GENESIS ENERGY, L.P.
2012 ANNUAL REPORT TO UNITHOLDERS
LETTER TO OUR UNITHOLDERS
Our past year was busy as we continued to identify and secure new opportunities for
our partners to participate in the growing demand for our integrated services and capabilities.
Through acquisitions and opportunities to add services around our existing asset base, as well
as additional integration of our service capabilities, we experienced increased demand of our
services. These new opportunities have created and will continue to create volume growth,
probably the most critical operating metric for us. Our initiatives and strong business
fundamentals resulted in record segment margin of $262.3 million, a 30% increase over 2011.
We also generated record available cash before reserves of $179.2 million for the year. Our
operational highlights and accomplishments in 2012 included the following:
We achieved significant segment margin improvements in our Pipeline Transportation
and Supply and Logistics segments which improved over 2011 by approximately 42%
and 55%, respectively.
In Pipeline Transportation, we completed the acquisition of interests in several Gulf of
Mexico crude oil pipeline systems from Marathon Oil Corporation, including a 28%
ownership interest in Poseidon Oil Pipeline Company, LLC. We also commenced
construction with Enterprise Products Partners, L.P. of the South East Keathley Canyon
crude oil gathering pipeline in the deepwater Gulf of Mexico, allowing us to
interconnect with existing shallow-water pipelines for delivery of crude oil produced
from deepwater reservoirs to multiple refinery markets in the Gulf Coast. The new
pipeline is expected to begin service by mid-2014. We were able to increase volumes
on our Texas pipeline system by almost 15% due to strong demand for light sweet
crude oil from our refinery customers. Our new crude-by-rail unloading terminal at
Walnut Hill, Florida increased volumes on our Jay System.
In Supply and Logistics, we achieved improved operating results by increasing
volumes, improving operating efficiencies and changing certain existing crude oil and
petroleum product arrangements. Increased production from new sources of crude oil,
principally from liquids rich shale plays, contributed to the increased demand for our
services. We added crude by rail capabilities in Florida and West Texas and
commissioned our new crude oil terminal and barge dock in Texas City.
To meet the working capital requirements of our growing business and to provide for
future growth opportunities, we increased the committed amount under our senior
secured credit facility from $775 million to $1 billion. We issued $100 million of
unsecured notes in February 2012.
The distribution for the fourth quarter of 2012 represented the thirtieth consecutive
quarter with an increase in the per unit distribution. During this period, twenty-five of
those quarterly increases have been 10% or greater year-over-year. The fourth quarter
distribution of $0.485 per unit, paid in February 2013, represents a 10% increase in the
distribution paid over the year earlier period.
We expect to complete several additional growth projects in 2013 including our new
18-inch pipeline from Webster to Texas City; our crude gathering system in the Niobrara shale
development in Wyoming; our Natchez, Mississippi terminal improvements for steaming and
unloading railcars loaded with bitumen/dilbit originating in Alberta, Canada; and additional
tankage at Walnut Hill, Florida and in West Texas to allow us to expand our crude-by-rail
operations in those areas. We also plan to invest $125 million to improve existing assets and
develop new infrastructure in Louisiana, connecting to Exxon Mobil Corporation’s Baton
Rouge refinery. This infrastructure will include improving our existing terminal at Port
Hudson, constructing a new 20-inch pipeline, and adding a crude oil unit train unloading
facility. These facilities will be completed in 2013 and 2014.
In early February 2013, we completed an offering of $350 million of senior unsecured
notes and used the proceeds to pay down borrowings under our revolving credit facility and for
general partnership purposes, giving us approximately $800 million of availability under our
revolving credit facility to comfortably be able to complete all of our announced projects
without having to issue equity.
The fundamentals of our business are strong and in the coming years we don’t expect
those fundamentals to materially change. It goes without saying that our growth and success
in enhancing long-term value for our unitholders would not be possible without the
contribution of our employees and their dedication to safe, reliable and efficient operations.
Because of their efforts, we were able to deliver the thirtieth consecutive quarterly increase in
the distribution paid to our unitholders. We are targeting to keep that trend going in 2013,
while maintaining a conservative and flexible capital structure. We believe we’ve already
made and, are currently making, the investments necessary to build value for all of our
stakeholders in the years to come. Our goal is unchanged, and that is to create long-term
value for all of our stakeholders. The opportunities in front of us are great.
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, 2012
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, or a smaller reporting
company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange
Act.
Large accelerated filer
Non-accelerated filer
Accelerated filer
Smaller reporting company
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, 2012 (the last business day of
Registrant’s most recently completed second fiscal quarter) was approximately $1.6 billion based on $29.07 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 22, 2013, the Registrant had 81,162,755 Class A common units outstanding.
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GENESIS ENERGY, L.P.
2012 FORM 10-K ANNUAL REPORT
Table of Contents
Part I
Part II
Item 1
Business
Item 1A.
Risk Factors
Item 1B.
Unresolved Staff Comments
Properties
Legal Proceedings
Mine Safety Disclosures
Item 2.
Item 3.
Item 4.
Item 5.
Item 6.
Item 7.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
Selected Financial Data
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 Stockholder Matters
Item 13.
Certain Relationships and Related Transactions, and Director Independence
Item 14.
Principal Accountant Fees and Services
Item 15.
Exhibits and Financial Statement Schedules
Part IV
2
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 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 and
other such references are forward-looking statements. These forward-looking statements are identified as any statement that
does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “continue,” “estimate,”
“expect,” “forecast,” “goal,” “intend,” “may,” “could,” “plan,” “position,” “projection,” “strategy,” “should” or “will,”
or the negative of those terms or other variations of them or by comparable terminology. In particular, statements, expressed or
implied, concerning future actions, conditions or events or future operating results or the ability to generate sales, income or
cash flow are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks,
uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from
those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our
ability or the ability of our affiliates to control or predict. Specific factors that could cause actual results to differ from those in
the forward-looking statements include, among others:
•
demand for, the supply of, our assumptions about, changes in forecast data for, and price trends related to crude
oil, liquid petroleum, NaHS, 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;
•
throughput levels and rates;
3
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
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 energy 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 or other businesses for which we transport
crude oil, petroleum or other products or to whom we sell such 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, 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 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 indenture governing our notes, which contain various affirmative and
negative covenants;
loss of key personnel;
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;
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.
4
Item 1. Business
General
PART I
We are a growth-oriented master limited partnership formed in Delaware in 1996 and focused on the midstream
segment of the oil and gas industry in the Gulf Coast region of the United States, primarily Texas, Louisiana, Arkansas,
Mississippi, Alabama, Florida and in the Gulf of Mexico. Our common units are traded on the New York Stock Exchange under
the ticker symbol “GEL.” Our principal executive offices are located at 919 Milam, Suite 2100, Houston, Texas 77002 and our
telephone number is (713) 860-2500. Except to the extent otherwise provided, the information contained in this annual report is
as of December 31, 2012.
We provide an integrated suite of services to oil producers, refineries, and industrial and commercial enterprises that
use NaHS and caustic soda. Our business activities are primarily focused on providing services around and within refinery
complexes. Upstream of the refineries, we provide gathering and transportation of crude oil. Within the refineries, we provide
services to assist in their sulfur balancing requirements. Downstream of refineries, we provide transportation services as well as
market outlets for their finished refined products. 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 trucks.
Substantially all of our revenues are derived from providing services to integrated oil companies, large independent oil and gas
or refinery companies, and large industrial and commercial enterprises.
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. Since our acquisition of all of the equity interest in our
general partner in December 2010, our outstanding common units and waiver units representing limited partner interest
constitute all of the economic equity interest in us.
We manage our businesses through three divisions that constitute our reportable segments – Pipeline Transportation,
Refinery Services, and Supply and Logistics.
Pipeline Transportation Segment
Overview
We own interests in approximately 1,500 miles of crude oil pipelines located in the Gulf Coast region of the United
States. We also own two CO2 pipelines. Our pipelines generate cash flows from fees charged to customers or substantially
similar arrangements that otherwise limit our exposure to changes in commodity prices.
Crude Oil Pipelines
We own interests in three onshore crude oil pipeline systems, with approximately 460 miles of pipe located primarily
in Alabama, Florida, Mississippi and Texas. The FERC regulates the rates charged by two of our onshore systems to their
customers. The rates for the other onshore pipeline are regulated by the Railroad Commission of Texas. We also own interests
in various offshore crude oil pipeline systems, with approximately 1,050 miles of pipe and an aggregate design capacity of
approximately 1,300 MBbls per day, located offshore in the Gulf of Mexico, a producing region representing approximately
20% of the crude oil production in the United States in 2012. For example, we own a 28% interest in the Poseidon pipeline
system and a 50% interest in the Cameron Highway pipeline system, or CHOPS, which is the largest crude oil pipeline (in
terms of both length and design capacity) located in the Gulf of Mexico. We acquired our interest in Poseidon, along with
certain other pipeline interests, on January 3, 2012.
CO2 Pipelines
We own interests in 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 a large, independent oil company
through 2028. 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. We receive a fixed quarterly payment under the NEJD arrangement.
Payments on the Free State pipeline are dependent on throughput.
Refinery Services Segment
We primarily (i) provide services to nine refining operations located primarily in Texas, Louisiana, Arkansas and Utah;
(ii) operate significant storage and transportation assets in relation to those services; and (iii) sell NaHS and caustic soda to
large industrial and commercial companies. Our refinery services primarily involve processing refiners’ high sulfur (or “sour”)
5
gas streams to remove the sulfur. Our refinery services footprint also includes terminals, and we utilize railcars, ships, barges
and trucks to transport product. Our refinery services contracts are typically long-term in nature and have an average remaining
term of four years. NaHS is a by-product derived from our refinery 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 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.
