will amortize these intangible assets on a straight line basis over an estimated useful life
of 19 years.
In connection with our valuation and purchase price allocation, we have identified asset retirement obligations
("AROs") relating to the crude oil pipelines, natural gas pipelines and related assets with a preliminary fair value of $158.2
million. Of these AROs, $9.8 million of retirement costs were estimated to be incurred within the next year and thus were
included in accrued liabilities in the table above, as well as on our Consolidated Balance Sheet at December 31, 2015. The
remainder of the AROs recorded as a result of our Enterprise acquisition are included within "Other long-term liabilities" in the
table above, as well as on our Consolidated Balance Sheet. See further discussion of AROs assumed as a result of our Enterprise
acquisition in Note 6.
Noncontrolling interest as shown in the table above relates to the fair value assigned to the 20% ownership interest of
our joint venture partner in Independence Hub, LLC, a consolidated subsidiary acquired as a result of our Enterprise acquisition
in which we have an 80% ownership interest.
Our Consolidated Financial Statements include the results of our acquired offshore pipeline transportation business
since July 24, 2015, the effective closing date of the acquisition. The following table presents selected financial information
included in our Consolidated Financial Statements for the periods presented:
Revenues
Net income
Year Ended
December 31,
2015
$
$
101,444
58,805
The table below presents selected unaudited pro forma financial information incorporating the historical results of our
newly acquired offshore pipeline transportation assets. The pro forma financial information below has been prepared as if the
acquisition had been completed on January 1, 2015 and is based upon assumptions deemed appropriate by us and may not be
indicative of actual results. This pro forma information was prepared using historical financial data of the Enterprise offshore
pipelines and services businesses and reflects certain estimates and assumptions made by our management. Our unaudited pro
forma financial information is not necessarily indicative of what our consolidated financial results would have been had our
Enterprise acquisition been completed on January 1, 2015.
F-17
Pro forma consolidated financial operating results:
Revenues
Net Income Attributable to Genesis Energy L.P.
Basic and diluted earnings per unit:
As reported net income per unit
Pro forma net income per unit
Year Ended
December 31,
2015
2,421,989
425,363
4.09
3.91
$
$
$
$
As relating to our Enterprise acquisition, we incurred approximately $15 million in acquisition related costs through
December 31, 2015 and incurred an additional $1 million during the year ended December 31, 2016. Such costs are included as
"General and Administrative costs" on our Unaudited Condensed Consolidated Statement of Operations.
4. Receivables
Accounts receivable – trade, net consisted of the following:
Accounts receivable - trade
Allowance for doubtful accounts
Accounts receivable - trade, net
December 31,
2017
2016
$
$
503,917
(8,468)
495,449
$
$
231,187
(6,505)
224,682
The following table presents the activity of our allowance for doubtful accounts for the periods indicated:
Balance at beginning of period
Charged to costs and expenses
Amounts written off
Balance at end of period
5. Inventories
The major components of inventories were as follows:
Petroleum products
Crude oil
Caustic soda
NaHS
Raw materials - Alkali Operations
Work-in-process - Alkali Operations
Finished goods, net - Alkali Operations
Materials and supplies, net - Alkali Operations
Other
Total
2017
December 31,
2016
$
$
6,505
2,001
(38)
8,468
$
$
1,446
6,463
(1,404)
6,505
$
$
2015
2,973
1,242
(2,769)
1,446
December 31,
2017
2016
$
8,731
$
29,873
5,755
8,277
4,550
7,355
14,075
10,030
7
11,550
73,133
4,593
9,304
—
—
—
—
7
$
88,653
$
98,587
Inventories are valued at the lower of cost or net realizable value. The net realizable value of inventories were not
recorded below cost as of December 31, 2017 and December 31, 2016.
F-18
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.
6. Fixed Assets, Mineral Leaseholds and Asset Retirement Obligations
Fixed Assets
Fixed assets consisted of the following:
Crude oil pipelines and natural gas pipelines and related assets
Alkali facilities, machinery, and equipment
Onshore facilities, machinery, and equipment
Transportation equipment
Marine vessels
Land, buildings and improvements
Office equipment, furniture and fixtures
Construction in progress
Other
Fixed assets, at cost
Less: Accumulated depreciation
Net fixed assets
Mineral Leaseholds
December 31,
2017
2016
$
3,028,657
$
2,901,202
497,601
692,364
21,483
918,953
223,186
18,112
151,768
48,891
—
427,658
17,543
863,199
55,712
9,654
440,225
48,203
5,601,015
(734,986)
4,866,029
$
4,763,396
(548,532)
4,214,864
$
Our Mineral Leaseholds, as relating to our recently acquired Alkali Business, consist of the following:
Mineral leaseholds
Less: Accumulated depletion
Mineral leaseholds, net
December 31,
2017
566,019
(1,513)
564,506
$
Depreciation expense was $226.0 million, $194.0 million and $124.2 million for the years ended December 31, 2017,
2016, and 2015, respectively. Depletion expense was $1.5 million for the year ended December 31, 2017, with no similar
expense in 2016 and 2015.
During 2017, we sold certain non-core natural gas gathering and platform assets in the Gulf of Mexico included in our
offshore pipeline transportation services segment, as well as certain onshore terminal facilities in West Texas included in our
onshore facilities and transportation segment. These sales resulted in total gains on asset sales of $40.3 million for the year
ended December 31, 2017.
F-19
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, 2015
$
188,662
AROs arising from the acquisition and consolidation of a previously held equity method investment
Accretion expense
Revisions in timing and estimated costs of AROs
Settlements
December 31, 2016
Accretion expense
Revisions in timing and estimated costs of AROs
Acquisitions
Divestitures
Settlements
Other
December 31, 2017
20,940
10,800
(2,254)
(4,422)
213,726
11,008
7,146
131
(7,649)
(26,415)
240
$
198,187
At December 31, 2017 and December 31, 2016, $20.9 million and $22.4 million are included as current in "Accrued
liabilities" on our Consolidated Balance Sheet, respectively. The remainder of the ARO liability at each period is included in
"Other long-term liabilities" on our Consolidated Balance Sheet.
With respect to our AROs, the following table presents our forecast of accretion expense for the periods indicated:
2018
2019
2020
2021
2022
$
$
$
$
$
10,799
9,760
9,429
10,069
10,753
Certain of our unconsolidated affiliates have AROs recorded at December 31, 2017 relating to contractual agreements
and regulatory requirements. These amounts are immaterial to our Consolidated Financial Statements.
7. Net Investment in Direct Financing Leases
Our direct financing leases include a lease of the Northeast Jackson Dome (“NEJD”) Pipeline. Under the terms of the
agreement, we are paid quarterly payments, which commenced August 2008. These quarterly payments are fixed at
approximately $20.7 million per year during the lease term at an interest rate of 10.25%. At the end of the lease term in 2028,
we will convey all of our interests in the NEJD Pipeline to the lessee for a nominal payment. There are requirements in our
leases that would provide credit support should the credit rating of our lessee fall to certain levels, and at December 31, 2017,
the required credit support has been provided.
F-20
The following table lists the components of the net investment in direct financing leases:
December 31,
2017
2016
$
215,884
$
236,495
950
(83,918)
132,916
(7,633)
125,283
$
1,107
(97,822)
139,780
(6,921)
132,859
Total minimum lease payments to be received
Unamortized initial direct costs
Less unearned income
Net investment in direct financing leases
Less current portion (included in other current assets)
Long-term portion of net investment in direct financing leases
$
At December 31, 2017, minimum lease payments to be received for each of the five succeeding fiscal years are $20.7
million.
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, 2017 and 2016, the unamortized differences in
carrying value totaled $382.4 million and $398.1 million, respectively. We amortize the differences in carrying value as a
change in equity earnings.
As part of our Enterprise acquisition, we increased our ownership interest in each of Cameron Highway Oil Pipeline
Company ("CHOPS") and Southeast Keathley Canyon Pipeline Company, LLC ("SEKCO") from 50% to 100%. Consequently,
these entities were reflected as equity investees until July 24, 2015, at which point they became fully consolidated wholly
owned subsidiaries. Upon consolidation, we recorded a $332.4 million non-cash gain due to the step up in basis on our
historical interest.
Also, as part of our Enterprise acquisition, our ownership interest in Poseidon Oil Pipeline Company, LLC
("Poseidon") increased from 28% to 64%. We also acquired a 50% ownership interest in Deepwater Gateway, LLC and a
25.7% interest in Neptune Pipeline Company, LLC. These additional interests in Deepwater Gateway, LLC and Neptune
Pipeline Company, LLC were accounted for as equity investments from the acquisition date of July 24, 2015.
In the first quarter of 2016, we purchased the remaining 50% interest in Deepwater Gateway, LLC for approximately
$26.0 million (including adjustments for working capital), increasing our ownership interest to 100%. Consequently, we now
consolidate Deepwater Gateway, LLC instead of accounting for our interest under the equity method.
The following table presents information included in our Consolidated Financial Statements related to our equity
investees.
Genesis’ share of operating earnings
Amortization of differences attributable to Genesis' carrying value of
equity investments
Net equity in earnings
Distributions received
Year Ended December 31,
2017
2016
2015
66,814
$
63,805
$
17,157
(15,768)
51,046
82,898
$
$
(15,861)
47,944
87,220
$
$
37,293
54,450
97,468
$
$
$
F-21
The following tables present the combined balance sheet information for the last two years and income statement data
for the last three years for our equity investees (on a 100% basis) including the effects of the change in our ownership interest
due to the Enterprise and Deepwater acquisitions as previously discussed:
BALANCE SHEET DATA:
Assets
Current assets
Fixed assets, net
Other assets
Total assets
Liabilities and equity
Current liabilities
Other liabilities
Equity
Total liabilities and equity
INCOME STATEMENT DATA:
Revenues
Operating Income
Net Income
Poseidon's revolving credit facility
December 31,
2017
2016
$
$
$
$
34,381
$
362,214
14,927
411,522
23,289
249,610
138,623
$
$
411,522
$
35,375
365,563
3,177
404,115
23,928
230,327
149,860
404,115
Year Ended December 31,
2017
2016
2015
$
$
$
191,078
139,604
134,479
$
$
$
193,038
122,836
118,175
$
$
$
189,941
12,191
7,810
Borrowings under Poseidon’s revolving credit facilities, which was amended and restated in February 2015, are
primarily used to fund spending on capital projects. The February 2015 credit facility is non-recourse to Poseidon’s owners and
secured by its assets. The February 2015 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.
F-22
9. Intangible Assets, Goodwill and Other Assets
Intangible Assets
The following table reflects the components of intangible assets being amortized at December 31, 2017 and 2016:
December 31, 2017
December 31, 2016
Weighted
Amortization
Period in Years
Gross
Carrying
Amount
Accumulated
Amortization
Carrying
Value
Gross
Carrying
Amount
Accumulated
Amortization
Carrying
Value
Sodium Minerals and Sulfur Services:
Customer relationships
Licensing agreements
Non-compete agreement
Segment total
Onshore Facilities & Transportation:
Customer relationships
Intangibles associated with lease
Segment total
Marine contract intangible
Offshore pipeline contract intangibles
Other
Total
5
6
3
5
15
5
19
5
$ 94,654
$
92,493
$
2,161
$ 94,654
$
89,756
$
4,898
38,678
36,528
800
89
2,150
711
38,678
34,204
—
—
134,132
129,110
5,022
133,332
123,960
35,430
13,260
48,690
27,000
158,101
28,900
35,082
4,933
40,015
11,700
20,109
13,483
348
8,327
8,675
15,300
35,430
13,260
48,690
27,000
137,992
158,101
15,417
28,569
33,676
4,459
38,135
6,300
11,788
10,622
4,474
—
9,372
1,754
8,801
10,555
20,700
146,313
17,947
$396,823
$ 214,417
$182,406
$395,692
$ 190,805
$204,887
The licensing agreements referred to in the table above relate to the agreements we have with refiners to provide
services. The onshore facilities and transportation lease relates to a terminal facility in Shreveport, Louisiana. The marine
contract intangible relates to the contracts we assumed in the purchase of the M/T American Phoenix in November 2014.
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 identified in
connection with our purchase price allocation surrounding the Enterprise Acquisition.
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. Generally, the contribution to our cash flows of the customer and supplier relationships,
licensing agreements and trade name intangible assets is expected to decline over time, such that greater value is attributable to
the periods shortly after the acquisition was made. The onshore facilities and transportation lease, marine contract, offshore
pipeline contract intangibles and other intangible assets are being amortized on a straight-line basis. Amortization expense on
intangible assets was $23.6 million, $24.3 million and $20.0 million for the years ended December 31, 2017, 2016 and 2015,
respectively.
The following table reflects our estimated amortization expense for each of the five subsequent fiscal years:
Sodium Minerals and Sulfur Services:
Customer relationships
Licensing agreements
Non Compete
Onshore Facilities & Transportation:
Customer relationships
Intangibles associated with lease
Marine contract intangibles
Offshore pipeline contract intangibles
Other
Total
2018
2019
2020
2021
2022
$
2,161
$
— $
— $
— $
2,150
267
41
474
5,400
8,321
2,974
—
267
39
474
5,400
8,321
2,952
—
177
38
474
4,500
8,321
2,921
—
—
37
474
—
8,321
1,810
—
—
—
35
474
—
8,321
1,652
$
21,788
$
17,453
$
16,431
$
10,642
$
10,482
F-23
Goodwill
The carrying amount of goodwill by business segment at both December 31, 2017 and 2016 was $301.9 million in
sodium minerals and sulfur services and $23.1 million in onshore facilities and transportation. We have not recognized any
impairment losses related to goodwill for any of the periods presented.
Other Assets
Other assets consisted of the following:
CO2 volumetric production payments, net of amortization
Deferred marine charges, net (1)
Other deferred costs and deposits
Other assets, net of amortization
December 31,
2017
2016
$
$
2,175
$
30,246
24,207
56,628
$
3,503
27,710
25,398
56,611
(1) See discussion of deferred charges on marine transportation assets in the Summary of Accounting Policies (Note 2)
The CO2 assets are being amortized on a units-of-production method. We recorded amortization of $1.3 million in
2017, $3.9 million in 2016 and $5.9 million in 2015.
10. Debt
At December 31, 2017 and 2016, our obligations under debt arrangements consisted of the following:
December 31, 2017
December 31, 2016
Unamortized
Discount and
Debt Issuance
Costs
Principal
Net Value
Principal
Unamortized
Discount and
Debt Issuance
Costs
Net Value
$1,099,200
$
— $ 1,099,200
$1,278,200
$
— 1,278,200
145,170
750,000
400,000
350,000
550,000
450,000
$3,744,370
$
$
1,303
16,077
5,691
5,717
9,462
8,002
143,867
733,923
394,309
344,283
540,538
441,998
350,000
750,000
400,000
350,000
—
—
4,163
19,296
6,758
6,614
—
—
345,837
730,704
393,242
343,386
—
—
46,252
$ 3,698,118
$3,128,200
$
36,831
$3,091,369
Senior secured credit facility
5.750% senior unsecured notes
6.750% senior unsecured notes
6.000% senior unsecured notes
5.625% senior unsecured notes
6.500% senior unsecured notes
6.250% senior unsecured notes
Total long-term debt
Senior Secured Credit Facility
In July 2017, we amended our credit agreement to, among other things, make certain technical amendments related to
the financing of our acquisition of our Alkali Business. The key terms for rates under our $1.7 billion senior secured credit
facility, which are dependent on our leverage ratio (as defined in the credit agreement), are as follows:
• The interest rate on borrowings may be based on an alternate base rate or a Eurodollar rate, at our option. The alternate
base rate is equal to the sum of (a) the greatest of (i) the prime rate as established by the administrative agent for the
credit facility, (ii) the federal funds effective rate plus 0.5% of 1% and (iii) the LIBOR rate for a one-month maturity
plus 1% and (b) the applicable margin. The Eurodollar rate is equal to the sum of (a) the LIBOR rate for the applicable
interest period multiplied by the statutory reserve rate and (b) the applicable margin. The applicable margin varies
from 1.50% to 3.00% on Eurodollar borrowings and from 0.50% to 2.00% on alternate base rate borrowings,
depending on our leverage ratio. Our leverage ratio is recalculated quarterly and in connection with each material
acquisition. At December 31, 2017, the applicable margins on our borrowings were 1.75% for alternate base rate
borrowings and 2.75% for Eurodollar rate borrowings.
• Letter of credit fees range from 1.50% to 3.00% based on our leverage ratio as computed under the credit facility. The
rate can fluctuate quarterly. At December 31, 2017, our letter of credit rate was 2.75%.
F-24
• We pay a commitment fee on the unused portion of the $1.7 billion maximum facility amount. The commitment fee on
the unused committed amount will range from 0.25% to 0.50% per annum depending on our leverage ratio (0.50% at
December 31, 2017).
• Our credit facility contains a $300 million accordion feature, giving us the ability to expand the size of the facility up
to $2.0 billion for acquisitions or growth projects, subject to lender consent.
Our credit facility contains customary covenants (affirmative, negative and financial) that could limit the manner in
which we may conduct our business. As defined in our credit facility, we are required to meet three primary financial metrics—
a maximum leverage ratio, a maximum senior secured leverage ratio and a minimum interest coverage ratio. Our credit
agreement provides for the temporary inclusion of certain pro forma adjustments to the calculations of the required ratios
following material acquisitions. In general, our leverage ratio calculation compares our consolidated funded debt (including
outstanding notes we have issued) to EBITDA (as defined and adjusted in accordance with the credit facility) and cannot
exceed 5.75 to 1.00. Our senior secured leverage ratio excludes outstanding debt under senior unsecured notes and cannot
exceed 3.75 to 1.00. Our interest coverage ratio calculation compares EBITDA (as defined and adjusted in accordance with the
credit facility) to interest expense and must be greater than 3.00 to 1.00 (2.75 to 1.00 during an acquisition period).
At December 31, 2017, we had $1.1 billion borrowed under our credit facility, with $29.0 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 $1.0 million was outstanding at December 31, 2017. Due to the revolving nature of loans
under our credit facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date
of May 9, 2022. The total amount available for borrowings under our credit facility at December 31, 2017 was $599.8 million.
Our credit facility does not include a “borrowing base” limitation except with respect to our inventory loans.
Senior Unsecured Notes
On February 8, 2013, we issued $350 million of aggregate principal amount of 5.75% senior unsecured notes due
February 15, 2021 (the "2021 Notes"). Our 2021 Notes were sold at face value. Interest payments are due on February 15 and
August 15 of each year. Our 2021 Notes mature on February 15, 2021. The net proceeds were used to repay borrowings under
our credit facility and for general partnership purposes. On December 11, 2017, $204.8 million of these notes were validly
tendered and repaid upon the issuance of our $450 million unsecured notes issued on December 11, 2017 as discussed below. A
total loss of approximately $6.2 million for the tender is recorded to "Other income/(expense), net" in our Consolidated
Statements of Operations. The remaining principal balance on these notes as of December 31, 2017 is $145.2 million, which is
expected to be fully redeemed on February 15, 2018.
On May 15, 2014, we issued $350 million in aggregate principal amount of 5.625% senior unsecured notes due
December 15, 2014 (the "2024 Notes"). Our 2024 Notes were sold at face value. Interest payments are due on June 15 and
December 15 of each year with the initial interest payment due December 15, 2014. Our 2024 Notes mature on June 15, 2024.
The net proceeds were used to repay borrowings under our credit facility and for general partnership purposes.
On May 21, 2015, we issued $400 million in aggregate principal amount of 6.0% senior unsecured notes due May 15,
2023 (the "2023 Notes"). Interest payments are due on May 15 and November 15 of each year with the initial interest payment
due November 15, 2015. Our 2023 Notes mature on May 15, 2023. We used a portion of the proceeds from those notes to
effectively redeem all of our outstanding $350 million, 7.875% senior unsecured notes due 2018, using a combination of public
tender offer and our redemption rights relating to those notes. The aggregate principal amount of the 7.875% notes totaling
$300.1 million were tendered and the remaining $49.9 million were redeemed in full. A total loss of approximately $19.2
million for the tender and redemption of notes is recorded to "Other income/(expense), net" in our Consolidated Statements of
Operations.
On July 23, 2015, we issued $750 million in aggregate principal amount of 6.75% senior unsecured notes due
August 1, 2022 (the "2022 Notes"). Interest payments are due on February 1 and August 1 of each year with the initial interest
payment due February 1, 2016. Our 2022 Notes mature on August 1, 2022. That issuance generated net proceeds of $728.6
million net of issuance discount and underwriting fees. The net proceeds were used to fund a portion of the purchase price for
our Enterprise acquisition.
On August 14, 2017, we issued $550 million in aggregate principal amount of 6.50% senior unsecured notes due
October 1, 2025 (the "2025 Notes"). Interest payments are due April 1 and October 1 of each year with the initial interest
payment due April 1, 2018. That issuance generated net proceeds of $540.1 million, net of issuance costs incurred. Our 2025
Notes mature on October 1, 2025. The net proceeds were used to fund a portion of the purchase price for our acquisition of our
Alkali Business.
F-25
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 $442.0 million, net of issuance costs incurred. Our 2026
Notes mature on May 15, 2026. The net proceeds were used to redeem a portion of our outstanding principal on the 5.75%
senior unsecured notes due 2021. Of the net proceeds, $204.8 million were used to redeem the portion of the 5.75% senior
unsecured notes that were validly tendered, and the remaining balance was used for repaying a portion of the borrowings
outstanding under our revolving credit facility. In addition, in January 2018 we called for the redemption of our remaining 2021
Notes. Refer to Note 25 where we discuss our subsequent events.
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
2021 Notes
2022 Notes
2023 Notes
2024 Notes
2025 Notes
2026 Notes
February 15,
2017
August 1,
2018
May 15,
2018
June 15,
2019
October 1,
2020
February 15,
2021
February 15,
2017
August 1,
2018
May 15,
2018
June 15,
2019
October 1,
2020
February 15,
2021
Guarantees of our 2021, 2022, 2023, 2024, 2025 and 2026 Notes will be released under certain circumstances,
including (i) in connection with any sale or other disposition of (a) all or substantially all of the properties or assets of a
guarantor (including by way of merger or consolidation) or (b) all of the capital stock of such guarantor, in each case, to a
person that is not a restricted subsidiary of the Partnership (ii) if the Partnership designates any restricted subsidiary that is a
guarantor as an unrestricted subsidiary, (iii) upon legal defeasance, covenant defeasance or satisfaction and discharge of the
applicable indenture, (iv) upon the liquidation or dissolution of such guarantor, or (v) at such time as such guarantor ceases to
guarantee any other indebtedness of either of the issuers and any other guarantor.
Covenants and Compliance
Our credit agreement and the indenture governing the senior notes contain cross-default provisions. Our credit
documents prohibit distributions on, or purchases or redemptions of, units if any default or event of default is continuing. In
addition, those agreements contain various covenants limiting our ability to, among other things:
•
•
•
•
incur indebtedness if certain financial ratios are not maintained;
grant liens;
engage in sale-leaseback transactions; and
sell substantially all of our assets or enter into a merger or consolidation.
A default under our credit documents would permit the lenders thereunder to accelerate the maturity of the outstanding
debt. As long as we are in compliance with our credit facility, our ability to make distributions of “available cash” is not
restricted. As of December 31, 2017, we were in compliance with the financial covenants contained in our credit facility and
indenture.
11. Partners’ Capital, Mezzanine Equity and Distributions
At December 31, 2017, 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.
F-26
Distributions
Generally, we will distribute 100% of our available cash (as defined by our partnership agreement) within 45 days
after the end of each quarter to unitholders of record. Available cash generally means, for each fiscal quarter, all cash on hand at
the end of the quarter:
•
less the amount of cash reserves that our general partner determines in its reasonable discretion is necessary or
appropriate to:
•
•
•
provide for the proper conduct of our business;
comply with applicable law, any of our debt instruments, or other agreements; or
provide funds for distributions to our unitholders for any one or more of the next four quarters;
•
plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital
borrowings. Working capital borrowings are generally borrowings that are made under our credit facility and in all
cases are used solely for working capital purposes or to pay distributions to partners.
We paid distributions in 2018, 2017 and 2016 as follows:
Distribution For
2015
4th Quarter
2016
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
2017
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
Date Paid
Per Unit Amount
Total Amount
February 12, 2016
May 13, 2016
August 12, 2016
November 14, 2016
February 14, 2017
May 15, 2017
August 14, 2017
November 14, 2017
February 14, 2018
$
$
$
$
$
$
$
$
$
0.6550
0.6725
0.6900
0.7000
0.7100
0.7200
0.7225
0.5000
0.5100
$
$
$
$
$
$
$
$
$
72,036
73,961
81,406
82,585
83,765
88,257
88,563
61,290
62,515
Equity Issuances and Contributions
Our partnership agreement authorizes our general partner to cause us to issue additional limited partner interests and
other equity securities, the proceeds from which could be used to provide additional funds for acquisitions or other needs.
On March 24, 2017, we issued 4,600,000 Class A common units in a public offering at a price of $30.65 per unit,
which included the exercise by the underwriters of an option to purchase up to 600,000 additional common units from us. We
received proceeds, net of offering costs, of approximately $140.5 million from that offering.
On July 27, 2016, we issued 8,000,000 Class A common units in a public offering at a price of $37.90 per unit. We
received proceeds, net of underwriting discounts and offering costs, of approximately $298.0 million from that offering. We
used those proceeds to repay a portion of the borrowings outstanding under our credit facility.
On July 22, 2015, we issued 10,350,000 Class A common units in a public offering at a price of $43.77 per unit, which
included the exercise by the underwriters of an option to purchase up to 1,350,000 additional common units from us. We
received proceeds, net of underwriting discounts and offering costs, of approximately $437.2 million from that offering. We
used the net proceeds to fund a portion of the purchase price for our Enterprise acquisition.
On April 10, 2015, we issued 4,600,000 Class A common units in a public offering at a price of $44.42 per unit, which
included the exercise by the underwriters of an option to purchase up to 600,000 additional common units from us. We received
proceeds, net of underwriting discounts and offering costs, of approximately $198.2 million from that offering. We used the net
proceeds for general partnership purposes, including the repayment of a portion of the borrowings outstanding under our credit
facility.
The new common units issued in 2017, 2016 and 2015 to the public for cash were as follows:
F-27
Period
March 2017
July 2016
July 2015
April 2015
Purchaser of
Common Units
Public
Public
Public
Public
Units
Gross
Unit Price
Issuance Value
Costs
Net Proceeds
4,600
8,000
10,350
4,600
$
$
$
$
30.65
37.90
43.77
44.42
$
$
$
$
140,990
303,200
453,020
204,332
$
$
$
$
(477) $
(4,748) $
(15,856) $
(6,164) $
140,513
298,452
437,164
198,168
Class A Convertible Preferred Units
On September 1, 2017, we sold $750 million of Class A convertible preferred units ("preferred units") in a private
placement, comprised of 22,249,494 units for a cash purchase price per unit of $33.71 (subject to certain adjustments,
the “Issue Price”) to two initial purchasers. Our general partner executed an amendment to our partnership agreement in
connection therewith, which, among other things, authorized and established the rights and preferences of our preferred units.
Our preferred units are a new class of security that ranks senior to all of our currently outstanding classes or series of limited
partner interests with respect to distribution and/or liquidation rights. Holders of our preferred units vote on an as-converted
basis with holders of our common units and have certain class voting rights, including with respect to any amendment to the
partnership agreement that would adversely affect the rights, preferences or privileges, or otherwise modify the terms, of those
preferred units.
Each of our preferred units accumulate quarterly distribution amounts in arrears at an annual rate of 8.75% (or
$2.9496), yielding a quarterly rate of 2.1875% (or $0.7374), subject to certain adjustments. With respect to any quarter ending
on or prior to March 1, 2019, we have the option to pay to the holders of our preferred units the applicable distribution amount
in cash, preferred units, or any combination thereof. If we elect to pay all or any portion of a quarterly distribution amount in
preferred units, the number of such preferred units will equal the product of (i) the number of then outstanding preferred units
and (ii) the quarterly rate. We have elected to pay the distribution amount attributable to the quarter ended on September 30,
2017 in preferred units. For each quarter ending after March 1, 2019, we must pay all distribution amounts in respect of our
preferred units in cash.
From time to time after September 1, 2020, we will have the right to cause the conversion of all or a portion of
outstanding preferred units into our common units, subject to certain conditions; provided, however, that we will not be
permitted to convert more than 7,416,498 of our preferred units in any consecutive twelve-month period. At any time after
September 1, 2020, if we have fewer than 592,768 of our preferred units outstanding, we will have the right to convert each
outstanding preferred unit into our common units at a conversion rate equal to the greater of (i) the then-applicable conversion
rate and (ii) the quotient of (a) the Issue Price and (b) 95% of the volume-weighted average price of our common units for the
30-trading day period ending prior to the date that we notify the holders of our outstanding preferred units of such conversion.