Supply and Logistic Segment
We provide supply and logistics services primarily to Gulf Coast oil and gas producers and refineries 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 portfolio of logistical assets
consisting of trucks, terminals, pipelines, railcars, rail loading and unloading facilities, and barges. We have access to a suite of
more than 300 trucks, 350 trailers, 180 rail cars, and terminals and tankage with 1.7 million barrels of storage capacity in
multiple locations along the Gulf Coast as well as capacity associated with our three common carrier crude oil pipelines. Our
marine operations include access to 50 barges with a combined transportation capacity of 1.5 million barrels of heavy refined
petroleum products, including asphalt, and 22 push/tow boats. Approximately half of our barges would be capable of
transporting crude oil if we were to make minor modifications. Usually, our supply and logistics segment experiences limited
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.
Our Objectives and Strategies
Our primary business objectives are to generate stable cash flows that allow us to make quarterly cash distributions to
our unitholders and to increase those distributions over time. We plan to achieve those objectives by executing the following
business and financial strategies.
Business Strategy
Our primary business strategy is to provide an integrated suite of services to oil and gas producers, refineries and other
customers. Successfully executing this strategy should enable us to generate and grow sustainable cash flows. 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 refinery services and supply and logistics 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 commodity price risks;
• Maintain a sound, disciplined capital structure; and
• Create strategic arrangements and share capital costs and risks through joint ventures and strategic alliances.
6
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 three
business segments and own and operate assets that enable us to provide a number of services to oil and CO2 producers;
refinery owners; and industrial and commercial enterprises that use NaHS and caustic soda. Our business lines
complement each other by allowing us to offer an integrated suite of services to common customers across segments.
•
Through our NaHS sales, we have indirect exposure to fast-growing, developing economies outside of the U.S. We sell
NaHS to the mining and pulp and paper industries, which sell copper and other mined materials and paper products in
the global market.
• We have lower commodity price risk exposure. The volumes of crude oil, refined products or intermediate feedstocks
that we purchase are either subject to back-to-back sales contracts or are hedged with NYMEX derivatives to limit our
exposure to movements in the price of the commodity. Our risk management policy requires that we monitor the
effectiveness of the hedges to maintain a value at risk of such hedged inventory that does not exceed $2.5 million. In
addition, our service contracts with refiners allow us to adjust our processing rates to maintain a balance between
NaHS supply and demand.
• Our businesses provide consistent consolidated financial performance. Our consistent and improving financial
performance, combined with our conservative capital structure, has allowed us to increase our distribution for thirty
consecutive quarters as of our most recent distribution declaration. During this period, twenty-five of those quarterly
increases have been 10% or greater year-over-year.
• Our pipeline transportation and related assets are strategically located. Our crude oil pipelines are located in the Gulf
of Mexico and provide our customers access to multiple delivery points. In addition, a majority of our terminals are
located in areas that can be accessed by truck, rail or barge.
• We believe we are one of the largest marketers of NaHS in North and South America. We believe the scale of our well-
established refinery services operations as well as our integrated suite of assets provides us with a unique cost
advantage over some of our existing and potential competitors.
• 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 refinery services market can
provide us with an advantage when evaluating new opportunities and/or markets.
• Our supply and logistics business is 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.
• We are financially flexible and have significant liquidity. As of December 31, 2012, we had $483.3 million available
under our $1 billion credit agreement, including up to $86.1 million available under the $150 million petroleum
products inventory loan sublimit, and $83.3 million available for letters of credit. Our inventory borrowing base was
$63.9 million at December 31, 2012.
• 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 Growth Initiatives
The following is a brief listing of developments since December 31, 2011. Additional information regarding most of
these items may be found elsewhere in this report.
Gulf Coast Infrastructure
We plan to invest approximately $125 million to improve existing assets and develop new infrastructure in Louisiana,
including connecting to Exxon Mobil Corporation’s Baton Rouge refinery, one of the largest refinery complexes in North
America, with more than 500,000 barrels per day of refining capacity. Our investment includes improving our existing terminal
at Port Hudson, Louisiana, constructing a new 18-mile 20-inch diameter crude oil pipeline connecting Port Hudson to the
Baton Rouge Maryland Terminal and continuing downstream to the Anchorage Tank Farm and building a new crude oil unit
7
train facility at the Maryland Terminal. The Port Hudson upgrades and new crude oil pipeline are expected to be completed by
the end of 2013 and the Maryland Terminal completion is scheduled for the second quarter of 2014.
Deepwater Gulf of Mexico Pipeline Joint Venture
Southeast Keathley Canyon Pipeline Company LLC, or SEKCO, a joint venture with Enterprise Products Partners,
L.P., is constructing a deepwater pipeline serving the Lucius development area in southern Keathley Canyon of the Gulf of
Mexico. SEKCO has entered into crude oil transportation agreements with six Gulf of Mexico producers, including Anadarko
U.S. Offshore Corporation, Apache Deepwater Development LLC, Exxon Mobil Corporation, Eni Petroleum US LLC,
Petrobras America and Plains Offshore Operations, Inc. Those producers have dedicated their production from Lucius to the
pipeline for the life of the reserves. We expect the pipeline to provide capacity for additional projects in the deepwater Gulf of
Mexico. Enterprise Products serves as construction manager and will be the operator of the new pipeline.
The 149-mile, 18-inch diameter pipeline, designed to have a 115,000 barrel per day capacity, will connect the Lucius-
truss spar floating production platform to an existing junction platform at South Marsh Island that is part of the recently
acquired Poseidon pipeline system described above. The new pipeline is expected to begin service by mid-2014. See additional
discussion regarding this project in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of
Operations – Liquidity and Capital Resources.”
Texas City Projects
In the fourth quarter of 2012, we completed two projects to increase the services we provide to producers and refiners.
We acquired three above-ground storage tanks located in Texas City, Texas and an existing barge dock at the same location, all
approximately 1.5 miles from our existing Texas pipeline system. We also constructed a truck station and tankage in West
Columbia, Texas to provide incremental transportation service for the Eagle Ford Shale and other Texas production through our
pipeline system to refining markets in the greater Houston/Texas City area. We are able to handle approximately 40,000 barrels
per day of crude oil through the Texas City terminal. In addition, we have initiated construction of a 18-inch diameter loop of
our existing crude oil pipeline into Texas City, supported by a term contract with one of our refining customers, which we
expect will allow us to significantly expand our total service capabilities into the Texas City area by the late second quarter or
early third quarter of 2013.
HollyFrontier Tulsa Project
We are installing a new sour gas processing facility at Holly Refining and Marketing’s refinery complex located in
Tulsa, Oklahoma. The new facility, expected to be operational in mid-2013, will remove a portion of the sulfur from the crude
oil refined at Holly’s complex and is expected to result in potential additional capacity of 24,000 DST per year of NaHS.
Rail Projects
In August 2012, we completed construction on the first phase of a new crude-by-rail unloading terminal connected to
our existing crude oil pipeline at Walnut Hill, Florida. This facility is capable of handling unit train shipments of oil for direct
deliveries to an existing refinery customer and indirect deliveries (through third-party common carriers) to multiple other
markets in the Southeast at the option of the shippers. We anticipate the second phase of the terminal, which includes a 100,000
barrel storage tank and related equipment, to be fully operational in March of 2013.
In 2012, we completed initial phase construction of a crude oil rail loading facility in Wink, Texas, giving us the
capability to load Genesis and third party railcars designed to move West Texas production to more highly valued markets.
Additional expansion of this facility, which we estimate will be fully operational by late third quarter or early fourth quarter of
2013, will allow us to increase the capacity of this system.
In 2012, we commenced construction on a crude oil rail unloading/loading facility at our existing terminal located in
Natchez, Mississippi, which is designed to facilitate the movement of Canadian bitumen/dilbit to Gulf Coast markets. The
facility will have the capability to unload bitumen/dilbit as well as loading diluent for backhauls to Canada. In the first quarter
of 2013, we steamed and unloaded into tanks the first railcars loaded with bitumen/dilbit originating in Alberta, Canada.
Wyoming Gathering Project
We are re-activating portions of the related gathering and transportation pipelines in Wyoming and constructing a new
pipeline which will connect to the Casper, Wyoming markets. We anticipate the re-activation of existing pipelines and the new
pipeline will be completed in the second quarter of 2013.
Thirty Consecutive Distribution Rate Increases
We have increased our quarterly distribution rate for thirty consecutive quarters. During this period, twenty-five of
those quarterly increases have been 10% or greater year-over-year. On February 14, 2013, we paid a quarterly cash distribution
of $0.4850 (or $1.94 annually) per unit to unitholders of record as of February 1, 2013, an increase per unit of $0.0125 (or
8
2.6%) from the distribution in the prior quarter, and an increase of 10.2% from the distribution in February 2012. As in the past,
future increases (if any) in our quarterly distribution rate will depend on our ability to execute critical components of our
business strategy.
Organizational Structure
The following chart depicts our organizational structure at December 31, 2012.
Description of Segments and Related Assets
We conduct our business through three primary segments: Pipeline Transportation, Refinery Services and Supply and
Logistics. 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 12 to our Consolidated Financial Statements in Item 8.
Pipeline Transportation
Overview
We own three onshore crude oil common carrier pipelines, interests in several offshore crude oil pipeline systems in
the Gulf of Mexico and two CO2 pipelines. Our core pipeline transportation business is the transportation of crude oil for others
for a fee.
9
Crude Oil Pipelines
Onshore Crude Oil Pipelines.
Through the onshore pipeline systems 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 (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 three onshore common carrier crude oil pipeline systems: the Texas System, the Jay System and
the Mississippi System.
Product
Interest Owned
System Miles
Approximate Owned and leased tankage
storage capacity (Bbls)
Location
Texas System
Crude Oil
100%
90
220,000
West Columbia, TX to
Webster, TX
Webster, TX to Texas
City, TX
Webster, TX to Houston,
TX
Jay System
Crude Oil
100%
135
230,000
Mississippi System
Crude Oil
100%
235
247,500
Southern AL/FL to
Mobile, AL
Soso, MS to Liberty, MS
Rate Regulated
TXRRC
FERC
FERC
•
•
Texas System. Our Texas System transports crude oil from West Columbia to several delivery points near Houston,
Texas. The Texas System receives all of its volume from connections to other pipeline carriers. We earn a tariff for our
transportation services, with the tariff rate per barrel of crude oil varying with the distance from injection point to
delivery point.