Upon certain events involving certain changes of control in which more than 90% of the consideration payable to the
holders of our common units is payable in cash, our preferred units will automatically convert into common units at a
conversion ratio equal to the greater of (a) the then applicable conversion rate and (b) the quotient of (i) the product of (A) the
sum of (1) the Issue Price and (2) any accrued and accumulated but unpaid distributions on our preferred units, and (B) a
premium factor (ranging from 115% to 101% depending on when such transaction occurs) plus a prorated portion of unpaid
partial distributions, and (ii) the volume weighted average price of the common units for the 30 trading days prior to the
execution of definitive documentation relating to such change of control.
In connection with other change of control events that do not meet the 90% cash consideration threshold described
above, each holder of our preferred units may elect to (a) convert all of its preferred units into our common units at the then
applicable conversion rate, (b) if we are not the surviving entity (or if we are the surviving entity, but our common units will
cease to be listed), require us to use commercially reasonable efforts to cause the surviving entity in any such transaction to
issue a substantially equivalent security (or if we are unable to cause such substantially equivalent securities to be issued, to
convert its preferred units into common units in accordance with clause (a) above or exchanged in accordance with clause (d)
below or convert at a specified conversion rate), (c) if we are the surviving entity, continue to hold our preferred units or (d)
require us to exchange our preferred units for cash or, if we so elect, our common units valued at 95% of the volume-weighted
average price of our common units for the 30 consecutive trading days ending on the fifth trading day immediately preceding
the closing date of such change of control, at a price per unit equal to the sum of (i) the product of (x) 101% and (y) the Issue
Price plus (ii) accrued and accumulated but unpaid distributions and (iii) a prorated portion of unpaid partial distributions.
For a period of 30 days following (i) September 1, 2022 and (ii) each subsequent anniversary thereof, the holders of
our preferred units may make a one-time election to reset the quarterly distribution amount (a “Rate Reset Election”) to a cash
amount per preferred unit equal to the amount that would be payable per quarter if a preferred unit accrued interest on the Issue
F-28
Price at an annualized rate equal to three-month LIBOR plus 750 basis points; provided, however, that such reset rate shall be
equal to 10.75% if (i) such alternative rate is higher than the LIBOR-based rate and (ii) the then market price for our common
units is then less than 110% of the Issue Price. To become effective, the Rate Reset Election requires approval of holders of at
least a majority of our then outstanding preferred units and such majority must include each of our initial purchasers (or any
affiliate to whom they have transferred their preferred units) if such initial purchaser (including its affiliates) holds at least 25%
of the then outstanding preferred units.
Upon the occurrence of a Rate Reset Election, we may redeem our preferred units for cash, in whole or in part (subject
to certain minimum value limitations) for an amount per preferred unit equal to such preferred unit’s liquidation value (equal to
the Issue Price plus any accrued and accumulated but unpaid distributions, plus a prorated portion of certain unpaid partial
distributions in respect of the immediately preceding quarter and the current quarter) multiplied by (i) 110%, prior to
September 1, 2024, and (ii) 105% thereafter. Each holder of our preferred units may elect to convert all or any portion of its
preferred units into common units initially on a one-for-one basis (subject to customary adjustments and an adjustment for
accrued and accumulated but unpaid distributions and limitations) at any time after September 1, 2019 (or earlier upon a
change of control, liquidation, dissolution or winding up), provided that any conversion is for at least $50 million or such lesser
amount if such conversion relates to all of a holder’s remaining preferred units or has otherwise been approved by us.
If we fail to pay in full any preferred unit distribution amount after March 1, 2019 in respect of any two quarters,
whether or not consecutive, then until we pay such distributions in full, we will not be permitted to (a) declare or make any
distributions (subject to a limited exceptions for pro rata distributions on our preferred units and parity securities), redemptions
or repurchases of any of our limited partner interests that rank junior to or pari passu with our preferred units with respect to
rights upon distribution and/or liquidation (including our common units), or (b) issue any such junior or parity securities. If we
fail to pay in full any preferred unit distribution after March 1, 2019 in respect of any two quarters, whether or not consecutive,
then the preferred unit distribution amount will be reset to a cash amount per preferred unit equal to the amount that would be
payable per quarter if a preferred unit accrued interest on the Issue Price at an annualized rate equal to the then-current
annualized distribution rate plus 200 basis points until such default is cured.
In addition to their right to veto a Rate Reset Election under certain circumstances, we have granted each initial
purchaser (including its applicable affiliate transferees) certain rights, including (i) the right to appoint an observer, who shall
have the right to attend our board meetings for so long as an initial purchaser (including its affiliates) owns at least $200 million
of our preferred units; (ii) the right to purchase up to 50% of any parity securities on substantially the same terms offered to
other purchasers for so long as an initial purchaser (including its affiliates) owns at least 11,124,747 of our preferred units, and
(iii) the right to appoint two directors to our general partner’s board of directors if (and so long as) we fail to pay in full any
three quarterly distribution amounts, whether or not consecutive, attributable to any quarter ending after March 1, 2019.
The Rate Reset Election of these preferred units represents an embedded derivative that must be bifurcated from the
related host contract and recorded at fair value on our Consolidated Balance Sheet. See further information in Note 18. The
preferred units themselves are classified as mezzanine capital on our Consolidated Balance Sheet.
Accounting for the Class A Convertible Preferred Units
The preferred units are considered redeemable securities under GAAP due to the existence of redemption provisions
upon a deemed liquidation event which is outside of the Partnership's control. Therefore, they are presented as temporary
equity in the mezzanine section of the Consolidated Balance Sheet. The preferred units have been recorded at their issuance
date fair value, net of issuance costs. As the preferred units are not currently redeemable and the Partnership does not have
plans or expect any events which constitute a change of control in the agreement, adjustment to the initial carrying amount is
not necessary and would only be required if it becomes probable that the preferred units would become redeemable.
Initial Measurement
The preferred units were initially recognized at their issuance date fair value, net of issuance costs. As discussed
above, a portion of the net proceeds were allocated to the Preferred Distribution Rate Reset Election and recorded in Other long
term liabilities on the Consolidated Balance Sheet as described below:
F-29
Transaction price, gross
Transaction cost to other third parties
Transaction price, net
Allocation of Net Transaction Price
Preferred Units, net
Preferred Distribution Rate Reset Election (Note 18)
Year Ended December 31,
2017
750,000
(23,581)
726,419
691,969
34,450
726,419
Subsequent Measurement
As discussed above, subsequent adjustment of the preferred units will not occur until it becomes probable that they
would become redeemable. Once redemption becomes probable, the carrying amount of the preferred units would be adjusted
to the redemption value over a period of time comprising the date the feature first becomes probable and the date the units can
first be redeemed.
Preferred unit distributions are recognized on the date in which they are declared. In November 2017, we declared a
$5.5 million distribution on the preferred units from September 1, 2017 (date of issuance) to September 30, 2017. This
distribution was 100% paid in kind through the issuance of 162,234 additional preferred units. The following table shows the
change in our Class A Convertible Preferred Units from initial measurement at September 1, 2017 to December 31, 2017:
Balance as of December 31, 2016
Issuance of Preferred Units, net
Allocation to Preferred Distribution Rate Reset Election (Note 18)
Distribution paid-in-kind
Allocation of Distribution paid-kind to Preferred Distribution Rate Reset
Election (Note 18)
Balance as of December 31, 2017
Balance as of December 31, 2016
Issuance of Preferred Units
Distribution paid-in-kind
Balance as of December 31, 2017
Year Ended December 31,
2017
—
726,419
(34,450)
5,469
(287)
697,151
Year Ended December 31,
2017
—
22,249,494
162,234
22,411,728
Net income attributable to common unitholders is reduced by Preferred Unit distributions that accumulated during the
period. During 2017, net income attributable to common unitholders was reduced by $22 million as a result of distributions
that accumulated during the period. With respect to our Class A Convertible Preferred Units relating to the fourth quarter of
2017, we declared a payment-in-kind ("PIK") of the quarterly distribution, which resulted in the issuance of an additional
490,252 Class A Convertible Preferred Units. This PIK amount equates to a distribution of $0.7374 per Class A Convertible
Preferred Unit for the 2017 Quarter, or $2.9496 annualized. These distributions were paid on February 14, 2018 to unitholders
holders of record at the close of business January 31, 2018.
F-30
12. Net Income Per Common Unit
Basic net income per common unit is computed by dividing net income, after considering income attributable to our
Class A preferred unitholders, by the weighted average number of common units outstanding.
The dilutive effect of the Class A Convertible Preferred units is calculated using the if-converted method. Under the
if-converted method, the Class A Preferred units are assumed to be converted at the beginning of the period (beginning with
their respective issuance date), and the resulting common units are included in the denominator of the diluted net income per
common unit calculation for the period being presented. Distributions declared in the period and undeclared distributions that
accumulated during the period are added back to the numerator for purposes of the if-converted calculation. For the year ended
December 31, 2017, the effect of the assumed conversion of the 22,411,728 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 and weighted average units used in computing basic and diluted net income
per common unit (in thousands, except per unit amounts):
Net Income Attributable to Genesis Energy L.P.
Less: Accumulated distributions attributable to Class A Convertible
Preferred Units
Net Income Available to Common Unitholders
Weighted Average Outstanding Units
Basic and Diluted Net Income per Common Unit
Year Ended
December 31,
2017
2016
2015
82,647
$
113,249
$
422,528
(21,995)
60,652
—
—
$
113,249
$
422,528
121,546
113,433
103,004
0.50
$
1.00
$
4.10
$
$
$
13. Business Segment Information
Our operations consist of four operating segments (see Note 1 for discussion of segment reporting change):
• 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, sodium hydrosulfide (or “NaHS,” commonly pronounced "nash");
• Onshore Facilities and Transportation – terminaling, blending, storing, marketing, and transporting crude oil,
petroleum products (primarily fuel oil, asphalt, and other heavy refined products), and CO2; and
• Marine Transportation – marine transportation to provide waterborne transportation of petroleum products and crude
oil throughout North America.
Substantially all of our revenues are derived from, and substantially all of our assets are located in, the United States.
We define Segment Margin as revenues less product costs, operating expenses (excluding non-cash charges, such as
depreciation and amortization), and segment general and administrative expenses, plus our equity in distributable cash
generated by our equity investees. In addition, our Segment Margin definition excludes the non-cash effects of our legacy stock
appreciation rights plan and includes the non-income portion of payments received under direct financing leases.
Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety
of measures including Segment Margin, segment volumes, where relevant, and capital investment.
F-31
Segment information for each year presented below is as follows:
Offshore
Pipeline
Transportation
Sodium
Minerals &
Sulfur Services
Onshore
Facilities &
Transportation
Marine
Transportation
Total
317,540
$
130,333
8,815
$ 1,354,469
$
$
96,376
149,123
Year Ended December 31, 2017
Segment Margin (a)
Capital expenditures (b)
Revenues:
External customers
Intersegment (c)
$
$
$
Total revenues of reportable segments $
Year Ended December 31, 2016
Segment Margin (a)
Capital expenditures (b)
Revenues:
$
$
External customers
Intersegment (c)
Total revenues of reportable segments $
Year Ended December 31, 2015
Segment Margin (a)
Capital expenditures (b)
Revenues:
$
319,455
(1,216)
318,239
336,620
46,277
$
332,514
2,165
334,679
197,723
$ 1,527,320
External customers
Intersegment (c)
$
140,230
—
Total revenues of reportable segments $
140,230
$
$
$
$
$
$
$
$
$
$
$
$
50,294
$
594,543
68,414
$ 1,580,821
194,050
$ 2,028,377
11,237
$
—
205,287
$ 2,028,377
70,079
78,804
$
$
569,571
443,993
206,211
$ 1,712,493
6,810
213,021
—
$
$ 1,712,493
103,222
$
476,585
69,009
$ 2,007,611
230,192
$ 2,246,529
8,565
$
—
238,757
$ 2,246,529
$
$
$
$
$
$
$
$
$
$
470,789
(8,167)
462,622
$ 1,044,083
(1,854)
$ 1,042,229
79,508
2,274
180,665
(9,162)
171,503
80,246
1,595
$
$
$
$
$
$
83,364
316,638
993,103
187
993,290
95,394
409,687
187,257
(9,377)
177,880
$ 1,688,850
812
$ 1,689,662
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,
2017
2,486,803
December 31,
2016
2,575,335
December 31,
2015
2,623,478
1,848,188
395,043
394,626
1,927,976
1,875,403
1,615,335
824,777
49,737
813,722
43,089
777,952
48,208
$ 7,137,481
$ 5,702,592
$ 5,459,599
(a) A reconciliation of total Segment Margin to net income attributable to Genesis Energy, L.P. for each year is presented
below.
(b) Capital expenditures include maintenance and growth capital expenditures, such as fixed asset additions (including
enhancements to existing facilities and construction of growth projects) as well as acquisitions of businesses and
contributions to equity investees related to same. In addition to construction of growth projects, capital spending in our
sodium minerals and sulfur services segment included $1.3 billion during the year ended December 31, 2017 related to
the acquisition of our Alkali Business. During the year ended December 31, 2016, capital expenditures in our offshore
pipeline transportation segment included $35.1 million related to the acquisition of the remaining 50% ownership in
Deepwater Gateway. Additionally, in 2015, there was $1.5 billion in capital spending to fund our Enterprise
acquisition. Capital spending in this segment also included $2.5 million during the year ended December 31, 2015
representing capital contributions to our SEKCO pipeline to fund our share of the construction costs for its pipeline (as
prior to our Enterprise acquisition in July 2015, we owned a 50% interest in the SEKCO pipeline with Enterprise
owning the remaining 50%).
(c) Intersegment sales were conducted under terms that we believe were no more or less favorable than then-existing
market conditions.
F-32
Reconciliation of total Segment Margin to net income attributable to Genesis Energy, L.P.:
Total Segment Margin
Corporate general and administrative expenses
Depreciation, depletion, amortization and accretion
Interest expense
Adjustment to exclude distributable cash generated by equity investees
not included in income and include equity in investees net income (1)
Non-cash items not included in Segment Margin
Cash payments from direct financing leases in excess of earnings
Gain on step up of historical basis
Loss on extinguishment of debt
Differences in timing of cash receipts for certain contractual
arrangements (2)
Gain on sales of assets
Other, net
Non-cash provision for leased items no longer in use
Income tax expense
Net income attributable to Genesis Energy, L.P.
Year Ended
December 31,
2016
$ 569,571
(40,905)
(230,563)
(139,947)
2017
$ 594,543
(60,029)
(262,021)
(176,762)
2015
$ 476,585
(61,370)
(155,081)
(100,596)
(31,852)
(14,305)
(6,921)
—
(6,242)
17,540
40,311
(2,985)
(12,589)
3,959
82,647
$
(39,276)
(3,221)
(6,277)
—
—
(43,018)
2,809
(5,685)
332,380
(19,225)
13,253
—
(6,044)
—
(3,342)
$ 113,249
6,359
—
(6,643)
—
(3,987)
$ 422,528
(1) Includes distributions attributable to the period and received during or promptly following such period.
(2) Certain cash payments received from customers under certain of our minimum payment obligation contracts are not recognized as
revenue under GAAP in the period in which such payments are received.
14. Transactions with Related Parties
Transactions with related parties were as follows:
Year Ended December 31,
2017
2016
2015
Revenues:
Sales of CO2 to Sandhill Group, LLC (1)
Revenues from services and fees to Poseidon Oil Pipeline Company, LLC (2)
Revenues from product sales to ANSAC
$
2,820
$
3,097
$
12,357
124,536
10,844
—
3,259
4,536
—
Expenses:
Amounts paid to our CEO in connection with the use of his aircraft
Charges for products purchased from Poseidon Oil Pipeline Company, LLC (2)
Charges for services from ANSAC
$
$
660
986
2,242
$
660
1,007
—
690
464
—
(1) We own a 50% interest in Sandhill Group, LLC.
(2) We own a 64% interest in Poseidon Oil Pipeline Company, LLC.
Our CEO, Mr. Sims, owns an aircraft which is used by us for business purposes in the course of operations. We pay
Mr. Sims a fixed monthly fee and reimburse the aircraft management company for costs related to our usage of the aircraft,
including fuel and the actual out-of-pocket costs. Based on current market rates for chartering of private aircraft under long-
term, priority arrangements with industry recognized chartering companies, we believe that the terms of this arrangement are
no worse than what we could have expected to obtain in an arms-length transaction.
F-33
Transactions with Unconsolidated Affiliates
Poseidon
As part of our Enterprise acquisition, we became the operator of Poseidon in the third quarter of 2015. We provide
management, administrative and pipeline operator services to Poseidon under an Operation and Management Agreement .
Currently, that agreement renews automatically annually unless terminated by either party (as defined in the agreement). Our
revenues for the years ended December 31, 2017, 2016 and 2015 reflect $8.4 million, $7.9 million and $3.9 million,
respectively, of fees we earned through the provision of services under that agreement. At December 31, 2017, and 2016,
Poseidon Oil Pipeline Company, LLC owed us $2.2 million and $1.6 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.
Net sales to ANSAC were $124.5 million during the period September 1, 2017 to December 31, 2017. The costs
charged to us by ANSAC, included in operating costs, were $2.2 million during the period September 1, 2017 to December 31,
2017.
As of December 31, 2017, our receivables from and payables to ANSAC were:
Receivables:
ANSAC
Payables:
ANSAC
December 31
2017
$
$
74,490
1,223
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.
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,
2017
2016
2015
$
$
(140,948) $
49,055
(3,622)
(410)
(9,859) $
(54,361)
(3,902)
3,059
99,384
3,811
(11,916)
6,417
97,569
8,512
10,156
$
(17,426)
(8,161)
(90,650) $
(101,581)
9,257
5,372
Payments of interest and commitment fees were $168.3 million, $157.4 million and $86.8 million during the years
ended December 31, 2017, 2016 and 2015, respectively. We capitalized interest of $15.0 million, $26.6 million and $17.1
million during the years ended December 31, 2017, 2016 and 2015.
F-34
During the years ended December 31, 2017, 2016 and 2015, we paid taxes of $1.0 million, $1.3 million and $0.9
million.
At December 31, 2017, 2016 and 2015, we had incurred liabilities for fixed and intangible asset additions totaling
$39.7 million, $33.7 million and $68.6 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.
During the year ended December 31, 2015, as a result of our Enterprise acquisition, we acquired the 50% ownership
interest in each of CHOPS and SEKCO as previously held by Enterprise, resulting in 100% ownership interest by us in each of
these subsidiaries. As a result, we recorded a one-time $332.4 million non-cash gain from the step up in basis in our historical
50% ownership interest in each of CHOPS and SEKCO to fair value (resulting from the fair value assigned to the 50%
ownership interest in each of CHOPS and SEKCO that we acquired from Enterprise, as derived from the preliminary purchase
price allocation). This also results in the consolidation of CHOPS and SEKCO by us, resulting in the inclusion of the operating
assets and liabilities on our Consolidated Balance Sheet. As 50% of the operating assets and liabilities of CHOPS and SEKCO
were based on our historical interest with no cash impact, these amounts relating to our historical interest were not included in
net changes in components of operating assets and liabilities in the Consolidated Statements of Cash Flows in 2015.
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 LTIP is adjusted to recognize changes in the estimated compensation cost and
vesting. Management’s estimates of the fair value of these awards granted in 2017 are adjusted for assumptions about expected
forfeitures of units prior to vesting. For our performance-based awards, our fair value estimates are weighted based on
probabilities for each performance condition applicable to the award.
During 2017, we granted 297,214 phantom units with tandem DERs at a weighted average grant fair value of $32.37
per unit. During 2016, we granted 339,584 phantom units with tandem DERs at a weighted average grant date fair value of
$30.71 per unit. The phantom units granted during 2017 and 2016 were both service-based and performance-based awards. The
service-based awards vest on the third anniversary of the date of grant. Performance-based phantom unit awards granted in
2016 and 2017 will vest on the third anniversary of issuance, in an amount ranging from 50% to 150% of the targeted number
of phantom units, if certain quarterly cash distribution per common unit targets are achieved in the fourth quarter of 2019 and
2020, respectively. If the quarterly cash distribution per common unit is below the threshold target, all of the performance-
based phantom units granted will be forfeited.
During 2015, we granted 212,825 phantom units with tandem DERs at a weighted average grant date fair value of
$44.95 per unit. These phantom units are expected to be forfeited as the distribution per common unit is below the minimum
target threshold.
A summary of our phantom unit activity for our service-based and performance-based awards is set forth below:
F-35
Service-Based Awards
Performance-Based Awards
Number of
Phantom
Units
Average
Grant
Date Fair
Value
Total
Value
(in thousands)
Number of
Phantom
Units
Average
Grant
Date Fair
Value
Total
Value
(in thousands)
40.59
$
7,356
483,232
$
38.82
$
18,757
Unvested at December 31, 2016
Granted
Forfeited
Settled
181,230
102,868
$
$
(3,402) $
(40,859) $
32.27
37.22
53.84
Unvested at December 31, 2017
239,837
$
34.81
$
3,320
(127)
(2,200)
8,349
$
194,346
(17,410) $
(77,793) $
$
582,375
32.43
35.43
54.18
34.73
$
6,303
(617)
(4,215)
20,228
At December 31, 2017, we estimated the unrecognized compensation cost of our phantom awards to be approximately
$2.1 million to be recognized over a weighted average period of approximately 1.5 years. We recorded a credit of $3.4 million
and a charge of $8.9 million to compensation expense for the years ended December 31, 2017 and 2016, respectively. Our
liability for these awards totaled $3.2 million and $13.6 million at December 31, 2017 and 2016, respectively.
Equity-Based Compensation Plan Expense
Equity-based compensation expense during the three years ended December 31, 2017 was as follows:
Consolidated Statement of Operations
Onshore facilities and transportation operating costs
Marine transportation operating costs
Sodium minerals and sulfur services operating costs
Offshore pipeline operating costs
General and administrative expenses
Total
Expense Related to Equity-Based
Compensation Plans
2017
2016
2015
$ (1,137) $ 1,688
1,089
(483)
(533)
(152)
(2,272)
4,575
$ (4,577) $ 8,580
547
681
$ 1,185
851
227
94
4,565
$ 6,922
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.
During 2017, 2016 and 2015 our largest customer was Shell Oil Company, which accounted for 13%, 12%, and 12%
of total revenues, respectively. The revenues from Shell Oil Company in all three years relate primarily to our onshore facilities
and transportation operations.
In addition, 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.
F-36
18. Derivatives
Commodity Derivatives
We have exposure to commodity price changes related to our inventory and purchase commitments. We utilize
derivative instruments (primarily futures and options contracts traded on the NYMEX) to hedge our exposure to commodity
prices, primarily of crude oil, fuel oil and petroleum products. Our decision as to whether to designate derivative instruments as
fair value hedges for accounting purposes relates to our expectations of the length of time we expect to have the commodity
price exposure and our expectations as to whether the derivative contract will qualify as highly effective under accounting
guidance in limiting our exposure to commodity price risk. Most of the petroleum products, including fuel oil that we supply
cannot be hedged with a high degree of effectiveness with derivative contracts available on the NYMEX; therefore, we do not
designate derivative contracts utilized to limit our price risk related to these products as hedges for accounting
purposes. Typically we utilize crude oil and other petroleum products futures and option contracts to limit our exposure to the
effect of fluctuations in petroleum products prices on the future sale of our inventory or commitments to purchase petroleum
products, and we recognize any changes in fair value of the derivative contracts as increases or decreases in our cost of
sales. The recognition of changes in fair value of the derivative contracts not designated as hedges for accounting purposes can
occur in reporting periods that do not coincide with the recognition of gain or loss on the actual transaction being
hedged. Therefore we will, on occasion, report gains or losses in one period that will be partially offset by gains or losses in a
future period when the hedged transaction is completed.
We have designated certain crude oil futures contracts as hedges of crude oil inventory due to our expectation that
these contracts will be highly effective in hedging our exposure to fluctuations in crude oil prices during the period that we
expect to hold that inventory. We account for these derivative instruments as fair value hedges under the accounting guidance.
Changes in the fair value of these derivative instruments designated as fair value hedges are used to offset related changes in
the fair value of the hedged crude oil inventory. Any hedge ineffectiveness in these fair value hedges and any amounts
excluded from effectiveness testing are recorded as a gain or loss in the Consolidated Statement of Operations.
In accordance with NYMEX requirements, we fund the margin associated with our loss positions on commodity
derivative contracts traded on the NYMEX. The amount of the margin is adjusted daily based on the fair value of the
commodity contracts. The margin requirements are intended to mitigate a party’s exposure to market volatility and the
associated contracting party risk. We offset fair value amounts recorded for our NYMEX derivative contracts against margin
funding as required by the NYMEX in Current Assets - Other in our Consolidated Balance Sheets.
At December 31, 2017, we had the following outstanding derivative commodity contracts that were entered into to
economically hedge inventory or fixed price purchase commitments.
Designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 bbls)
Weighted average contract price per bbl
Not qualifying or not designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 bbls)
Weighted average contract price per bbl
Fuel oil futures:
Contract volumes (1,000 bbls)
Weighted average contract price per bbl
Crude oil options:
Contract volumes (1,000 bbls)
Weighted average premium received
Sell (Short)
Contracts
Buy (Long)
Contracts
297
57.70
223
56.86
$
260
55.01
$
80
0.85
$
$
$
$
$
—
—
152
57.30
20
53.20
45
0.24
F-37
Financial Statement Impacts
The following table summarizes the accounting treatment and classification of our derivative instruments on our
Consolidated Financial Statements.
Impact of Unrealized Gains and Losses
Consolidated
Balance Sheets
Consolidated
Statements of Operations
Derivative Instrument
Hedged Risk
Designated as hedges under accounting guidance:
Crude oil futures contracts
(fair value hedge)
Volatility in crude oil prices -
effect on market value of
inventory
Derivative is recorded in
Other current assets (offset
against margin deposits) and
offsetting change in fair value
of inventory is recorded
in Inventories
Not qualifying or not designated as hedges under accounting guidance:
Commodity hedges
consisting of crude oil,
heating oil and natural gas
futures and forward
contracts and call options
Volatility in crude oil and
petroleum products prices -
effect on market value of
inventory or purchase
commitments
Derivative is recorded in
Other current assets (offset
against margin deposits) or
Accrued liabilities
Preferred Distribution Rate
Reset Election
This instrument is not related
to a risk, but is rather part of
a host contract with the
issuance of our Preferred
Units
Derivative is recorded in
Other long-term liabilities
Excess, if any, over effective
portion of hedge is recorded
in Onshore facilities and
transportation costs - product
costs
Effective portion is offset in
cost of sales against change
in value of inventory being
hedged
Entire amount of change in
fair value of derivative is
recorded in Onshore facilities
and transportation costs -
product costs
Entire amount of change in
fair value of derivative is
recorded in Other income
(expense)
Unrealized gains are subtracted from net income and unrealized losses are added to net income in determining cash
flows from operating activities. To the extent that we have fair value hedges outstanding, the offsetting change recorded in the
fair value of inventory is also eliminated from net income in determining cash flows from operating activities. Changes in
margin deposits necessary to fund unrealized losses also affect cash flows from operating activities.
F-38
The following tables reflect the estimated fair value gain (loss) position of our derivatives at December 31, 2017 and
2016:
Fair Value of Derivative Assets and Liabilities
Asset Derivatives:
Commodity derivatives—futures and call options (undesignated
hedges):
Gross amount of recognized assets
Gross amount offset in the Consolidated Balance Sheets
Net amount of assets presented in the Consolidated Balance
Sheets
Total asset derivatives
Commodity derivatives—futures and call options (designated
hedges):
Gross amount of recognized assets
Gross amount offset in the Consolidated Balance Sheets
Net amount of assets presented in the Consolidated Balance
Sheets
Liability Derivatives:
Preferred Distribution Rate Reset Election (2)
Commodity derivatives—futures and call options (undesignated
hedges):
Gross amount of recognized liabilities
Gross amount offset in the Consolidated Balance Sheets
Net amount of liabilities presented in the Consolidated Balance
Sheets
Commodity derivatives—futures and call options (designated
hedges):
Gross amount of recognized liabilities
Gross amount offset in the Consolidated Balance Sheets
Net amount of liabilities presented in the Consolidated Balance
Sheets
Consolidated
Balance Sheets
Location
Current Assets -
Other
Current Assets -
Other
Current Assets -
Other
Current Assets -
Other
Other Long-Term
Liabilities (2)
Current Assets -
Other (1)
Current Assets -
Other (1)
Current Assets -
Other (1)
Current Assets -
Other (1)
Fair Value
December 31, 2017
December 31, 2016
$
$
$
$
$
$
$
$
$
$
505
(505)
—
—
54
(54)
—
(45,209)
(1,203)
1,203
—
(863)
338
(525)
$
$
$
$
$
$
$
$
$
443
(443)
—
—
3,321
(3,321)
—
—
(1,772)
1,772
—
(9,506)
7,589
(1,917)
(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 amounts associated with cash
margin. Our exchange-traded derivatives are transacted through brokerage accounts and are subject to margin requirements as
established by the respective exchange. On a daily basis, our account equity (consisting of the sum of our cash balance and the
fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation
margin. As of December 31, 2017, we had a net broker receivable of approximately $1.0 million (consisting of initial margin
of $1.3 million decreased by $0.3 million of variation margin). As of December 31, 2016, we had a net broker receivable of
approximately $5.6 million (consisting of initial margin of $5.1 million increased by $0.5 million of variation margin). At
December 31, 2017 and December 31, 2016, 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.