Jay System. Our Jay System provides crude oil shippers access to refineries, pipelines and storage near Mobile,
Alabama. The system also includes gathering connections to approximately 35 wells, additional oil storage capacity of
20,000 barrels in the field and a delivery connection to a refinery in Alabama.
• 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. The system is adjacent to
several 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.
Offshore Crude Oil Pipelines.
We own interests in several crude oil pipelines located offshore in the Gulf of Mexico, a producing region representing
approximately 20% of the crude oil production in the United States in 2012. CHOPS is the largest crude oil pipeline (in terms
of both length and design capacity) located in the Gulf of Mexico. The table below reflects our interests in our operating
offshore crude oil pipelines.
10
Product
Interest Owned (1)
System Miles
Capacity (Bbls/day)
2012 Throughput (Bbls/day)
Location
Rate Regulated
In-Service Date
CHOPS
Crude Oil
50%
380
500,000
96,664
Poseidon
Crude Oil
28%
367
400,000
211,375
Odyssey
Crude Oil
29%
120
200,000
36,157
Eugene Island
Crude Oil
23%
183
200,000
15,191
Gulf of Mexico
(primarily offshore
of Texas and
Louisiana)
Gulf of Mexico
(primarily offshore
of Louisiana)
Gulf of Mexico
(primarily offshore
of Louisiana)
Gulf of Mexico
(primarily offshore
of Louisiana)
No
2004
No
1996
No
1998
FERC
1983
(1) We acquired our interests in CHOPS in November 2010 and our interests in our other offshore pipelines in January 2012.
• CHOPS. CHOPS is comprised of 24- to 30-inch diameter pipelines to deliver crude oil from developments 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. Enterprise
Products owns the remaining 50% interest in, and operates, the joint venture. The pipeline has significant available
capacity to accommodate future growth in the fields from which the production is dedicated to the pipeline as well as
to transport volumes from non-dedicated fields both currently in production and to be developed in the future.
• 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. Affiliates of Enterprise Products and Shell each own a 36% interest in Poseidon. An affiliate of
Enterprise Products serves as the operator.
• 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, and an affiliate of Shell serves as the operator.
• Eugene Island. The Eugene Island system is comprised of a network of crude oil pipelines, the main pipeline of which
is 20 inches in diameter, to deliver crude oil from developments in the central Gulf of Mexico to other pipelines and
terminals onshore Louisiana. Other owners in Eugene Island include affiliates of Exxon-Mobil, Chevron-Texaco,
ConocoPhillips and Shell Oil Company. An affiliate of Shell serves as the operator.
•
SEKCO Pipeline. As described in “Recent Developments” we entered into a joint venture with Enterprise Products to
construct a deepwater pipeline serving the Lucius development area in southern Keathley Canyon of the Gulf of
Mexico. The pipeline is expected to begin service by mid-2014.
11
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"
NEJD System (1)
CO2
100%
183
20"
Jackson Dome near Jackson, MS
to East Mississippi
Jackson Dome near Jackson, MS
to Donaldsonville, LA
No
No
(1) Subject to a fixed payment agreement.
Our Free State pipeline extends from CO2 source fields near Jackson, Mississippi to oil fields in eastern Mississippi.
We have a twenty-year transportation services agreement (through 2028) related to the transportation of CO2 on our Free State
pipeline.
Denbury Resources, Inc., or Denbury, has leased the NEJD System from us through 2028. Our NEJD System
transports CO2 to tertiary oil recovery operations in southwest Mississippi.
Customers
Our customers on our Mississippi, Jay and Texas systems are primarily large, energy companies. Denbury has
exclusive use of the NEJD Pipeline System and is responsible for all operations and maintenance on that system and will bear
and assume all obligations and liabilities with respect to that system. Currently, Denbury also has rights to exclusive use of our
Free State pipeline.
Due to the cost of finding, developing and producing oil properties in the deepwater regions of the Gulf of Mexico,
most of our offshore pipeline customers are integrated oil companies and other large producers, and those producers desire to
have longer-term arrangements ensuring that their production can access the markets. The anchor customers for CHOPS
(including subsidiaries of BP p.l.c., BHP Billiton Group and Chevron Corporation) dedicated their production from
approximately 86,400 acres to CHOPS for the life of the reserves underlying such acreage, which dedications included Mad
Dog and Atlantis fields as well as other deepwater oil discoveries. Those producer agreements include both firm and, to the
extent CHOPS has any remaining capacity, interruptible capacity arrangements. Since its formation, CHOPS has entered into
handling arrangements with numerous other producers pursuant to both firm and interruptible capacity arrangements covering
deepwater discoveries, including Constitution, Ticonderoga, K2, Shenzi, Front Runner, Cottonwood and Tahiti. Our primary
customers for our Poseidon system include BHP Billiton Group, Repsol, Hess and Anadarko Petroleum Corporation, primarily
from the Shenzi, Allegheny and K2 Complex developments in addition to other deepwater developments. Anadarko, Chevron,
ENI, Marathon, Murphy, Statoil and Hess have dedicated their production to Poseidon from the Allegheny, Marco Polo,
Droshky, Bald Plate, Front Runner and Lobster fields.
Usually, our offshore 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 pipeline transportation segment did not account for more than ten percent of our
consolidated revenues.
Competition
Competition among common carrier pipelines is based primarily on posted tariffs, quality of customer service and
proximity to production, refineries 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.
12
The principal competition for our offshore pipelines includes other crude oil 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, 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.
Refinery Services
Our refinery services segment (i) provides sulfur-extraction services to nine refining operations primarily located in
Texas, Louisiana, Arkansas and Utah, (ii) operates significant storage and transportation assets in relation to our business and
(iii) sells NaHS and caustic soda (or NaOH) to large industrial and commercial companies. Our refinery services activities
involve processing 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 refinery services
activities. A majority of the NaHS we receive is sourced from refineries owned and operated by large companies, including
Phillips 66, CITGO, HollyFrontier, and Ergon.
Our refinery services footprint includes terminals in the Gulf Coast, the Midwest, Montana, Utah, British Columbia
and South America. We also utilize railcars, ships, barges and trucks to transport product. In conjunction with our supply and
logistics segment, we sell and deliver NaHS and caustic soda to over 100 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. Our refinery services contracts
are typically long-term in nature. The average remaining life of our refinery services contracts is four years. 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 services utilizing NaHS units at nine refining locations, and we manage sulfur removal by
exclusive rights to market NaHS produced at three third-party sites. While some of our customers have elected to own the
sulfur removal facilities located at their refineries, we operate those facilities. These NaHS facilities are located primarily in the
southeastern United States.
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 United States, Canada and Mexico. We also export the NaHS to South America for sale to customers for mining in
Peru and Chile. No customer of the refinery services segment is responsible for more than ten percent of our consolidated
revenues. Approximately 10% of the revenues of the refinery services segment in 2012 resulted from sales to Kennecott Utah
Copper, a subsidiary of Rio Tinto plc. 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 copper mining. We also supply caustic soda to some of the refineries in which we operate for use in cleaning
processing equipment.
13
Competition
Our competitors for the supply of NaHS consist primarily of parties who produce NaHS as a by-product of processes
involved with agricultural pesticide products, plastic additives and lubricant viscosity. Typically our competitors for the
production of NaHS have only one manufacturing location and they do not have the logistical infrastructure that we have to
supply customers. Our primary competitor has been AkzoNobel, a chemical manufacturing company that produces NaHS
primarily in its pesticide operations.
Our competitors for sales of caustic soda include manufacturers of caustic soda. These competitors supply caustic soda
to our refinery services operations and support us in our third-party NaOH 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
NaOH from one source.
Supply and Logistics
We provide supply and logistics services to Gulf Coast oil and gas producers and refineries 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 portfolio of logistical assets consisting of
trucks, terminals, pipelines, railcars and barges. Our crude oil related services include gathering crude oil from producers at the
wellhead, transporting crude oil by truck to pipeline injection points and marketing crude oil to refiners. Not unlike our crude
oil operations, we also gather refined products from refineries, transport refined products via truck, railcar or barge, and sell
refined products to customers in wholesale markets. For these services, we generate fee-based income and 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
oil and products, minus the associated costs of aggregation and transportation.
Our crude oil supply and logistics operations are concentrated in Texas, Louisiana, Alabama, Florida and
Mississippi. These operations help to ensure (among other things) a base supply source for our oil pipeline systems and our
refinery customers while providing our producer customers with a market outlet for their production. Usually, our supply and
logistics segment experiences limited 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 primarily with NYMEX derivatives to offset the
remaining price risk. By utilizing our network of trucks, rail, barges, terminals and pipelines, we are able to provide
transportation related services to crude oil producers and refiners as well as enter into back-to-back gathering and marketing
arrangements with these same parties. 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
transport approximately 50,000 barrels per day of crude oil, much of which is produced from large and growing resource basins
throughout Texas and the Gulf Coast. Given our network of terminals, we have the ability to store crude oil during periods of
contango (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 limit 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.
Our refined products supply and logistics operations are concentrated in the Gulf Coast region, principally Texas and
Louisiana. Through our footprint of owned and leased trucks, leased railcars, terminals and barges, we are able to provide Gulf
Coast area refineries with transportation services as well as market outlets for their 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. By
utilizing our broad network of relationships and logistics assets, including our terminal accessibility, 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. Alternatively, our refinery customers may choose to manufacture such refined products
depending on a number of economic and operating factors, and therefore we cannot predict the timing of contribution margins
related to our blending services. We recently completed two crude oil rail loading/unloading facilities in Walnut Hill, Florida
and Wink, Texas which provide synergies to our existing asset footprint. An additional crude oil rail facility in Natchez,
Mississippi, estimated to be completed in the first quarter of 2013, will facilitate the movement of Canadian bitumen/dilbit
markets in the Gulf of Mexico. We generally earn a fee for loading or unloading railcars at these facilities. Our industrial gases
supply and logistics operations supply CO2, which we acquire pursuant to our volumetric production payments (also known as
VPPs) to industrial customers currently under four long-term contracts, with an average remaining contract life of five years.