F-39
Preferred Distribution Rate Reset Election
A derivative feature embedded in a contract that does not meet the definition of a derivative in its entirety must be
bifurcated and accounted for separately if the economic characteristics and risks of the embedded derivative are not clearly and
closely related to those of the host contract. For a period of 30 days following (i) September 1, 2022 and (ii) each subsequent
anniversary thereof, the holders of our preferred units may make a Rate Reset Election to a cash amount per preferred unit
equal to the amount that would be payable per quarter if a preferred unit accrued interest on the Issue Price at an annualized
rate equal to three-month LIBOR plus 750 basis points; provided, however, that such reset rate shall be equal to 10.75% if
(i) such alternative rate is higher than the LIBOR-based rate and (ii) the then market price for our common units is then less
than 110% of the Issue Price. The Rate Reset Election of the preferred units represents an embedded derivative that must be
bifurcated from the related host contract and recorded at fair value on our Consolidated Balance Sheet. Corresponding changes
in fair value are recognized in Other Expense in our Consolidated Statement of Operations. At December 31, 2017, the fair
value of this embedded derivative was a liability of $45.2 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 call
options:
Contracts designated as hedges under
accounting guidance
Contracts not considered hedges under
accounting guidance
Total commodity derivatives
Preferred Distribution Rate Reset Election
(Note 19)
Amount of Gain (Loss) Recognized in Income
Year Ended
December 31,
Consolidated Statements of
Operations Location
2017
2016
2015
Onshore facilities and
transportation product costs
Onshore facilities and
transportation product costs
$
$
5,116
$
(13,195) $
(1,101)
(1,314)
3,802
$
(5,847)
(19,042) $
16,026
14,925
Other Expense
$
(10,472) $
— $
—
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)
and liabilities;
Level 1 fair values are based on observable inputs such as quoted prices in active markets for identical assets
(2)
and liabilities and are either directly or indirectly observable as of the measurement date; and
Level 2 fair values are based on pricing inputs other than quoted prices in active markets for identical assets
(3)
Level 3 fair values are based on unobservable inputs in which little or no market data exists.
As required by fair value accounting guidance, financial assets and liabilities are classified in their entirety based on
the lowest level of input that is significant to the fair value measurement.
Our assessment of the significance of a particular input to the fair value requires judgment and may affect the
placement of assets and liabilities within the fair value hierarchy levels.
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, 2017 and 2016.
F-40
Recurring Fair Value Measures
Commodity derivatives:
Assets
Liabilities
Preferred Distribution Rate Reset Election
$
$
$
Rollforward of Level 3 Fair Value Measurements
December 31, 2017
December 31, 2016
Level 1
Level 2
Level 3
Level 1
Level 2
Level 3
559
$
— $
— $
— $ (45,209) $
3,764
— $
$
— $ (11,278) $
— $
— $
— $
— $
—
—
—
(2,066) $
— $
The following table provides a reconciliation of changes in fair value at the beginning and ending balances for our
derivatives classified as level 3:
Beginning Balance
Initial valuation of Preferred Distribution Rate Reset Election
Net Loss for the period included in earnings
Allocation of Distribution Paid-in-kind
Ending Balance
Year Ended
December 31,
2017
—
$
$
(34,450)
(10,472)
(287)
(45,209)
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 embedded derivative feature is based on a valuation model that estimates the fair value of the
convertible preferred units with and without a Rate Reset Election. This model contains inputs, including our common unit
price, a ten year history of the dividend yield, default probabilities and timing estimates which involve management judgment.
A significant increase or decrease in the value of these inputs could result in a material change in fair value to this embedded
derivative feature. We report unrealized gains and losses associated with this embedded derivative in our Consolidated
Statements of Operations as Other income (expense), net.
See Note 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 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, 2017 our
senior unsecured notes had a carrying value of $2.6 billion and a fair value of $2.7 billion, compared to $1.8 billion and $1.9
billion, respectively at December 31, 2016. 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.
Additionally, we recorded the fair value of net assets acquired and liabilities assumed in connection with our Alkali
Business acquisition as of the acquisition date of September 1, 2017. The fair value measurements were primarily based on
significant unobservable inputs (Level 3) developed using company-specific information. See Note 3 for further information
associated with the values recorded in our Alkali Business acquisition.
F-41
20. Employee Benefit Plans
Upon acquisition of our Alkali Business in 2017, we now sponsor a defined benefit plan. We account for the Alkali
Business benefit plan as a single employer pension plan that benefits only employees of our Alkali Business, and thus, the
related assets and liability costs of the plan are recorded in the Consolidated Balance Sheet. Under the Alkali Business benefit
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 Sheet are as follows:
Change in benefit obligation:
Benefit Obligation, beginning of year
Service Cost
Interest Cost
Actuarial Loss
Benefits Paid
Acquisition of Alkali Business
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
Acquisition of Alkali Business
Fair Value of Plan assets, end of year
Funded Status at end of period
Amounts recognized in the Statement of Financial Position
Non-current assets
Current liabilities
Non-current Liabilities
Net Asset (Liability) at end of year
Amounts recognized in accumulated other comprehensive loss:
Net actuarial loss
Amounts recognized in accumulated other comprehensive loss:
December 31,
2017
—
1,749
267
992
(56)
19,578
22,530
—
647
2,250
(56)
10,465
13,306
(9,224)
—
—
(9,224)
(9,224)
604
604
$
$
$
$
$
F-42
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 2018 Contributions by Employer
Future Expected Benefit Payments
2018
2019
2020
2021
2022
2023-2027
$
$
3,898
413
676
869
983
1,099
7,672
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
December 31,
2017
$
$
1,749
267
(259)
1,757
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 benefit 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 benefit plan is administered by a Board-appointed committee that has fiduciary responsibility for
the plan's management. The committee is responsible for the oversight and management of the plan's investments. The
committee maintains an investment policy that provides guidelines for selection and retention of investment managers or funds,
allocation of plan assets and performance review procedures and updating of the policy. The objective of the committee's
investment policy is to manage the plan assets in such a way that will allow for the on-going payment of the Company's
obligation to the beneficiaries.
Weighted average assumptions used to determine benefit
obligation:
December 31, 2017
Discount Rate
Expected Long-term Rate of Return
Rate of Compensation Increase
3.90%
6.28%
N/A
The discount rate used to determine the net periodic cost at the beginning of the period was 4.15%.
Pension Plan Assets - We maintain target allocation percentages among various asset classes based on an investment policy
established for our Pension Plan. The target allocation is designed to achieve long term objectives of return, mitigating risk,
and considering expected cash flows. Our Pension Plan asset allocations at December 31, 2017 by asset category are as
follows:
F-43
December 31, 2017
Target %
Actual %
Equity securities
Fixed income securities
Other
41-60%
40-50%
0-10%
41%
50%
9%
A summary of total investments for our pension plan assets measured at fair value at December 31, 2017 is presented below:
December 31, 2017
Level 1
Level 2
Level 3
Total
260
2,518
10,528
13,306
—
—
—
—
—
—
—
—
260
2,518
10,528
13,306
Cash and cash equivalents
Equity securities
Mutual and other exchange
traded funds
21. Commitments and Contingencies
Commitments and Guarantees
Our office lease for our corporate headquarters extends until October 31, 2022. To transport products, we lease
tractors, trailers and railcars. In addition, we lease tanks and terminals for the storage of crude oil, petroleum products, NaHS
and caustic soda. Additionally, we lease a segment of pipeline where under the terms we make payments based on throughput.
We have no minimum volumetric or financial requirements remaining on our pipeline lease.
The future minimum rental payments under all non-cancelable operating leases as of December 31, 2017, were as
follows (in thousands):
2018
2019
2020
2021
2022
2023 and thereafter
Total minimum lease obligations
Office
Space
Transportation
Equipment
Terminals and
Tanks
Total
$
3,972
$
25,871
$
14,737
$
3,951
3,984
3,233
2,693
4,696
25,209
23,403
17,818
16,317
55,614
12,593
8,833
6,545
4,754
55,627
$
22,529
$
164,232
$
103,089
$
44,580
41,753
36,220
27,596
23,764
115,937
289,850
Total operating lease expense from our continuing operations was as follows (in thousands):
Year Ended December 31, 2017
Year Ended December 31, 2016
Year Ended December 31, 2015
$
$
$
36,933
41,906
36,833
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.
F-44
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.
The Tax Cuts and Jobs Act (“Act”) was enacted on December 22, 2017. The Act contains several tax law changes that
will impact the Partnership in the current and future periods, including a reduction in the U.S. federal corporate tax rate from
35% to 21%. At December 31, 2017, the Partnership has not completed its accounting for the tax effects of the Act; however,
in certain cases, as described below, the Partnership has made a reasonable estimate of the effects on our existing deferred tax
balances.
The Partnership remeasured its U.S. deferred tax assets and liabilities and recorded a $5.3 million benefit relating to
the U.S. federal corporate tax rate change.
Our income tax (benefit) expense is as follows:
Current:
Federal
State
Total current income tax expense (benefit)
Deferred:
Federal
State
Total deferred income tax expense (benefit)
Total income tax expense (benefit)
Year Ended December 31,
2017
2016
2015
$
$
$
$
$
— $
100
100
$
(5,530) $
1,471
(4,059) $
(3,959) $
— $
1,200
1,200
1,862
280
2,142
3,342
$
$
$
$
—
1,200
1,200
2,478
309
2,787
3,987
F-45
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
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,
2017
2016
$
$
$
$
$
9,506
$
9,506
(1,285)
8,221
$
(3,896) $
(15,797)
(441)
(20,134)
(20,134) $
(11,913) $
10,787
10,787
(869)
9,918
(4,480)
(20,693)
(716)
(25,889)
(25,889)
(15,971)
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.
The reconciliation between the Partnership's effective tax rate on income (loss) from operations and the statutory tax
rate is as follows:
Income from operations before income taxes
Partnership income not subject to federal income tax
Income subject to federal income taxes
Tax expense at federal statutory rate
State income taxes, net of federal tax
Return to provision, federal and state
Other
Remeasurement of deferred taxes due to enacted tax rate change
Income tax expense (benefit)
Effective tax rate on income from operations before income taxes
2017
78,120
(77,704)
416
146
1,396
(163)
(68)
(5,270)
(3,959)
$
$
$
$
Year Ended December 31,
2016
114,424
(109,111)
5,313
1,860
$
$
$
2015
425,572
(418,500)
7,072
2,475
$
$
$
949
(198)
731
—
928
(193)
777
—
$
3,342
$
3,987
(5)%
3%
1%
At December 31, 2017, 2016 and 2015, we had no uncertain tax positions.
F-46
23. Quarterly Financial Data (Unaudited)
The table below summarizes our unaudited quarterly financial data for 2017 and 2016.
Revenues from continuing operations
Operating income
Net income
Net loss attributable to noncontrolling interest
Net income attributable to Genesis Energy, L.P.
Basic and diluted net income per common unit:
Net income per common unit
Cash distributions per common unit (1)
Revenues from continuing operations
Operating income
Net income
Net loss (income) attributable to noncontrolling interest
Net income attributable to Genesis Energy, L.P.
Basic and diluted net income per common unit:
Net income per common unit
Cash distributions per common unit (1)
First
415,491
52,597
26,938
152
27,090
0.23
0.7100
First
378,414
59,848
35,177
126
35,303
0.32
0.6550
2017 Quarters
Second
Third
Fourth
$
$
$
$
$
$
$
$
$
$
$
$
$
$
406,723
61,447
33,580
153
33,733
0.28
0.7200
$
$
$
$
$
$
$
486,114
43,100
6,160
152
6,312
0.01
0.7225
2016 Quarters
Second
Third
445,976
47,988
23,601
126
23,727
0.22
0.6725
$
$
$
$
$
$
$
460,050
55,179
31,983
118
32,101
0.28
0.6900
$
$
$
$
$
$
$
$
$
$
$
$
$
$
720,049
63,407
15,401
111
15,512
(0.01)
0.5000
Fourth
428,053
43,412
20,321
1,797
22,118
0.19
0.7000
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(1) Represents cash distributions declared and paid in the applicable period.
24. Condensed Consolidating Financial Information
Our $2.6 billion aggregate principal amount of senior unsecured notes co-issued by Genesis Energy, L.P. and Genesis
Energy Finance Corporation are fully and unconditionally guaranteed jointly and severally by all of Genesis Energy, L.P.’s current
and future 100% owned domestic subsidiaries, except Genesis Free State Pipeline, LLC, Genesis NEJD Pipeline, LLC and certain
other minor subsidiaries. Genesis NEJD Pipeline, LLC is 100% owned by Genesis Energy, L.P., the parent company. The
remaining non-guarantor subsidiaries are owned by Genesis Crude Oil, L.P., a guarantor subsidiary. Genesis Energy Finance
Corporation has no independent assets or operations. See Note 10 for additional information regarding our consolidated debt
obligations.
The following is condensed consolidating financial information for Genesis Energy, L.P. and subsidiary guarantors:
F-47
Condensed Consolidating Balance Sheet
December 31, 2017
Genesis
Energy, L.P.
(Parent and
Co-Issuer)
Genesis
Energy Finance
Corporation
(Co-Issuer)
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
Eliminations
Genesis
Energy, L.P.
Consolidated
ASSETS
Current assets:
Cash and cash equivalents
$
6
$
— $
8,340
$
695
$
— $
9,041
Other current assets
Total current assets
Fixed Assets, at cost
Less: Accumulated depreciation
Net fixed assets
Mineral Leaseholds
Goodwill
Other assets, net
Advances to affiliates
Equity investees and other investments
Investments in subsidiaries
Total assets
LIABILITIES AND CAPITAL
Current liabilities
Senior secured credit facilities
$
$
Senior unsecured notes
Deferred tax liabilities
Advances from affiliates
Other liabilities
Total liabilities
Mezzanine Capital:
Class A Convertible Preferred Units
Partners’ capital, common units
Accumulated other comprehensive income (loss)(1)
Noncontrolling interests
50
56
—
—
—
—
—
14,083
3,808,712
—
2,689,861
—
—
—
—
—
—
—
—
—
—
—
614,682
623,022
5,523,431
(708,269)
4,815,162
564,506
325,046
378,371
—
381,550
82,616
12,316
13,011
77,584
(26,717)
50,867
—
—
(56)
(56)
—
—
—
—
—
126,300
85,423
(154,437)
(3,894,135)
626,992
636,033
5,601,015
(734,986)
4,866,029
564,506
325,046
364,317
—
—
—
—
381,550
(2,772,477)
—
6,512,712
$
— $
7,170,273
$
275,601
$
(6,821,105) $
7,137,481
46,086
$
— $
399,017
$
11,417
$
(256) $
456,264
1,099,200
2,598,918
—
—
45,210
3,789,414
697,151
2,026,147
—
—
—
—
—
—
—
—
—
—
—
—
—
—
11,913
3,894,027
182,414
4,487,371
—
—
—
—
—
—
—
(3,894,027)
1,099,200
2,598,918
11,913
—
183,237
194,654
(154,290)
256,571
(4,048,573)
4,422,866
—
—
—
697,151
2,683,506
89,026
(2,772,532)
2,026,147
(604)
—
—
(8,079)
—
—
(604)
(8,079)
Total liabilities, mezzanine capital and partners’
capital
(1) The entire balance and activity within Accumulated Other Comprehensive Income is related to our pension held within our
Guarantor Subsidiaries.
(6,821,105) $
6,512,712
7,170,273
275,601
— $
$
$
$
$
7,137,481
F-48
Condensed Consolidating Balance Sheet
December 31, 2016
Genesis
Energy, L.P.
(Parent and
Co-Issuer)
Genesis
Energy Finance
Corporation
(Co-Issuer)
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
Eliminations
Genesis
Energy, L.P.
Consolidated
ASSETS
Current assets:
Cash and cash equivalents
$
6
$
— $
6,360
$
663
$
— $
7,029
Other current assets
Total current assets
Fixed Assets, at cost
Less: Accumulated depreciation
Net fixed assets
Mineral Leaseholds
Goodwill
Other assets, net
Advances to affiliates
Equity investees and other investments
Investments in subsidiaries
Total assets
LIABILITIES AND CAPITAL
Current liabilities
Senior secured credit facilities
$
$
Senior unsecured notes
Deferred tax liabilities
Advances from affiliates
Other liabilities
Total liabilities
Mezzanine Capital
Class A Convertible Preferred Units
Partners' capital
Accumulated other comprehensive income (loss)
Noncontrolling interests
Total liabilities, mezzanine capital and partners’
capital
50
56
—
—
—
—
—
10,696
2,650,930
—
2,594,882
—
—
—
—
—
—
—
—
—
—
—
340,555
346,915
4,685,811
(524,315)
4,161,496
—
325,046
390,214
—
408,756
80,735
12,237
12,900
77,585
(24,217)
53,368
—
—
(302)
(302)
—
—
—
—
—
133,980
73,295
(140,533)
(2,724,225)
352,540
359,569
4,763,396
(548,532)
4,214,864
—
325,046
394,357
—
—
—
—
408,756
(2,675,617)
—
5,256,564
$
— $
5,713,162
$
273,543
$
(5,540,677) $
5,702,592
34,864
$
— $
211,591
$
14,505
$
(157) $
260,803
1,278,200
1,813,169
—
—
—
3,126,233
—
2,130,331
—
—
—
—
—
—
—
—
—
—
—
—
—
—
25,889
2,724,224
165,266
3,126,970
—
—
—
—
—
—
—
(2,724,224)
1,278,200
1,813,169
25,889
—
179,592
194,097
(140,377)
204,481
(2,864,758)
3,582,542
—
—
—
—
2,586,192
89,727
(2,675,919)
2,130,331
—
—
—
(10,281)
—
—
—
(10,281)
$
5,256,564
$
— $
5,713,162
$
273,543
$
(5,540,677) $
5,702,592
F-49
Condensed Consolidating Statement of Operations
Year Ended December 31, 2017
Genesis
Energy, L.P.
(Parent and
Co-Issuer)
Genesis
Energy Finance
Corporation
(Co-Issuer)
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
Eliminations
Genesis
Energy, L.P.
Consolidated
REVENUES:
Offshore pipeline transportation services
$
— $
— $
318,239
$
— $
— $
318,239
Sodium minerals and sulfur services
Marine transportation
Onshore facilities and transportation
Total revenues
COSTS AND EXPENSES:
Onshore facilities and transportation costs
Marine transportation costs
Sodium minerals and sulfur services
operating costs
Offshore pipeline transportation operating
costs
General and administrative
Depreciation and amortization
Gain on sale of assets
Total costs and expenses
OPERATING INCOME
Equity in earnings of equity investees
Equity in earnings of subsidiaries
Interest (expense) income, net
Other expense
Income before income taxes
Income tax benefit (expense)
NET INCOME
Net loss attributable to noncontrolling
interests
NET INCOME ATTRIBUTABLE TO
GENESIS ENERGY, L.P.
Less: Accumulated distributions attributable to
Class A Convertible Preferred Units
NET INCOME AVAILABLE TO
COMMON UNIT HOLDERS
$
$
9,252
—
18,936
28,188
1,089
—
9,129
2,840
—
2,500
—
15,558
12,630
—
—
(13,905)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
276,341
(176,979)
(16,715)
82,647
—
82,647
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
460,790
205,287
1,023,293
2,007,609
967,558
154,606
332,209
69,225
66,421
249,980
(40,311)
1,799,688
207,921
51,046
(520)
14,122
—
272,569
3,928
276,497
(7,420)
—
—
462,622
205,287
1,042,229
(7,420)
2,028,377
—
—
968,647
154,606
(7,420)
333,918
—
—
—
—
72,065
66,421
252,480
(40,311)
(7,420)
1,807,826
—
—
(275,821)
—
—
(1,275)
(275,821)
31
—
(1,244)
(275,821)
220,551
51,046
—
(176,762)
(16,715)
78,120
3,959
82,079
—
568
—
568
82,647
$
— $
276,497
$
(676) $
(275,821) $
82,647
(21,995)
—
—
—
—
(21,995)
60,652
$
— $
276,497
$
(676) $
(275,821) $
60,652
F-50
Condensed Consolidating Statement of Operations
Year Ended December 31, 2016
Genesis
Energy, L.P.
(Parent and
Co-Issuer)
Genesis
Energy Finance
Corporation
(Co-Issuer)
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
Eliminations
Genesis
Energy, L.P.
Consolidated
$
— $
— $
334,679
$
— $
334,679
—
—
—
—
—
—
—
—
—
—
—
—
—
253,048
(139,799)
—
113,249
—
113,249
—
—
—
—
171,389
213,021
972,794
— 1,691,883
—
—
—
—
—
—
923,567
142,551
90,711
68,791
45,625
219,696
— 1,490,941
—
—
—
—
—
—
—
—
—
200,942
47,944
(6,744)
14,407
—
256,549
(3,337)
253,212
—
7,873
—
20,496
28,369
1,060
—
8,491
10,833
—
2,500
22,884
5,485
—
—
(14,555)
—
(7,759)
—
—
171,503
213,021
993,290
(7,759)
1,712,493
—
—
924,627
142,551
(7,759)
91,443
—
—
—
79,624
45,625
222,196
(7,759)
1,506,066
—
—
(246,304)
—
—
206,427
47,944
—
(139,947)
—
(9,070)
(246,304)
114,424
(5)
(9,075)
2,167
—
(3,342)
(246,304)
111,082
—
2,167
$ 113,249
$
— $
253,212
$
(6,908) $
(246,304) $
113,249
—
—
—
—
—
—
$ 113,249
$
— $
253,212
$
(6,908) $
(246,304) $
113,249
REVENUES:
Offshore pipeline transportation services
Sodium minerals and sulfur services
Marine transportation
Onshore facilities and transportation
Total revenues
COSTS AND EXPENSES:
Onshore facilities and transportation costs
Marine transportation costs
Sodium minerals and sulfur services
operating costs
Offshore pipeline transportation operating
costs
General and administrative
Depreciation and amortization
Total costs and expenses
OPERATING INCOME
Equity in earnings of equity investees
Equity in earnings of subsidiaries
Interest (expense) income, net
Other expense, net
Income before income taxes
Income tax expense
NET INCOME
Net loss attributable to noncontrolling interests
NET INCOME ATTRIBUTABLE TO
GENESIS ENERGY, L.P.
Less: Accumulated distributions attributable to
Class A Convertible Preferred Units
NET INCOME AVAILABLE TO
COMMON UNIT HOLDERS
F-51
REVENUES:
Offshore pipeline transportation services
Sodium minerals and sulfur services
Marine transportation
Onshore facilities and transportation
Total revenues
COSTS AND EXPENSES:
Onshore facilities and transportation costs
Marine transportation costs
Sodium minerals and sulfur services
operating costs
Offshore pipeline transportation operating
costs
General and administrative
Depreciation and amortization
Total costs and expenses
OPERATING INCOME
Equity in earnings of equity investees
Equity in earnings of subsidiaries
Gain on basis step up on historical interest
Interest (expense) income, net
Other income/(expense), net
Income before income taxes
Income tax expense
NET INCOME
Net loss attributable to noncontrolling interest
NET INCOME ATTRIBUTABLE TO
GENESIS ENERGY, L.P.
Less: Accumulated distributions attributable to
Class A Convertible Preferred Units
NET INCOME AVAILABLE TO
COMMON UNIT HOLDERS
$
$
$
$
$
Condensed Consolidating Statement of Operations
Year Ended December 31, 2015
Genesis
Energy, L.P.
(Parent and
Co-Issuer)
Genesis
Energy Finance
Corporation
(Co-Issuer)
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
Eliminations
Genesis
Energy, L.P.
Consolidated
$
— $
— $
137,681
$
2,549
$
— $
140,230
—
—
—
—
—
—
—
—
—
—
—
—
—
542,226
—
(100,494)
(19,204)
422,528
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
175,132
238,757
1,665,917
2,217,487
1,601,972
135,200
11,942
—
23,745
38,236
836
—
(9,194)
—
—
177,880
238,757
1,689,662
(9,194)
2,246,529
—
—
1,602,808
135,200
94,241
11,759
(9,194)
96,806
38,459
64,995
141,785
2,076,652
140,835
54,450
2,053
332,380
15,042
1,675
546,435
(4,036)
1,254
—
8,355
22,204
16,032
—
—
—
(15,144)
—
888
49
937
943
—
—
—
39,713
64,995
150,140
(9,194)
2,089,662
—
—
(544,279)
—
—
—
156,867
54,450
—
332,380
(100,596)
(17,529)
(544,279)
425,572
—
(3,987)
(544,279) $
421,585
—
943
(544,279) $
422,528
$
$
$
422,528
$
— $
542,399
$
— $
— $
— $
422,528
$
— $
542,399
$
1,880
— $
— $
— $
— $
—
—
422,528
$
— $
542,399
$
1,880
$
(544,279) $
422,528
F-52
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2017
Net cash (used in) provided by operating activities
$
162,980
$
— $
481,727
$
(4,585) $
(301,264) $
338,858
Genesis
Energy, L.P.
(Parent and
Co-Issuer)
Genesis
Energy Finance
Corporation
(Co-Issuer)
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
Eliminations
Genesis
Energy, L.P.
Consolidated
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
140,513
(250,593)
20,280
(4,647)
—
(1,325,759)
1,157,781
(6,764)
—
—
—
—
—
124
85,722
—
1,291,530
(1,474,873)
—
—
—
—
—
—
1,458,700
(1,637,700)
1,000,000
726,419
(204,830)
(25,913)
—
(12,000)
(1,157,781)
—
—
2,770
13,847
4,617
32
663
695
(140,513)
140,513
321,875
(321,875)
—
(13,847)
2,770
(57)
(990,266)
1,138,027
—
—
$
— $
2,012
7,029
9,041
CASH FLOWS FROM INVESTING
ACTIVITIES:
Payments to acquire fixed and intangible
assets
Cash distributions received from equity
investees - return of investment
Investments in equity investees
Acquisitions
Intercompany transfers
Repayments on loan to non-guarantor
subsidiary
Contributions in aid of construction costs
Proceeds from asset sales
Other, net
—
—
(140,513)
—
(1,157,781)
—
—
—
—
Net cash (used in) provided by investing activities
(1,298,294)
CASH FLOWS FROM FINANCING
ACTIVITIES:
Borrowings on senior secured credit facility
Repayments on senior secured credit facility
Proceeds from issuance of senior unsecured
notes, including premium
Proceeds from issuance of Class A convertible
preferred units, net
Repayment of senior unsecured notes
Debt issuance costs
Intercompany transfers
Issuance of common units for cash, net
Distributions to partners/owners
Contributions from noncontrolling interest
Other, net
1,458,700
(1,637,700)
1,000,000
726,419
(204,830)
(25,913)
—
140,513
(321,875)
—
—
Net cash provided by financing activities
1,135,314
Net decrease in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
$
—
6
6
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(250,593)
20,280
(4,647)
(1,325,759)
—
6,764
124
85,722
—
(1,468,109)
—
—
—
—
—
—
1,169,781
140,513
(321,875)
—
(57)
988,362
1,980
6,360
$
— $
8,340
$
F-53
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2016
Net cash (used in) provided by operating activities
$
179,853
$
— $
398,320
$
9,586
$
(289,421) $
298,338
Genesis
Energy, L.P.
(Parent and
Co-Issuer)
Genesis
Energy Finance
Corporation
(Co-Issuer)
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
Eliminations
Genesis
Energy, L.P.
Consolidated
CASH FLOWS FROM INVESTING
ACTIVITIES:
Payments to acquire fixed and intangible
assets
Cash distributions received from equity
investees - return of investment
Investments in equity investees
Acquisitions
Intercompany transfers
Repayments on loan to non-guarantor
subsidiary
Contributions in aid of construction costs
Proceeds from assets sales
Other, net
—
—
(298,020)
—
(31,436)
—
—
—
—
Net cash (used in) provided by investing activities
(329,456)
CASH FLOWS FROM FINANCING
ACTIVITIES:
Borrowings on senior secured credit facility
Repayments on senior secured credit facility
Debt issuance costs
Intercompany transfers
Issuance of common units for cash, net
Distributions to partners/owners
Contributions from noncontrolling interest
Other, net
Net cash provided by (used in) financing activities
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
$
1,115,800
(952,600)
(1,578)
—
298,020
(310,039)
—
—
149,603
—
6
6
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(463,100)
21,353
—
(25,394)
—
6,113
13,374
3,609
(151)
(444,196)
—
—
—
57,701
298,020
(310,039)
—
(1,734)
43,948
(1,928)
8,288
—
—
—
—
—
—
—
—
—
—
—
—
—
(26,264)
—
—
236
14,504
(11,524)
(1,938)
2,601
—
—
298,020
—
31,436
(6,113)
—
—
—
(463,100)
21,353
—
(25,394)
—
—
13,374
3,609
(151)
323,343
(450,309)
—
—
—
(31,437)
(298,020)
310,039
—
(14,504)
(33,922)
—
—
1,115,800
(952,600)
(1,578)
—
298,020
(310,039)
236
(1,734)
148,105
(3,866)
10,895
$
— $
6,360
$
663
$
— $
7,029
F-54
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2015
Net cash (used in) provided by operating activities
$
(14,082) $
— $
308,144
$
45,125
$
(49,651) $
289,536
Genesis
Energy, L.P.