Our existing customer contracts expire between 2015 and 2023. At December 31, 2012, we had approximately 53.3 Bcf of CO2
remaining under the VPPs. All of our CO2 supply is currently from our interests—our VPPs—in fields producing naturally
occurring CO2. We do not expect to renew or replace our CO2 supply agreements.
14
Within our supply and logistics business segment, we employ many types of logistically flexible assets. These assets
include 300 trucks, 350 trailers, 180 rail cars, 50 barges with approximately 1.5 million barrels of refined products
transportation capacity, 22 push/tow boats, and terminals and other tankage with 1.7 million barrels of leased and owned
storage capacity in multiple locations along the Gulf Coast, accessible by truck, rail or barge. Our leased rail cars consist of
approximately 80 refined product rail cars and 100 crude oil rail cars. We will take delivery of approximately 400 leased crude
oil rail cars in 2013. Our marine fleet 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 United States,
including the Red, Ouachita and Mississippi Rivers. Approximately half of our barges would be capable of transporting crude
oil if we were to make minor modifications.
Customers
Our supply and logistics business encompasses hundreds of producers and customers, for which we provide
transportation related services, as well as gather from and market to crude oil, refined products and CO2. During 2012, more
than 10% of our consolidated revenues were generated from Shell. We do not believe that the loss of any one customer for
crude oil, petroleum products or CO2 would have a material adverse effect on us as these products are readily marketable
commodities.
Competition
In our crude oil supply and logistics operations, we compete with other midstream service providers and regional and
local companies who may have significant market share in the areas in which they operate. In our refined products supply and
logistics operations, we compete primarily with regional companies. Competitive factors in our supply and logistics 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.
Geographic Segments
All of our operations are in the United States. Additionally, we transport and sell NaHS to customers in South America
and Canada. Revenues from customers in foreign countries totaled approximately $19.3 million, $19.7 million and $14.5
million in 2012, 2011 and 2010, respectively. The remainder of our revenues was generated from sales to customers in the
United States.
Credit Exposure
Due to the nature of our operations, a disproportionate percentage of our trade receivables constitute obligations of oil
companies, independent refiners, and mining and other industrial companies that purchase NaHS. This energy 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 the obligations of integrated and independent energy companies with stable payment
experience. 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 and petroleum products and NaHS, 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 pipeline transportation segment.
Employees
To carry out our business activities, we employed approximately 950 employees at December 31, 2012. None of our
employees are represented by labor unions, and 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 be filed with FERC and posted publicly.
15
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 the 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 the 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 portion of the rate increase
resulting from application of the index is substantially in excess of the 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, or agreements between shippers and the oil pipeline company that the rate is acceptable, or
Settlement Rates. The pipeline tariff rates on our Mississippi and Jay Systems are either rates that were grandfathered and have
been changed 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 are neither interstate nor common carrier pipelines. However, these pipelines are subject to
federal regulation under the Outer Continental Shelf Lands Act, which requires all pipelines operating on or across the outer
continental shelf to provide nondiscriminatory transportation service.
Our intrastate common carrier pipeline operations in Texas are subject to regulation by the Railroad Commission of
Texas. The applicable Texas statutes require that pipeline rates and practices be reasonable and non-discriminatory and that
pipeline rates provide a fair return on the aggregate value of the property of a common carrier, after providing reasonable
allowance for depreciation and other factors and for reasonable operating expenses. Most of the volume on our Texas System is
now shipped under joint tariffs with Enterprise Products and Exxon. 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 tow boats, barges and marine equipment create maritime obligations involving
property, personnel and cargo 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 by 2015. All of our barges are double-hulled.
Jones Act. The Jones Act is a federal law that restricts maritime transportation between locations in the United States
to vessels built and registered in the United States and owned and manned by United States 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 United States-flag vessel operations compared to foreign-flag vessel operations. Further, the USCG
and American Bureau of Shipping, or ABS, maintain the most stringent regime of vessel inspection in the world, which tends to
result in higher regulatory compliance costs for United States-flag operators than for owners of vessels registered under foreign
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 that provides that, upon
proclamation by the president of the United States of a national emergency or a threat to the national security, the United States
Secretary of Transportation may requisition or purchase any vessel or other watercraft owned by United States citizens
(including us, provided that we are considered a United States citizen for this purpose). If one of our tow boats or barges were
purchased or requisitioned by the United States 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.
16
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 require the acquisition of and
compliance with permits for regulated activities, limit or prohibit operations on environmentally sensitive lands such as
wetlands or wilderness areas or areas inhabited by endangered or threatened species, result in capital expenditures to limit or
prevent emissions or discharges, and 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 oil and gas
exploration and production wastes as “hazardous wastes.” Any such changes in the laws and regulations could have a material
adverse effect on our capital expenditures and operating expenses.
We believe that we are in substantial compliance with the requirements of CERCLA, RCRA and related state and local
laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations required
under such laws and regulations. Although we believe that the current costs of managing our wastes as they are presently
classified are reflected in our budget, any legislative or regulatory reclassification of oil and natural gas exploration and
production wastes could increase our costs to manage and dispose of such wastes.
Water
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 oil, into navigable waters of
the United States, as well as state waters. Permits must be obtained to discharge pollutants into these waters. In addition, the
Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm
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water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from
certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or
operations that may impact groundwater conditions. The Oil Pollution Act, or the OPA, is the primary federal law for oil spill
liability. The OPA contains numerous requirements relating to the prevention of and response to oil spills into waters of the
United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing
waterways must maintain certain significant levels of financial assurance to cover potential environmental cleanup and
restoration costs. Under the OPA, strict, joint and several liability may be imposed on “responsible parties” for all containment
and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a
release of oil to surface waters and natural resource damages, resulting from oil spills into or upon navigable waters, adjoining
shorelines or in the exclusive economic zone of the United States. A “responsible party” includes the owner or operator of an
onshore facility.
Noncompliance with the Clean Water Act or the OPA may result in substantial civil and criminal penalties. We believe
we are in material compliance with each of these requirements.
Air Emissions
The Federal Clean Air Act, 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.
NEPA
Under the National Environmental Policy Act, or NEPA, a federal agency, commonly in conjunction with a current
permittee or applicant, may be required to prepare an environmental assessment or a detailed environmental impact statement
before taking any major action, including issuing a permit for a pipeline extension or addition that would affect the quality of
the environment. Should an environmental impact statement or environmental assessment be required for any proposed
pipeline extensions or additions, NEPA may prevent or delay construction or alter the proposed location, design or method of
construction.
Climate Change
In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse
gases 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 by the EPA allowed the
agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under
existing provisions of the CAA. Among such regulations, the EPA adopted its "tailoring rule," which became effective in
January 2011 and establishes new thresholds that determine which stationary sources of greenhouse gases are required to obtain
permits and implement best available control technology standards on account of their greenhouse gas emission levels. The
EPA has also adopted rules limiting greenhouse gas emissions from new motor vehicles and creating reporting requirements for
large greenhouse gas emissions sources.
Further, Congress has considered various proposals to reduce greenhouse gas emissions that may impose a carbon
emissions tax, a cap-and-trade program or other programs aimed at carbon reduction, including the American Clean Energy and
Security Act of 2009, passed by the U.S. House of Representatives in June 2009 and a similar bill in the U.S. Senate. Either bill
would have established an economy-wide cap-and-trade program to reduce U.S. emissions of greenhouse gases including
carbon dioxide and methane that may contribute to the warming of the earth's atmosphere and other climatic changes. The
current administration supports legislation to reduce greenhouse gas emissions through an emission allowance system. As
allowances under such a system would be expected to significantly escalate in cost over time, the net effect of any potential
cap-and-trade legislation would be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined
petroleum products and natural gas. In addition, at least one-third of the states, either individually or through multi-state
regional initiatives, have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned
development of greenhouse gas emission inventories and/or greenhouse gas cap-and-trade programs. Our compliance with any
future legislation or regulation of greenhouse gases, if it occurs, may result in materially increased compliance and operating
costs. It is not possible at this time to predict with any accuracy the structure or outcome of any future legislative or regulatory
efforts to address such emissions or the eventual costs to us of compliance.
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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 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. 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 DOT 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. Due to the proximity of all of our pipelines to water crossings and populated areas, we have
designated all of our pipelines as affecting HCAs. 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.
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 refinery 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
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 United States 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.
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
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practicable after we electronically file the material with, or furnish it to, the SEC. Additionally, these documents are available at
the SEC’s website (www.sec.gov). 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
We may not be able to fully execute our growth strategy if we are unable to raise debt and equity capital at an affordable
price.
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.
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.
The capital and credit markets have been, and may continue to be, disrupted and volatile as a result of adverse
conditions. The government response to the disruptions in the financial markets may not adequately restore investor or
customer confidence, stabilize such markets, or increase liquidity and the availability of credit to businesses. If the credit
markets continue to experience volatility and the availability of funds remains limited, we may experience difficulties in
accessing capital for significant growth projects or acquisitions which could adversely affect our strategic plans.
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.
Economic developments in the United States and worldwide in credit markets and concerns about economic growth
could impact our operations and materially reduce our profitability and cash flows.
Continued uncertainty in the credit markets and concerns about local and global economic growth have had a
significant adverse impact on global financial markets. If these disruptions, which have occurred over the last several years,
reappear, they could negatively impact our cash flows and profitability. Tightening of the credit markets, lower levels of
liquidity in many financial markets, and extreme volatility in fixed income, credit and equity markets could limit our access to
capital.
Additionally, significant decreases in our operating cash flows could affect the fair value of our long-lived assets and
result in impairment charges. At December 31, 2012, we had $325 million of goodwill recorded on our Consolidated Balance
Sheet.
Fluctuations in interest rates could adversely affect our business.
We have exposure to movements in interest rates. The interest rates on our credit facility ($500 million outstanding at
December 31, 2012) 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 refinery
services, pipeline transportation, and supply and logistics businesses, which fluctuate from quarter to quarter based on, among
other things:
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the volumes and prices at which we purchase and sell crude oil, refined products, and caustic soda;
the volumes of sodium hydrosulfide, or NaHS, that we receive for our refinery services and the prices at which we sell
NaHS;
the demand for our trucking, barge and pipeline transportation services;
the demand for our terminal storage services;
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 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 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, 2012, we had approximately $500
million outstanding of senior secured indebtedness and an additional $350.9 million of senior unsecured indebtedness.