(Parent and
Co-Issuer)
Genesis
Energy Finance
Corporation
(Co-Issuer)
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
Eliminations
Genesis
Energy, L.P.
Consolidated
CASH FLOWS FROM INVESTING
ACTIVITIES:
Payments to acquire fixed and intangible
assets
Cash distributions received from equity
investees - return of investment
Investments in equity investees
Acquisitions
Intercompany transfers
Repayments on loan to non-guarantor
subsidiary
Contributions in aid of construction costs
Proceeds from asset sales
Other, net
—
186,026
(633,761)
—
(1,240,973)
—
—
—
—
Net cash (used in) provided by investing activities
(1,688,708)
CASH FLOWS FROM FINANCING
ACTIVITIES:
Borrowings on senior secured credit facility
Repayments on senior secured credit facility
Proceeds from issuance of senior unsecured
notes
Repayment of senior secured notes
Debt issuance costs
Distribution to partners/owners
Distributions to noncontrolling interest
Issuance of common units for cash, net
Intercompany transfers
Other, net
1,525,050
(960,450)
1,139,718
(350,000)
(28,901)
(256,389)
—
633,759
—
—
Net cash provided by (used in) financing activities
1,702,787
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
$
(3)
9
6
(495,774)
25,645
(3,045)
(1,520,299)
—
5,524
3,179
2,811
(1,976)
(1,983,935)
—
—
—
—
—
(256,389)
(960)
633,759
1,299,830
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(495,774)
(186,026)
633,761
25,645
(3,045)
—
(1,520,299)
1,240,973
(5,524)
—
—
—
—
—
3,179
2,811
(1,976)
1,683,184
(1,989,459)
—
—
—
—
—
256,389
—
1,525,050
(960,450)
1,139,718
(350,000)
(28,901)
(256,389)
(960)
(633,759)
633,759
(58,857)
(1,240,973)
(471)
15,190
(15,190)
—
(471)
1,675,769
(43,667)
(1,633,533)
1,701,356
(22)
8,310
1,458
1,143
—
—
1,433
9,462
$
— $
8,288
$
2,601
$
— $
10,895
F-55
25. Subsequent Events
In January 2018, we called for redemption of the remaining $145.2 million of the original $350 million aggregate
principal amount of our outstanding 5.750% senior notes due 2021. The redemption was completed on February 15, 2018 and
holders received a redemption price of 101.438% of the principal amount, plus accrued and unpaid interest.
F-56
REPORT OF INDEPENDENT AUDITORS
The Management Committee
Poseidon Oil Pipeline Company, L.L.C.
We have audited the accompanying financial statements of Poseidon Oil Pipeline Company, L.L.C., which comprise the balance sheet as of
December 31, 2017, and the related statements of operations, cash flows, and members’ equity (deficit) for the year then ended, and the
related notes to the financial statements.
Management’s Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of these financial statements in conformity with U.S. generally accepted
accounting principles; this includes the design, implementation and maintenance of internal control relevant to the preparation and fair
presentation of financial statements that are free of material misstatement, whether due to fraud or error.
Auditor’s Responsibility
Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with
auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The
procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial
statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s
preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but
not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An
audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates
made by management, as well as evaluating the overall presentation of the financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Poseidon Oil Pipeline
Company, L.L.C. at December 31, 2017, and the results of its operations and its cash flows for the year then ended in conformity with U.S.
generally accepted accounting principles.
/s/ ERNST & YOUNG LLP
Houston, Texas
February 15, 2018
F-57
INDEPENDENT AUDITOR'S REPORT
To the Management Committee of
Poseidon Oil Pipeline Company, L.L.C.
Houston, Texas
We have audited the accompanying financial statements of Poseidon Oil Pipeline Company, L.L.C. (the "Company"), which comprise the
balance sheets as of December 31, 2016, and the related statements of operations, cash flows, and members' equity for each of the two years
in the period ended December 31, 2016, and the related notes to the financial statements.
Management's Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles
generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to
the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.
Auditors' Responsibility
Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with
auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The
procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial
statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the Company's
preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but
not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, we express no such opinion.
An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates
made by management, as well as evaluating the overall presentation of the financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Poseidon Oil Pipeline
Company, L.L.C. as of December 31, 2016, and the results of its operations and its cash flows for each of the two years in the period ended
December 31, 2016 in accordance with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 17, 2017
F-58
POSEIDON OIL PIPELINE COMPANY, L.L.C.
BALANCE SHEETS
(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
Accounts receivable—trade
Accounts receivable—related parties
Crude oil inventory
Other current assets
Total current assets
FIXED ASSETS, net
OTHER ASSETS
TOTAL ASSETS
LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable – trade
Accounts payable – related parties
Deferred revenue
Other current liabilities
Total current liabilities
LONG-TERM DEBT
OTHER LIABILITIES
COMMITMENTS AND CONTINGENCIES (see Note 2)
MEMBERS' EQUITY (DEFICIT)
TOTAL LIABILITIES AND MEMBERS' EQUITY
December 31,
2017
December 31,
2016
$
132
$
14,443
1,121
2,691
324
18,711
217,343
1,203
95
12,501
2,377
1,461
677
17,111
232,736
861
$
$
237,257
$
250,708
1,757
$
2,384
11,357
2,062
17,560
206,600
30,834
3,747
1,771
13,258
1,951
20,727
202,050
17,594
(17,737)
237,257
10,337
$
250,708
$
The accompanying notes are an integral part of these financial statements.
F-59
POSEIDON OIL PIPELINE COMPANY, L.L.C.
STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
CRUDE OIL HANDLING REVENUES:
Third parties
Related parties
Total crude oil handling revenues
COSTS AND EXPENSES:
Crude oil handling costs
Third parties
Related parties
Total crude oil handling costs
Other operating costs and expenses
Third parties
Related parties
Total other operating costs and expenses
Depreciation and accretion expenses
General and administrative costs
Total costs and expenses
OPERATING INCOME
Interest expense
NET INCOME
Year Ended December 31,
2017
2016
2015
$
98,024
$
100,383
$
19,109
117,133
19,899
120,282
97,977
25,769
123,746
1,774
5,889
7,663
852
8,388
9,240
15,633
45
32,581
84,552
6,026
1,989
3,788
5,777
1,238
7,914
9,152
15,615
101
30,645
89,637
4,729
$
78,526
$
84,908
$
460
1,554
2,014
2,800
7,997
10,797
15,619
129
28,559
95,187
4,352
90,835
The accompanying notes are an integral part of these financial statements.
F-60
POSEIDON OIL PIPELINE COMPANY, L.L.C.
STATEMENTS OF CASH FLOWS
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization and accretion expenses
Loss on sale of assets
Effect of changes in operating accounts:
Accounts receivable
Inventories
Other current assets
Accounts payable
Other liabilities
Net cash provided by operating activities
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to fixed assets
Proceeds from asset sales
Net cash used in investing activities
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under revolving credit facility
Repayments of principal
Debt issuance costs
Cash distributions to Members
Net cash used in financing activities
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION
Cash paid during the year for interest
Current liabilities for capital expenditures at end of year
Year Ended December 31,
2017
2016
2015
$
78,526
$
84,908
$
90,835
15,905
—
(687)
(1,230)
(261)
(1,434)
11,334
15,887
—
2,139
(887)
(379)
409
9,082
15,935
194
(4,533)
(100)
(248)
1,494
9,909
102,153
111,159
113,486
(66)
—
(66)
84,200
(79,650)
—
(106,600)
(102,050)
37
95
132
5,698
57
$
$
$
$
$
$
(183)
—
(183)
85,900
(81,100)
—
(116,300)
(111,500)
(524)
619
95
$
(2,244)
118
(2,126)
73,750
(71,750)
(1,360)
(115,500)
(114,860)
(3,500)
4,119
619
4,402
$
— $
4,180
—
The accompanying notes are an integral part of these financial statements.
F-61
POSEIDON OIL PIPELINE COMPANY, L.L.C.
STATEMENT OF MEMBERS' EQUITY (DEFICIT)
(In thousands)
January 1, 2015
Net income (loss)
Equity transfer
Cash distributions to members
December 31, 2015
Net income
Cash distributions to members
December 31, 2016
Net income
Cash distributions to members
December 31, 2017
Poseidon
Pipeline
Company,
L.L.C.
Shell Oil
Products
U.S.
Shell
Midstream
Partners, L.P.
GEL
Poseidon,
LLC
Total
23,902
$
23,902
$
— $
18,590
$
66,394
32,700
—
(41,580)
15,022
30,567
(41,868)
3,721
28,269
16,178
(20,640)
(19,440)
—
—
—
—
—
(38,376)
(6,386) $
$
—
— $
16,522
20,640
(22,140)
15,022
30,567
(41,868)
3,721
25,435
—
(32,340)
11,685
23,774
(32,564)
2,895
90,835
—
(115,500)
41,729
84,908
(116,300)
10,337
28,269
(38,376)
(6,386) $
21,988
78,526
(106,600)
(29,848)
(4,965) $ (17,737)
The accompanying notes are an integral part of these financial statements.
F-62
POSEIDON OIL PIPELINE COMPANY, L.L.C.
NOTES TO FINANCIAL STATEMENTS
1. Company Organization and Description of Business
Company Organization
Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”) is a Delaware limited liability company formed in February 1996 to design,
construct, own and operate an unregulated crude oil pipeline system located in the central Gulf of Mexico offshore Louisiana.
Unless the context requires otherwise, references to “we”, “us”, “our” or “the Company” within these notes are intended to mean
Poseidon.
At December 31, 2017 we were owned (i) 36% by Poseidon Pipeline Company, L.L.C. and (ii) 28% by GEL Poseidon, LLC,
collectively ("Genesis") and (iii) 36% by Shell Midstream Partners, L.P. On July 1, 2015, Shell Oil Products U.S. sold its ownership
interest in Poseidon to Shell Midstream Partners, L.P. On July 24, 2015, all of the ownership interest in Poseidon Pipeline Company,
L.L.C., was transferred by Enterprise Products Partners, L.P. (“Enterprise”) to an affiliate of Genesis as part of the sale of Enterprise’s
offshore business. Following such transfer, Poseidon Pipeline Company, L.L.C. continued to own a 36% ownership interest in
Poseidon.
Description of Business
The Poseidon Oil Pipeline System (the “Pipeline”) gathers crude oil production from the outer continental shelf and deep-water
areas of the Gulf of Mexico offshore Louisiana for delivery to onshore locations in south Louisiana. The system includes a pipeline
junction platform located at South Marsh Island 205 (“SMI-205”). Manta Ray Gathering Company, L.L.C. (“Manta Ray”), a
wholly owned subsidiary of Genesis acquired as part of Enterprise’s offshore business, serves as operator of the Pipeline.
2. Significant Accounting Policies
Our financial statements are prepared on the accrual basis of accounting in accordance with U.S. generally accepted accounting
principles (“GAAP”).
Except as noted within the context of each footnote disclosure, dollar amounts presented in the tabular data within these footnote
disclosures are stated in thousands of dollars.
In preparing these financial statements, the Company has evaluated subsequent events for potential recognition or disclosure
through February 15, 2018, the issuance date of the financial statements.
Cash and Cash Equivalents
Cash and cash equivalents represent unrestricted cash on hand and may also include highly liquid investments with original
maturities of less than three months from the date of purchase.
Contingency and Liability Accruals
We accrue reserves for contingent liabilities including environmental remediation and potential legal claims. When our assessment
indicates that it is probable that a liability has occurred and the amount of the liability can be reasonably estimated, we make
accruals. We base our estimates on all known facts at the time and our assessment of the ultimate outcome, including consultation
with external experts and counsel. We revise these estimates as additional information is obtained or resolution is achieved.
We also make estimates related to future payments for environmental costs to remediate existing conditions attributable to past
operations. Environmental costs include costs for studies and testing as well as remediation and restoration. We sometimes make
these estimates with the assistance of third parties involved in monitoring the remediation effort.
At December 31, 2017, we were not aware of any contingencies or liabilities that would have a material effect on our financial
position, results of operations or cash flows.
Crude Oil Handling Costs
Crude oil handling costs represent expenses we incur as a result of utilizing third party-owned and related party-owned pipelines
in the provision of services.
Estimates
F-63
Preparing our financial statements in conformity with GAAP requires us to make estimates that affect amounts presented in the
financial statements. Our most significant estimates relate to (i) the useful lives and depreciation methods used for fixed assets;
(ii) measurement of fair value and projections used in impairment testing of fixed assets; (iii) contingencies; (iv) revenue and
expense accruals; and (v) estimates of future asset retirement obligations.
Actual results could differ materially from our estimates. On an ongoing basis, we review our estimates based on currently available
information. Any changes in the facts and circumstances underlying our estimates may require us to update such estimates, which
could have a material impact on our financial statements.
Fair Value Information
The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair values based
on their short-term nature. The fair value of the amounts outstanding under the February 2015 Credit Facility approximate book
value as of December 31, 2017 given the variable rate nature of this debt.
Impairment Testing for Long-Lived Assets
Long-lived assets such as fixed assets are reviewed for impairment when events or changes in circumstances indicate that the
carrying amount of such assets may not be recoverable. Long-lived assets with carrying values that are not expected to be recovered
through future cash flows are written-down to their estimated fair values. The carrying value of a long-lived asset is deemed not
recoverable if it exceeds the sum of undiscounted cash flows expected to result from the use and eventual disposition of the asset.
If the asset’s carrying value exceeds the sum of its undiscounted cash flows, a non-cash asset impairment charge equal to the
excess of the asset’s carrying value over its estimated fair value is recorded. Fair value is defined as the price that would be received
to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date.
We measure fair value using market price indicators or, in the absence of such data, appropriate valuation techniques.
No asset impairment charges were recognized during the years ended December 31, 2017, 2016 or 2015.
Income Taxes
We are organized as a pass-through entity for federal income tax purposes. As a result, our financial statements do not provide for
such taxes and our Members are individually responsible for their allocable share of our taxable income for federal income tax
purposes.
Inventories
We take title to crude oil volumes we purchase from producers and volumes we obtain through contractual pipeline loss allowances.
Timing and measurement differences between receipt and delivery volumes, as well as fluctuations in crude oil pricing, impact
our inventory balances. Our inventory amounts are presented at the lower of average cost or market.
Due to fluctuating crude oil prices, we recognize lower of cost or market adjustments when the carrying value of our crude oil
inventory exceeds its net realizable value. These non-cash charges are a component of “Crude oil handling costs” on our Statement
of Operations in the period they are recognized. We recognized $0.1 million, $0.0 million and $0.1 million of lower of cost or net
realizable value adjustments during 2017, 2016 and 2015, respectively.
Fixed Assets and Asset Retirement Obligation
Fixed assets are recorded at cost. Expenditures for additions, improvements and other enhancements to fixed assets are capitalized,
and minor replacements, maintenance, and repairs that do not extend asset life or add value are charged to expense as incurred.
When fixed assets are retired or otherwise disposed of, the related cost and accumulated depreciation is removed from the accounts
and any resulting gain or loss is included in results of operations for the respective period.
In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the reporting
periods it benefits. Our fixed assets are depreciated using the straight-line method, which results in depreciation expense being
incurred evenly over the life of an asset. Our estimate of depreciation expense incorporates management assumptions regarding
the useful economic lives and residual values of our assets. Estimated useful lives are 10 to 30 years for our related fixed assets.
Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result
from their acquisition, construction, development and/or normal operation. When an ARO is incurred, we record a liability for
the ARO and capitalize an equal amount as an increase in the carrying value of the related long-lived asset. ARO amounts are
measured at their estimated fair value using expected present value techniques. Over time, the liability is accreted to its present
value (through accretion expense) and the capitalized amount is depreciated over the remaining useful life of the related long-
term asset. We will incur a gain or loss to the extent that our ARO liabilities are not settled at their recorded amounts. See Note
3 for additional information regarding our fixed assets and related AROs.
F-64
Revenue Recognition
Crude oil handling revenues are generated from purchase and sale agreements whereby we purchase crude oil from producers at
various receipt points along the Pipeline for a contractual fixed price (less a “handling fee”) and sell common stream crude oil
back to the producers at various redelivery points at the same contractual fixed price (before the handling fee was applied). Since
these purchase and sale transactions are with the same customer and entered into in contemplation of one another, the purchase
and sales amounts are netted against one another and the residual handling fees are recognized as crude oil handling revenue. The
intent of these buy-sell arrangements is to earn a fee for handling crude oil (a service to the producer) and not to engage in crude
oil marketing activities. We also net the corresponding receivables and payables from such transactions on our Balance Sheets for
consistency of presentation.
We have entered into long-term pipeline capacity reservation agreements with Anadarko Petroleum Corporation, Eni Petroleum
Co. Inc., Exxon Mobil Corporation, Freeport-McMoran Inc., Petrobras America Inc., and Teikoku Oil (North America) Co., Ltd.,
collectively the “Lucius producers”. The term of these agreements is 20 years (July 2014 through June 2034), which corresponds
to the period of dedicated production from the Lucius producers under the agreements. The amount of pipeline capacity reserved
each year for the Lucius producers is based on their expected production volumes for that period (as defined in the contract). The
capacity reservation agreements require the Lucius producers to make scheduled minimum bill payments to us (as defined in the
contract). We defer that portion of the minimum bill payments that relate to future performance obligations under the contract.
We recognized $13.3 million of pipeline capacity reservation revenues from the Lucius producers during each of the years ended
December 31, 2017, 2016 and 2015. At December 31, 2017 our deferred revenue attributable to the Lucius agreements totaled
$39.6 million of which $11.4 million is expected to be recognized as revenue in 2018.
Recent and Proposed Accounting Pronouncements
In May 2014, the FASB issued revised guidance on revenue from contracts with customers that will supersede most current revenue
recognition guidance, including industry-specific guidance. The core principle of the revenue model is that an entity will recognize
revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which
the entity expects to be entitled in exchange for those goods or services. The new standard provides a five-step analysis for
transactions to determine when and how revenue is recognized. The guidance permits the use of either a full retrospective or a
modified retrospective approach. In July 2015, the FASB approved a one year deferral of the effective date of this standard to
December 15, 2017 for annual reporting periods beginning after that date for public companies, or December 15, 2018 for all
other entities. We have elected to adopt the new standard for the annual reporting period following December 15, 2018. While we
do not believe there will be a material impact to our revenues upon adoption, we are continuing to evaluate the impacts of our
pending adoption of this guidance and our preliminary assessments are subject to change.
In August 2014, the FASB issued Accounting Standards Update 2014-15, Disclosure of Uncertainties about an Entity’s Ability to
Continue as a Going Concern, which was codified as ASC 205-40. ASC 205-40 requires management to evaluate an entity’s
ability to continue as a going concern within one year after the date that the financial statements are issued. ASC 205-40 is effective
for fiscal years ending after December 15, 2016. In accordance with ASC 205-40, the Company performed an evaluation to
determine if there are conditions or events that raise substantial doubt about the Company’s ability to continue as a going concern
and management’s plans to mitigate those conditions and events that alleviate the substantial doubt. During management’s
evaluation, they considered the Company’s credit facility which contains certain financial covenants that are measured quarterly.
The Company is in compliance with its financial covenants at December 31, 2017 and notes no conditions that raise substantial
doubt about the Company’s ability to meet its obligations for the next twelve months.
In July 2015, the FASB issued guidance modifying the accounting for inventory. Under this guidance, the measurement principle
for inventory will change from lower of cost or market value to lower of cost and net realizable value. The guidance defines net
realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion,
disposal, and transportation. The guidance is effective for reporting periods after December 15, 2016, with early adoption permitted.
We have adopted this guidance as of January 1, 2017 with no material impact on our consolidated financial statements.
In February 2016, the FASB issued guidance to improve the transparency and comparability among companies by requiring lessees
to recognize a lease liability and a corresponding lease asset for virtually all lease contracts. The guidance also requires additional
disclosure about leasing arrangements. The guidance is effective for interim and annual periods beginning after December 15,
2018 and requires a modified retrospective approach to adoption. Early adoption is permitted. We are currently evaluating this
guidance.
F-65
In August 2016, the FASB issued guidance that addresses how certain cash receipts and payments are presented and classified in
the statement of cash flows under Topic 230, Statement of Cash flow, and other Topics. The guidance is effective for annual
reporting periods, and interim periods therein, beginning after December 15, 2017. We do not expect the adoption of this guidance
to have a material impact on our financial statements.
3. Fixed Assets and Asset Retirement Obligations
Fixed Assets
Our fixed asset values and related accumulated depreciation balances were as follows at the dates indicated:
Pipelines and facilities
Construction in progress
Total
Less accumulated depreciation
Fixed assets, net
At December 31,
2017
433,174
87
433,261
(215,918)
217,343
$
$
2016
433,105
32
433,137
(200,401)
232,736
$
$
2015
432,941
13
432,954
(184,895)
248,059
$
$
Depreciation expense was $15.5 million, $15.5 million and $15.5 million for the years ended December 31, 2017, 2016 and 2015,
respectively
Asset retirement obligations
Our AROs result from regulatory requirements that would be triggered by the retirement of our offshore pipeline and platform
assets. The following table presents information regarding our asset retirement liabilities for the periods indicated:
ARO liability, beginning of period
Liabilities settled
Accretion expense
Revisions in expected cash flows
ARO liability, end of period
For the Year Ended December 31,
2017
2016
2015
$
$
1,513
—
116
—
1,629
$
$
1,405
—
108
—
1,513
$
$
1,302
—
103
—
1,405
At December 31, 2016, our forecast of accretion expense is as follows for the next five years:
2018
126
$
2019
135
$
2020
146
$
2021
157
$
2022
169
$
4. Debt Obligation
February 2015 Credit Facility
In February 2015, we entered into an amended and restated revolving credit agreement having an initial borrowing capacity of
$225 million, with a provision that its borrowing capacity could be expanded to $275 million with additional commitments from
the lenders. Amounts borrowed under the February 2015 credit facility mature in February 2020. We used $186.8 million of
borrowing capacity under the new credit facility to refinance principal amounts that were outstanding under the April 2011 Credit
Facility at termination. We incurred $1.3 million of debt issuance costs related to the February 2015 Credit Facility of which $0.6
million and $0.9 million is deferred within other assets on our Balance Sheet at December 31, 2017 and 2016, respectively.
The weighted-average variable interest rate charged under the February 2015 credit facility was approximately 2.8% and 2.2%
for the years ended December 31, 2017 and 2016, respectively. Interest rates charged under the 2015 credit facility are dependent
on certain quarterly financial ratios (as defined in the credit agreement). For Eurodollar loans where our leverage ratio is greater
F-66
than or equal to 1:1 and less than 2:1, the interest rate is the London Interbank Offered Rate (“LIBOR”) plus 1.75%, and for Base
Rate loans (as defined in the credit agreement), the interest rate is 0.75% plus a variable base rate equal to the greater of (i) the
prime rate, (ii) the federal funds rate plus 0.50% or (iii) LIBOR plus 1.00%. The interest rate on Eurodollar and Base Rate loans
would increase by 0.25% if our leverage ratio increased to greater than 2:1 and would decrease by 0.25% if our leverage ratio
decreased to less than or equal to 1:1. In addition, we pay commitment fees on the unused portion of the revolving credit facility
at rates that vary from 0.25% to 0.375%.
The February 2015 credit facility is non-recourse to our Members and secured by our assets. The February 2015 credit facility
also contains customary covenants such as restrictions on debt levels, liens, guarantees, mergers, sale of assets and distributions
to Members. A breach of any of these covenants could result in acceleration of our debt financial obligations. We were in compliance
with the covenants of our credit facility at December 31, 2017.
In general, if an Event of Loss occurs (as defined in the credit agreement), we are obligated to either repair the damage or use any
insurance proceeds we receive to reduce debt principal outstanding.
5. Members’ Equity
As a limited liability company, our Members are not personally liable for any of our debts, obligations or other liabilities. Income
or loss amounts are allocated to Members based on their respective membership interests. Cash contributions by and distributions
to Members are also based on their respective membership interests.
Cash distributions to Members are determined by our Management Committee, which is responsible for conducting the Company’s
affairs in accordance with our limited liability agreement.
6. Related Party Transactions
The following table summarizes our related party transactions for the period indicated:
Crude oil handling revenues:
Enterprise affiliates
Genesis affiliates
Shell affiliates
Total
Crude oil handling costs:
Enterprise affiliates
Genesis affiliates
Shell affiliates
Total
Other operating costs and expenses:
Enterprise affiliates
Genesis affiliates
Total
For the Year Ended December 31,
2017
2016
2015
$
$
$
$
— $
— $
986
18,123
19,109
—
3,951
1,938
5,889
—
8,388
8,388
$
$
$
1,007
18,892
19,899
—
2,930
858
3,788
—
7,914
7,914
$
$
$
470
464
24,835
25,769
209
595
750
1,554
4,056
3,941
7,997
Other operating costs and expenses include amounts charged to us by Manta Ray for operator fees and space on their SS-332A
platform.
F-67
The following table summarizes our related party accounts receivable and accounts payable amounts at the dates indicated:
Accounts receivable - related parties:
Genesis affiliates
Shell affiliates
Total accounts receivable - related parties
Accounts payable - related parties:
Genesis affiliates
Shell affiliates
Total accounts payable - related parties
At December 31,
2017
2016
$
$
$
— $
1,121
1,121
2,175
209
2,384
$
$
—
2,377
2,377
1,644
127
1,771
7. Significant Risks
Production and Credit Risk due to Customer Concentration
Offshore pipeline systems such as ours are directly impacted by exploration and production activities in the Gulf of Mexico for
crude oil. Crude oil reserves are depleting assets. Our crude oil pipeline system must access additional reserves to offset either
(i) the natural decline in production from existing connected wells or (ii) the loss of production to a competing takeaway pipeline.
We actively seek to offset the loss of volumes due to depletion by adding connections to new customers and production fields.
In terms of percentage of total revenues, our largest customers for the years ended December 31, 2017, 2016 and 2015, respectively,
were Anadarko Petroleum Corporation 24.0%, 16.8%, and 12.1%, Shell Oil Company 15.5%, 15.9%, and 20.4% and BHP Billiton
Ltd. 10.6%, 9.7%, and 9.3%, respectively. Shell Oil Company is a marketing agent for numerous producers who are dedicated to
us. The loss of any of these customers or a significant reduction in the crude oil volumes they have dedicated to us for handling
would have a material adverse effect on our financial position, results of operations and cash flows.
F-68
Officers*
Directors*
Conrad P. Albert (1) (2)
Private investor; former director of Anadarko Petroleum
Corporation and DeepTech International, Inc.; former
Executive Vice President of Manufacturers Hanover Trust
Company
James E. Davison (1)
Private investor; former chairman of Davison Transport, Inc.
James E. Davison, Jr. (1)
Private investor; executive of Davison family businesses
Sharilyn S. Gasaway(1) (2)
Private investor; former Executive Vice President and Chief
Financial Officer of Alltel Corporation
Kenneth M. Jastrow, II (1) (2) (3)
Former Non-executive Chairman of Forestar Group, Inc.;
former Chairman and Chief Executive Officer of Temple-
Inland, Inc.
Grant E. Sims (1)
Chairman of the Board and Chief Executive Officer, Genesis
Energy, LLC
Jack T. Taylor (1) (2)
Director of Sempra Energy and Murphy USA Inc.; former
KPMG Chief Operating Officer-Americas
(1) Governance, Compensation and Business Development
Committee Member. Mr. Jastrow serves as Chairman.
(2) Audit Committee Member. Ms. Gasaway serves as
Chairperson.
(3) Lead independent director
*Genesis Energy, L.P., does not have officers or directors. Listed
above are the officers and directors of the General Partner, Genesis
Energy, LLC
Grant E. Sims
Chief Executive Officer
Robert V. Deere
Chief Financial Officer
Edward T. Flynn
Executive Vice President
Richard R. Alexander
Vice President
Karen N. Pape
Senior Vice President and Controller
Kristen O. Jesulaitis
General Counsel
William S. Goloway
Vice President
Garland G. Gaspard
Senior Vice President
Chad A. Landry
Vice President
Ryan S. Sims
Vice President
Unitholder Information
Partnership Offices
Genesis Energy, L.P.
919 Milam, Suite 2100
Houston, TX 77002
(713) 860-2500
Partnership Website
www.genesisenergy.com
Exchange Listing
NYSE
Ticker Symbol: GEL
Principal Transfer Agent, Registrar and Cash Distribution
Paying Agent
American Stock Transfer & Trust Company
40 Wall Street
New York, NY 10005
(800) 937-5449
Additional Information:
• For information regarding your K-1 tax report, call (855)
502-0936
• Unitholder questions regarding transfers, lost certificates,
distribution checks and address changes should be directed
to the Transfer Agent or your stockbroker.
The Partnership’s Annual Report on Form 10-K is available
to Unitholders upon request. It is also available on the
Internet at http://www.genesisenergy.com
Genesis Energy, L.P. ♦ 919 Milam, Suite 2100 ♦ Houston, Texas 77002