We must comply with various affirmative and negative covenants contained in our credit facilities. Among other
things, these covenants limit our ability to:
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incur additional indebtedness or liens;
• make payments in respect of or redeem or acquire any debt or equity issued by us;
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sell assets;
• make loans or investments;
• make guarantees;
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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:
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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; or to otherwise fully
realize the value of our assets and opportunities because of the need to dedicate a substantial portion of our cash flow
from operations to payments on our indebtedness or to comply with any restrictive terms of our indebtedness;
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limit our flexibility in planning for, or reacting to, changes in our businesses and the industries in which we operate;
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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 facilities, 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 facility or under arrangements that may have terms and conditions at least as restrictive as
those contained in our existing credit facilities. 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 will have the right to accelerate the
maturity of such indebtedness and foreclose upon the collateral, if any, securing that indebtedness. In addition, if there is a
change of control as described in our credit facility, that would be an event of default, unless our creditors agreed otherwise,
and, under our credit facility, any such event could limit our ability to fulfill our obligations under our debt instruments and to
make cash distributions to unitholders which could adversely affect the market price of our securities.
In addition, from time to time, some of our joint ventures may have substantial indebtedness, which will include
affirmative and negative covenants and other provisions that limit their freedom to conduct certain operations, events of
default, prepayment and other customary terms.
Our profitability and cash flow are dependent on our ability to increase or, at a minimum, maintain our current
commodity—oil, refined products, 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 — oil, refined products, NaHS and caustic soda — volumes. We access commodity volumes through two sources,
producers and service providers (including gatherers, shippers, marketers and other aggregators). 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
transportation operations) or we can purchase the commodity from our customer and resell it to another party.
Our source of volumes depends on successful exploration and development of additional oil reserves by others;
continued demand for our refinery 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 oil and refined products available to us 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. Thus, oil production in our market area
may not rise to sufficient levels to allow us to maintain or increase the commodity volumes we are experiencing.
Our ability to access NaHS depends primarily on the demand for our proprietary refinery services 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 refinery services 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 refinery services operations are dependent upon the supply of caustic soda and the demand for NaHS, as well as
the operations of the refiners for whom we process sour gas.
Caustic soda is a major component of the proprietary sour gas 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 product from our refinery services operations, is a vital
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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 sour gas treatment 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. The refineries’ need for our sour gas services is also 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.
Our pipeline transportation operations are dependent upon demand for crude oil by refiners in the Midwest and on the
Gulf Coast.
Any decrease in this demand for crude oil by those refineries or connecting carriers to which we deliver could
adversely affect our cash flows. Those refineries’ need 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.
We face intense competition to obtain oil and refined products commodity volumes.
Our competitors — gatherers, transporters, marketers, brokers and other aggregators — include independents and
major integrated 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 and other 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 producers or refiners to gather, refine, market, transport, store or otherwise handle any of these crude oil reserves, NaHS,
caustic soda or other refined products. We compete with others for any such volumes on the basis of many factors, including:
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geographic proximity to the production;
costs of connection;
available capacity;
rates;
logistical efficiency in all of our operations;
operational efficiency in our refinery services 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 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
and trucks can result in less demand for our transportation services. 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 or transported by our pipelines. As a
result, we may experience declines in our margin and profitability if our volumes decrease.
Fluctuations in commodity prices could adversely affect our business.
Oil, natural gas, other petroleum products, NaHS and caustic soda prices are volatile and could have an adverse effect
on our profits and cash flow. Prices for commodities can fluctuate in response to changes in supply, market uncertainty and a
variety of additional factors that are beyond our control. Price reductions in those commodities can cause material long and
short term reductions in the level of throughput, volumes and, in some cases, margins.
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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 any of 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 purchased at the wellhead, we may
be responsible for distribution of proceeds to all of the interest owners. In other cases, we pay all of or a portion of the
production proceeds to an operator who distributes these proceeds to the various interest owners. These arrangements expose us
to operator credit risk. As a result, we must determine that operators have sufficient financial resources to make such payments
and distributions and to indemnify and defend us in case of a protest, action or complaint.
We sell petroleum products to many wholesalers and end-users that are not large companies and are privately-owned
operations. While those sales are not large volume sales, they tend to be frequent transactions such that a large balance can
develop quickly. Additionally, we sell NaHS and caustic soda to customers in a variety of industries. Many 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.
Additionally, many of our customers were impacted by the weakened economic conditions 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.
Our refinery services division is dependent on contracts with less than fifteen refineries and much of its revenue is
attributable to a few refineries.
If one or more of our refinery customers that, individually or in the aggregate, generate a material portion of our
refinery services revenue experience financial difficulties or changes in their strategy for sulfur removal such that they do not
need our services, our cash flows could be adversely affected. For example, in 2012, approximately 70% of our refinery
services’ division NaHS by-product volumes was attributable to Phillips 66’s refinery located in Westlake, Louisiana. That
contract requires Phillips 66 to make available minimum volumes of sour gas to us (except during periods of force majeure).
Although the primary term of that contract extends until 2018, if, for any reason, Phillips 66 does not meet its obligations under
that contract for an extended period of time, such non-performance could have a material adverse effect on our profitability and
cash flow.
Our operations are subject to federal and state 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 increasingly stringent environmental protection and safety laws and regulations that
restrict our operations, impose consequences of varying degrees for noncompliance, and require us to expend resources in an
effort to maintain compliance. Moreover, our operations, including the transportation and storage of crude oil and other
commodities, involves a risk that crude oil 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.
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 greenhouse
gases 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 by the EPA allowed the
agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under
existing provisions of the CAA. Among several such regulations, the EPA adopted its “tailoring rule,” which became effective
in January 2011 and establishes new thresholds that determine which stationary sources of greenhouse gases are required to
obtain permits and implement best available control technology standards on account of their greenhouse gas emission levels.
The EPA has also adopted rules limiting greenhouse gas emissions from new motor vehicles and creating reporting
requirements for large greenhouse gas emissions sources.
Further, Congress has considered various proposals to reduce greenhouse gas emissions that may impose a carbon
emissions tax, a cap-and-trade program or other programs aimed at carbon reduction, including the American Clean Energy and
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Security Act of 2009, passed by the U.S. House of Representatives in June 2009 and a similar bill in the U.S. Senate. Either bill
would have established an economy-wide cap-and-trade program to reduce U.S. emissions of greenhouse gases including
carbon dioxide and methane that may contribute to the warming of the earth's atmosphere and other climatic changes. The
current administration supports legislation to reduce greenhouse gas emissions through an emission allowance system. As
allowances under such a system would be expected to significantly escalate in cost over time, the net effect of any potential
cap-and-trade legislation would be to impose increasing costs on the combustion of carbon-based fuels such as crude oil,
refined petroleum products and natural gas. In addition, at least one-third of the states, either individually or through multi-state
regional initiatives, have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned
development of greenhouse gas emission inventories and/or greenhouse gas cap-and-trade programs. Our compliance with any
future legislation or regulation of greenhouse gases, if it occurs, may result in materially increased compliance and operating
costs. 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.
The effect on our operations of CAA regulations, legislative efforts or related implementation regulations that regulate
or restrict emissions of greenhouse gases 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 greenhouse gas emissions, pay any taxes related to our
greenhouse gas emissions and administer and manage a greenhouse gas 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.
In addition, some scientists have concluded that increasing concentrations of greenhouse gases in the earth's
atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of
storms, droughts, floods and other climate events; if any such effects were to occur, they could have an adverse effect on our
assets and operations.
Regulation of the rates, terms and conditions of services and a changing regulatory environment could affect our cash
flow.
The FERC regulates certain of our energy infrastructure assets engaged in interstate operations. Our intrastate pipeline
operations are regulated by state 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.
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 flows.
Our growth strategy may adversely affect our results of operations if we do not successfully integrate the businesses that
we acquire or if we substantially increase our indebtedness and contingent liabilities to make acquisitions.
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
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•
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.
If consummated, any acquisition or investment also likely would result in the incurrence of indebtedness and
contingent liabilities and an increase in interest expense and depreciation and amortization expenses. A substantial increase in
our indebtedness and contingent liabilities could have a material adverse effect on our business, as discussed above.
The 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
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.
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.
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 United States was the target of terrorist attacks of unprecedented scale. Since the
September 11 attacks, the U.S. government has issued warnings that energy assets, specifically the nation’s pipeline
infrastructure, may be the future targets of terrorist organizations. These developments have subjected our operations to
increased risks. Any future terrorist attack at our facilities, those of our customers and, in some cases, those of other pipelines,
could have a material adverse effect on our business.
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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 four members, only
two 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 participant and/or the lenders of our joint ventures, 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.
Due to our significant relationships with it, adverse developments concerning Denbury could adversely affect us, even if
we have not suffered any similar developments.
We have some important relationships with Denbury. It is the operator of our largest CO2 pipeline and the operator of
the fields that produce our CO2 reserves. We are also parties to agreements with Denbury, including the lease of our NEJD
System and the transportation arrangements related to the Free State pipeline. Denbury ships substantially all of the crude oil
that is shipped on our Mississippi System. We could be adversely affected if Denbury experiences any adverse developments or
fails to pay us for our services on a timely basis or fails to meet its obligations to us.
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
United States only to vessels operating under the U.S. flag, built in the United States, 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
oil and gas industry in response to the Deepwater Horizon drilling rig incident in the U.S. Gulf of Mexico and subsequent
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 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 United States coastwise trade and significantly increase competition with our
fleet, which could have an adverse effect on our business. Events within the oil and 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 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 oil and gas industry, including us, to additional
regulatory scrutiny and result in additional regulations and restrictions adversely affecting the U.S. oil and gas industry.
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A decrease in the cost of importing refined petroleum products could cause demand for U.S. flag product carrier and
barge capacity and charter rates to decline, which would decrease our revenues and our ability to pay cash distributions
on our units.
The demand for U.S. flag product carriers and barges is influenced by the cost of importing refined petroleum
products. Historically, charter rates for vessels qualified to participate in the U.S. coastwise trade under the Jones Act have been
higher than charter rates for foreign flag vessels. This is due to the higher construction and operating costs of U.S. flag vessels
under the Jones Act requirements that such vessels be built in the United States and manned by U.S. crews. This has made it
less expensive for certain areas of the United States 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 United
States and transporting them on U.S. flag vessels, demand for our vessels and the charter rates for them could decrease.
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, 2012, we have a number of significant unitholders. For example, certain members of the Davison
family (including their affiliates) and management owned approximately 18.4 million or 23% of our common units. We also
have other unitholders that may 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, 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 17% 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 business strategies, mergers, business combinations,
acquisitions or dispositions of significant assets, issuances of additional partnership securities, incurrence of debt or other
financing and the payment 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
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its affiliates, retention of counsel, accountants and service providers, and cash reserves, each of which can also affect
the amount of cash that is distributed to our unitholders; and
•
our general partner determines which costs incurred by it and its affiliates are reimbursable by us and the
reimbursement of these costs and of any services provided by our general partner could adversely affect our ability to
pay cash distributions to our unitholders.
Our Class B Common Units may be transferred to a third party without unitholder consent, which could affect our
strategic direction.
Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters
affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Only holders
of our Class B Common Units have the right to elect our board of directors. Holders of our Class B Common Units may
transfer such units to a third party without the consent of the unitholders. The new holders of our Class B Common Units may
then be in a position to replace our board of directors and officers of our general partner with its own choices and to control the
strategic decisions made by our board of directors and officers.
Unitholders with registration rights have rights to require underwritten offerings that could limit our ability to raise
capital in the public equity market.
Unitholders with registration rights have rights to require us to conduct underwritten offerings of our common units. If
we want to access the capital markets, 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 may 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, other than CHOPS are subject to the discretion of their respective management
committees. Further, each joint venture’s charter documents typically vest in its management committee sole discretion
regarding 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
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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.
Your liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for
those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership
is organized under Delaware law, and we conduct business in other states. The limitations on the liability of holders of limited
partner interests for the obligations of a limited partnership have not been clearly established in some states in which we do
business or may do business in from time to time in the future. You could be liable for any and all of our obligations as if you
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
•
your 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 Common Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being
subject to a material amount of entity-level taxation by individual states. A publicly-traded partnership can lose its status
as a partnership for a number of reasons, including not having enough “qualifying income.” If the Internal Revenue
Service, or IRS, were to treat us as a corporation 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 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 every taxable year consists of “qualifying income.” If less than 90% of our gross income for any taxable year is “qualifying
income” from transportation or processing of natural resources including crude oil, natural gas or products thereof, interest,
dividends or similar sources, 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, and do not plan to request, a ruling
from the IRS with respect to our treatment as a partnership for federal income tax purposes.
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
35% 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 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.
Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise
subject us to entity-level taxation. Moreover, any modification to the federal income tax laws and interpretations thereof may or
may not be applied retroactively. Any such changes could negatively impact the value of an investment in our common units.
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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 the cash available for distribution to our unitholders.
The tax treatment of publicly traded partnerships could be subject to potential legislative, judicial or administrative
changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, may be modified by
administrative, legislative or judicial interpretation at any time. Any modification to the U.S. federal income tax laws and
interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the
exception for us to be treated as a partnership for U.S. federal income tax purposes that is not taxable as a corporation, affect or
cause us to change our business activities, affect the tax considerations of an investment in us and change the character or
treatment of portions of our income. From time to time, members of Congress propose and consider substantive changes to the
existing U.S. federal income tax laws that would adversely affect the tax treatment of certain publicly traded partnerships. 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 flow.
A successful IRS contest of the federal income tax positions we take may adversely affect the market for our common
units, and the cost of any IRS contest will reduce our cash available for distribution to our unitholders and our general
partner.
We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership
for federal income tax purposes or any other matter affecting us. 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.
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.
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.
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 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. Prior distributions to unitholders in excess of the total net taxable income
unitholders were allocated for a common unit, which decreased their tax basis in that common unit, will, in effect, become
taxable income to unitholders if the common unit is sold at a price greater than their tax basis in that common unit, even if the
price they receive is less than their 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 unitholders sell their units, they may incur a tax liability
in excess of the amount of cash they receive from the sale.
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. Distributions to non-U.S. persons will be reduced by withholding taxes at the
highest applicable effective tax rate and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on
their share of our taxable income. Tax-exempt entities and non-U.S. persons should consult their tax advisors before investing
in our common units.
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We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common
units 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.
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, 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 unitholders do not live in any of those jurisdictions. 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, 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
United States 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 will reduce the cash available for distribution to us and, in turn, to our unitholders. If
the IRS were to successfully assert that these corporate subsidiaries have more tax liability than we anticipate or legislation was
enacted that increased the corporate tax rate, our cash available for distribution to our unitholders would be further reduced.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units
each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the
date a particular common unit is transferred.
We prorate our items of income, gain, loss, and deduction between transferors and transferees of our common units
each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a
particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. If the
IRS were to successfully challenge this method or new Treasury Regulations were issued, we may be required to change the
allocation of items of income, gain, loss, and deduction among our unitholders.
A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having
disposed of those units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to
those units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as
having disposed of the loaned units, such unitholder may no longer be treated for tax purposes as a partner with respect to those
units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition.
Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units
may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully
taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a
loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing
their units.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in
the termination of our partnership for federal income tax purposes.
We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange
of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among
other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and
unitholders receiving two Schedule K-1s) for one fiscal year. Our termination could also result in a deferral of depreciation
deductions allowable in computing our taxable income. In the case of a common unitholder reporting on a taxable year other
32
than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable
income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect
our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax
purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to
determine that a termination occurred.
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 19 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 19 to our Consolidated Financial Statements in Item 8.
Item 4. Mine Safety Disclosures
Not applicable.
33
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
Our Class A common units are listed on the New York Stock Exchange (“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.
2011
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
2012
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
Price Range
High
Low
Cash
Distributions
(1)
$ 29.83
$25.03
$ 29.08
$25.35
$ 28.12
$20.85
$ 28.33
$21.82
$ 33.81
$27.62
$ 31.40
$ 34.12
$26.70
$28.80
$ 36.38
$30.86
$
$
$
$
$
$
$
$
0.4000
0.4075
0.4150
0.4275
0.4400
0.4500
0.4600
0.4725
(1) Cash distributions are shown in the quarter paid and are based on the prior quarter’s activities.
At February 22, 2013, we had 81,162,755 Class A common units outstanding. As of December 31, 2012, the closing
price of our common units was $35.72 and we had approximately 38,200 record holders of our common units, which include
holders who own units through their brokers “in street name.”
After holders of our Waiver Units receive a minimal preferential quarterly distribution, we distribute all of our
available cash, as defined in our partnership agreement, within 45 days after the end of each quarter to unitholders of record.
Available cash consists generally of all of our cash receipts less cash disbursements, adjusted for net changes to cash reserves.
Cash reserves are the amounts deemed necessary or appropriate, in the reasonable discretion of our general partner, to provide
for the proper conduct of our business or to comply with applicable law, any of our debt instruments or other agreements. 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.
34
Item 6. Selected Financial Data
The table below includes selected financial and other data for the Partnership for the years ended December 31, 2012,
2011, 2010, 2009 and 2008 (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.”
Income Statement Data:
Revenues:
Supply and logistics
Refinery services
Pipeline transportation
Total revenues
Net income (loss) (2)
Net income (loss) attributable to Genesis
Energy, L.P. (2)
Net income (loss) available to Common
Unitholders
Net income attributable to Genesis
Energy, L.P. per Common Unit: Basic
and Diluted
Cash distributions declared per Common
Unit
Balance Sheet Data (at end of period):
Current assets
Total assets
Long-term liabilities
Partners’ capital:
Genesis Energy, L.P.
Noncontrolling interests
Total partners’ capital
Other Data:
Maintenance capital expenditures (3)
Volumes—continuing operations:
Onshore crude oil pipeline (barrels per
day)
Offshore crude oil pipeline (barrels per
day) (4)
CO2 pipeline (Mcf per day) (5)
NaHS sales (DST)
NaOH sales (DST)
Crude oil and petroleum products
(barrels per day)
(1)
2012
(1)
2011
2010 (1)
(1)
2009
(1)
2008
Year Ended December 31,
$
3,797,750
$
2,825,768
$
1,894,612
$
1,243,044
$
1,870,063
196,017
76,290
4,070,057
96,319
96,319
96,319
1.23
1.8225
404,034
2,109,664
880,518
916,495
—
916,495
$
$
$
$
$
$
$
$
$
$
$
201,711
62,190
3,089,669
51,249
51,249
51,249
0.75
1.6500
376,104
1,730,844
688,778
792,638
—
792,638
$
$
$
$
$
$
$
$
$
$
$
151,060
55,652
141,365
50,951
2,101,324
$
(50,541) $
1,435,360
6,178
(48,459) $
8,063
19,929
$
20,186
0.49
1.4900
252,538
1,506,735
630,757
669,264
—
669,264
$
$
$
$
$
$
$
0.51
1.3650
189,244
1,148,127
387,766
595,877
23,056
618,933
$
$
$
$
$
$
$
$
$
$
$
225,374
46,247
2,141,684
25,825
26,089
23,006
0.59
1.2225
168,127
1,178,674
394,940
632,658
24,804
657,462
$
$
$
$
$
$
$
$
$
$
$
4,430
4,237
2,856
4,426
4,454
92,897
82,712
67,931
60,262
64,111
359,387
186,479
142,712
77,492
120,723
169,962
147,670
99,702
149,270
167,619
145,213
93,283
—
154,271
107,311
88,959
—
160,220
162,210
68,647
94,043
71,043
61,012
48,117
47,569
(1) Our operating results and financial position have been affected by acquisitions, most notably the acquisition of
interests in several Gulf of Mexico crude oil pipeline systems from Marathon Oil Company, including its 28% interest
in Poseidon Oil Company, L.L.C., its 29% interest in Odyssey Pipeline, L.L.C. and its 23% interest in the Eugene
Island Pipeline System in January 2012, the acquisition of the black oil barge business of Florida Marine Transporters,
Inc. in August 2011, the 50% equity interest acquisition in CHOPS in November 2010, the acquisition of the
remaining 51% ownership interest in DG Marine in July 2010 and the Grifco acquisition in July 2008. The results of
these operations are included in our financial results prospectively from the acquisition date. For additional
35
information regarding our acquisitions during 2012, 2011 and 2010, see Note 3 to our Consolidated Financial
Statements included in Item 8.
(2) Includes executive compensation expense related to Series B and Class B awards borne entirely by our general partner
in the amounts of $76.9 million for 2010 and $14.1 million for 2009, see Note 15 to our Consolidated Financial
Statements in Item 8.
(3) Maintenance capital expenditures are capital expenditures to replace or enhance partially or fully depreciated assets to
sustain the existing operating capacity or efficiency of our assets and extend their useful lives.
(4) Includes barrels per day for CHOPS for the period we owned the pipeline in 2010.
(5) Volume per day for the period we owned the Free State CO2 pipeline in 2008.
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 and focused on the midstream
segment of the oil and gas industry in the Gulf Coast region of the United States, primarily Texas, Louisiana, Arkansas,
Mississippi, Alabama, Florida and in the Gulf of Mexico. We have a diverse portfolio of assets, including pipelines, refinery-
related plants, storage tanks and terminals, railcars, rail loading and unloading facilities, barges and trucks. We provide an
integrated suite of services to oil producers, refineries, and industrial and commercial enterprises that use NaHS and caustic
soda. Our business activities are primarily focused on providing services around and within refinery complexes. 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. Since our acquisition of all of the equity interest in our general partner in December
2010, our outstanding common units and waiver units representing limited partner interest constitute all of the economic equity
interest in us.
Included in Management’s Discussion and Analysis are the following sections:
•
•
•
•
•
•
•
•
Overview of 2012 Results and Operational Update
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 2012 Results and Operational Update
We reported net income of $96.3 million, or $1.23 per common unit, in 2012 compared to net income of $51.2 million,
or $0.75 per common unit, in 2011.
Segment Margin (as defined below in "Financial Measures") was $262.3 million in 2012, an increase of $59.8 million,
or 30%, as compared to 2011. This increase resulted from improvement in Segment Margin in our pipeline transportation and
supply and logistics segments of 42% and 55%, respectively. The contribution from our interests in certain Gulf of Mexico
pipelines that we acquired in 2012 and higher crude oil tariff revenues were the primary factors increasing pipeline
transportation segment margin. Results for our pipeline transportation segment were somewhat reduced during both years due
to ongoing improvements at several dedicated fields. Improvements at those fields were substantially completed late in the
third quarter of 2012. Our supply and logistics segment benefited from acquisitions and other growth initiatives completed in
the second half of 2011 as well as higher volumes handled by our expanded trucking and barge fleets. Our refinery services
segment margin decreased 2% primarily as a result of increased costs due to longer than anticipated refinery turnarounds at
some of our largest refinery service locations in the first half of 2012. To ensure uninterrupted NaHS supplies to our customers,
we incurred increased costs as a result of processing at and shipping from less efficient locations.
The information below provides certain updates regarding various operations and projects:
• Cameron Highway Pipeline. Production from several fields dedicated to our Cameron Highway pipeline in the
offshore Gulf of Mexico began to ramp back up in August 2012 after an extended period of maintenance on the third-
36
party operated surface and sub-sea production facilities, and total throughput levels on the pipeline have returned to
levels last seen in the first quarter of 2011.
• Gulf Coast Infrastructure.We plan to invest approximately $125 million to improve existing assets and develop new
infrastructure in Louisiana, including connecting to Exxon Mobil Corporation’s Baton Rouge refinery, one of the
largest refinery complexes in North America, with more than 500,000 barrels per day of refining capacity. Our
investment includes improving our existing terminal at Port Hudson, Louisiana, constructing a new 18-mile 20-inch
diameter crude oil pipeline connecting Port Hudson to the Baton Rouge Maryland Terminal and continuing
downstream to the Anchorage Tank Farm and building a new crude oil unit train facility at the Maryland Terminal.
The Port Hudson upgrades and new crude oil pipeline are expected to be completed by the end of 2013 and the
Maryland Terminal completion is scheduled for the second quarter of 2014.
• Walnut Hill Rail Facility. We continue to receive unit trains of crude oil at Walnut Hill, Florida for further delivery
downstream on our Jay Pipeline System, and would anticipate our new tank and related facilities to be fully
operational in March of 2013, allowing us to handle more trains, more efficiently.
• Wink Rail Facility. At our new crude loading facility outside Wink, Texas in the Permian Basin, we have continued to
support manifest service of crude oil volumes and in early February 2013 loaded our first full unit train. Construction
of our tanks and expanded trucking capabilities remains on track to be fully operational by late third quarter or early
fourth quarter of 2013.
• Natchez Terminal. At our terminal in Natchez, Mississippi, we have steamed and unloaded into tanks the first railcars
loaded with bitumen/dilbit originating in Alberta, Canada. As volumes continue to ramp up, we will begin loading
barges for further shipment to refineries along the Mississippi River.
• Texas City Facility. We have commissioned our new crude oil terminal and barge dock in Texas City. We would expect
the terminal and barge dock to see increasing levels of throughput in the latter half of 2013 upon the completion of our
new 18-inch pipeline from Webster to Texas City in the late second quarter or early third quarter of 2013.
• Wyoming. We have entered into an agreement with a local refinery in Wyoming which will support our investment to
expand and place into service certain segments of our crude oil gathering system in the Niobrara shale development in
Wyoming, with start-up operations expected in the second quarter of 2013.
• SEKCO. Construction has commenced on the SEKCO lateral in the Keathley Canyon area of the deepwater Gulf of
Mexico, and we expect significant contribution from this investment beginning mid-2014.
Distribution Increase
On January 10, 2013, we declared our thirtieth consecutive increase in our quarterly distribution to our common
unitholders relative to the fourth quarter of 2012. During that period, twenty-five of those quarterly increases have been 10% or
greater year-over-year. In February 2013, we paid a distribution of $0.485 per unit related to the fourth quarter of 2012
representing a 10.2% increase from our distribution of $0.44 per unit related to the fourth quarter of 2011. During the fourth
quarter of 2012, we paid a distribution of $0.4725 per unit related to the third quarter of 2012.
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
Our revenues for the year ended December 31, 2012 increased $980.4 million, or 32% from 2011. Additionally, our
costs and expenses increased $949.2 million or 32% between the two periods. The majority of our revenues and our costs are
derived from the purchase and sale of crude oil and petroleum products. The significant increase in our revenues and costs
between 2012 and 2011 is primarily attributable to increased volumes from our continuing operations and our acquisitions,
partially offset by slight decreases in the market prices for crude oil and petroleum products as described below.
Volumes in 2012 increased in our supply and logistics segment by 32% from 2011, as explained in our supply and
logistics Segment Margin discussion below. The average closing prices for West Texas Intermediate ("WTI") crude oil on the
New York Mercantile Exchange ("NYMEX") were consistent, decreasing 1% to $94.21 per barrel in 2012, as compared to
$95.12 per barrel in 2011.
37
Net income increased $45.1 million in 2012 from 2011. The increase in net income during 2012 primarily reflects
improved segment margin results due to our acquisitions and increased volumes. Our income tax expense decreased due to the
reversal of uncertain tax positions as a result of tax audit settlements and the expiration of statutes of limitations. These
increases to net income were partially offset by increases in general and administrative expenses and interest costs.
Revenues in 2011 increased $988.3 million, or 47% from 2010. Additionally, our costs and expenses increased $878.5
million or 41% between the two periods. The significant increase in our revenues and costs between 2011 and 2010 is primarily
attributable to the fluctuations in the market prices for crude oil and petroleum products. For example, prices for WTI crude oil
on the NYMEX averaged $95.12 per barrel in 2011, as compared to $79.53 per barrel in 2010, or a 20% increase. Net income
(attributable to us) increased $99.7 million in 2011 to $51.2 million from a net loss (attributable to us) of $48.5 million in 2010.
The increase in net income during 2011 primarily reflects the non-cash charges of $76.9 million we recorded in 2010 for
executive and equity-based compensation borne by our general partner. In addition, segment results for all of our segments
improved during 2011 as volumes increased. Our increased segment results were partially offset by increases in depreciation
and amortization expense and interest costs.
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:
Pipeline transportation
Refinery services
Supply and logistics
Total Segment Margin
Year Ended December 31,
2012
2011
2010
(in thousands)
$
$
96,539
$
67,908
$
72,883
92,911
74,618
59,975
48,305
62,923
38,336
262,333
$
202,501
$
149,564
Year Ended December 31, 2012 Compared with Year Ended December 31, 2011
Pipeline Transportation Segment
In January 2012, we acquired from Marathon Oil Company interests in several Gulf of Mexico crude oil pipeline
systems. The acquired pipeline interests include a 28% interest in Poseidon Oil Pipeline Company, L.L.C. (or “Poseidon”), a
100% interest in Marathon Offshore Pipeline, LLC (subsequently re-named GEL Offshore Pipeline, LLC, or “GOPL”) and a
29% interest in Odyssey Pipeline L.L.C. (or “Odyssey”). GOPL owns a 23% interest in the Eugene Island crude oil pipeline
system and a 100% interest in two smaller offshore pipelines. The purchase price, net of post-closing adjustments, was $205.6
million. We funded the purchase price with cash available under our credit facility.
This acquisition complements our existing infrastructure in the Gulf of Mexico and enhances our ability to provide
capacity and market optionality to producers for their existing and future developments as well as our refining customers
onshore Texas and Louisiana. The Poseidon pipeline system is comprised of a 367-mile network of crude oil pipelines, varying
in diameter from 16 to 24 inches, with capacity to deliver approximately 400,000 barrels per day of crude oil from
developments in the central and western offshore Gulf of Mexico to other pipelines and terminals onshore and offshore
Louisiana. Affiliates of Enterprise Products and Shell each own a 36% interest in Poseidon. An affiliate of Enterprise Products
serves as the operator of Poseidon. The Eugene Island pipeline system is primarily comprised of a 183-mile network of crude
oil pipelines, the main pipeline of which is 20 inches in diameter, with capacity to deliver approximately 200,000 barrels per
day of crude oil from developments in the central Gulf of Mexico to other pipelines and terminals onshore Louisiana. Other
owners in Eugene Island include affiliates of Exxon-Mobil, Chevron-Texaco, ConocoPhillips and Shell. An affiliate of Shell
serves as the operator of Eugene Island. The Odyssey pipeline system is comprised of a 120-mile network of crude oil
pipelines, varying in diameter from 12 to 20 inches, with capacity to deliver up to 200,000 barrels per day of 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, and an affiliate of Shell serves as the operator of Odyssey.
38
Operating results and volumetric data for our pipeline transportation segment are presented below:
Crude oil tariffs and revenues from direct financing leases—onshore crude oil pipelines
$
31,931
$
24,870
Year Ended December 31,
2012
2011
(in thousands)
Segment margin from offshore crude oil pipelines, including pro-rata share of distributable
cash from equity investees
CO2 tariffs and revenues from direct financing leases of CO2 pipelines
Sales of crude oil pipeline loss allowance volumes
Onshore pipeline operating costs, excluding non-cash charges for equity-based
compensation and other non-cash expenses
Payments received under direct financing leases not included in income
Other
Segment Margin
Volumetric Data (barrels/day unless otherwise noted):
Onshore crude oil pipelines:
Texas
Jay
Mississippi
Offshore crude oil pipelines:
CHOPS (1)
Poseidon (1) (2)
Odyssey (1) (2)
GOPL (2)
CO2 pipeline (Mcf/day):
Free State
38,500
26,603
9,165
(15,607)
5,016
931
15,772
26,334
7,756
(12,222)
4,615
783
$
96,539
$
67,908
51,880
22,306
18,711
96,664
211,375
36,157
15,191
45,183
16,900
20,629
120,723
—
—
—
186,479
169,962
(1) Volumes for our equity method investees are presented on a 100% basis.
(2) Acquired in January 2012.
During 2012, crude oil volumes shipped on our Texas System and Jay System increased 6,697 barrels per day (or
15%) and 5,406 barrels per day (or 32%), respectively. Volumes on our Texas System increased primarily as a result of
increased demand by one of the refiners connected to our system with capabilities for processing light crude oil such as that
being produced in the Eagle Ford Shale area. Additional barrels received at our new crude-by-rail unloading terminal at Walnut
Hill, Florida, increased volumes on the Jay System. On CHOPS, crude oil volumes declined 24,059 barrels per day (or 20%)
during 2012 due to ongoing improvements being made by producers at several connected fields. Improvements at those fields
were substantially completed late in the third quarter of 2012, and total throughput levels on the pipeline have returned to levels
last seen in the first quarter of 2011.
We deliver CO2 on our Free State Pipeline for use in tertiary recovery operations in east Mississippi. Denbury
currently has rights to exclusive use of the pipeline and is required to use the pipeline to supply CO2 to its current and certain of
its other tertiary operations in east Mississippi. We have a twenty-year financing lease (through 2028) with Denbury for their
use of our NEJD System. Denbury makes fixed quarterly base rent payments to us of $5.2 million per quarter or approximately
$20.7 million per year.
Segment Margin for our pipeline transportation segment increased $28.6 million, or 42%, in 2012 as compared to
2011. The significant components of this change were as follows:
• Crude oil tariff revenues of onshore crude oil pipelines increased $7.1 million primarily due to upward tariff indexing
of 6.9% and 8.6% for our FERC-regulated pipelines effective in July 2011 and 2012, respectively, and increased
volumes of 10,185 barrels per day transported on our onshore crude oil pipelines as described above.
39
•
Segment margin from our offshore crude oil pipelines increased $22.7 million reflecting a contribution of $29.1
million from our interests in the Gulf of Mexico pipelines that we acquired in 2012. The contribution to Segment
Margin by CHOPS declined by $6.4 million from 2011 due to ongoing improvements being made by producers at
several connected fields as discussed above.
• Revenues from sales of pipeline loss allowance volumes improved Segment Margin by $1.4 million due to an increase
of approximately 10,200 barrels sold in 2012 compared to 2011.
•
Pipeline operating costs, excluding non-cash charges, increased $3.4 million, due to pipeline integrity maintenance on
the pipelines and employee compensation and related benefit costs.
Refinery Services Segment
Operating results for our refinery services segment were as follows:
Volumes sold (in Dry short tons "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)
Raw material and processing costs as % of segment revenues
(1) Source: IHS Chemical
Year Ended December 31,
2012
2011
142,712
77,492
220,204
147,670
99,702
247,372
$
153,689
$
152,422
44,322
7,099
205,110
72,883
575
48%
$
$
$
47,339
10,633
210,394
74,618
513
48%
$
$
$
Refinery services Segment Margin for 2012 decreased $1.7 million, or 2%, from 2011. The significant components of
this fluctuation were as follows:
• NaHS sales volumes during 2012 decreased 3% from 2011 primarily due to the timing of sales to South American
customers. In late 2011, we experienced a high volume of sales to these customers. Sales volumes to customers in
South America can fluctuate due to scheduling of shipments.
• NaHS revenues increased primarily as a function of the increase in the average index price for caustic soda. The
pricing in our sales contracts for NaHS includes adjustments for fluctuations in commodity benchmarks, freight, labor,
energy costs and government indexes. The frequency at which these adjustments are applied varies by contract,
geographic region and supply point.
• Our raw material costs related to NaHS increased correspondingly to the rise in the average index price for caustic
soda. In addition, in the first half of 2012, longer than anticipated refinery turnarounds at some of our largest refinery
service locations resulted in increased costs as a result of processing at and shipping from less efficient locations to
ensure uninterrupted supplies of NaHS to our customers.
• Caustic soda sales volumes decreased 22% primarily due to turnarounds at some of our refinery customers in the first
half of 2012. Although caustic sales volumes may fluctuate, the contribution to Segment Margin from these sales is
not a significant portion of our refinery services activities. Caustic soda is a key component in the provision of our
sulfur-removal service, from which we receive the by-product NaHS. Consequently, we are a very large consumer of
caustic soda. In addition, our economies of scale and logistics capabilities allow us to effectively purchase additional
caustic soda for re-sale to third parties. Our ability to purchase caustic soda volumes is currently sufficient to meet the
demands of our refinery services operations and third-party sales.
40
• Average index prices for caustic soda increased to $575 per DST during 2012 compared to $513 per DST during 2011.
Those price movements affect the revenues and costs related to our sulfur removal services as well as our caustic soda
sales activities. However, generally changes in caustic soda prices do not materially affect Segment Margin
attributable to our sulfur processing services because we usually pass those costs through to our NaHS sales
customers. 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 on our operating costs.
Supply and Logistics Segment
Our supply and logistics segment is focused on utilizing our knowledge of the crude oil and petroleum markets and
our logistics capabilities from our terminals, railcars, rail loading and unloading facilities, trucks and barges to provide
suppliers and customers with a full suite of services. These services include:
•
•
•
•
•
purchasing and/or transporting crude oil from the wellhead to markets for ultimate use in refining;
supplying petroleum products (primarily fuel oil, asphalt, and other heavy refined products) to wholesale markets and
some end-users such as paper mills and utilities;
purchasing products from refiners, transporting the products to one of our terminals and blending the products to a
quality that meets the requirements of our customers;
utilizing our fleet of trucks and trailers, railcars, and barges to take advantage of logistical opportunities primarily in
the Gulf Coast states and inland waterways; and
industrial gas activities, including wholesale marketing of CO2 and processing of syngas through a joint venture.
We also 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 meeting their requirements, and to purchase the crude oil and transport it to
the refineries for sale. The imbalances and inefficiencies relative to meeting the refiners’ requirements can provide
opportunities for us to utilize our purchasing and logistical skills to meet their demands. The pricing in the majority of our
purchase contracts contain a market price component and a deduction to cover the cost of transporting the crude oil 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 petroleum 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. The opportunities to provide this service
cannot be predicted, but their contribution to margin as a percentage of their revenues tend to be higher than the same
percentage attributable to our recurring operations.
We utilize our fleet of 300 trucks, 350 trailers, 180 rail cars, 50 barges, 22 push/tow boats, and 1.7 million barrels of
leased and owned storage capacity to service our crude oil and refining customers and to store and blend the intermediate and
finished refined products.
41
Operating results for our supply and logistics segment were as follows:
Supply and logistics revenue
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
Year Ended December 31,
2012
2011
(in thousands)
$
3,797,750
$
2,825,768
(3,541,562)
(2,642,964)
(163,489)
212
(122,925)
96
$
92,911
$
59,975
Volumes of crude oil and petroleum products (barrels per day)
94,043
71,043
As discussed above in “Revenues, Costs and Expenses and Net Income,” the average market prices of crude oil and
petroleum products were consistent between 2012 and 2011. Fluctuations in these prices, however, have a limited impact on
our Segment Margin.
Segment Margin for our supply and logistics segment increased $32.9 million, or 55%, in 2012 as compared to 2011.
The increase in Segment Margin resulted primarily from the contribution of the black oil barge transportation assets that we
acquired in August 2011 and February 2012 and increased volumes handled by our expanded trucking, rail and barge fleets.
Our total volumes of crude oil and petroleum products increased by 32% primarily as a result of these expansions. Our
operating costs, excluding non-cash charges, increased 33% between the two periods due to our expanded trucking, rail and
barge fleets and increased utilization of such fleets.
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,
2012
2011
(in thousands)
$
$
22,873
$
19,466
11,735
6,132
1,679
8,868
1,763
4,376
42,419
$
34,473
Routine corporate and segment general and administrative expenses increased between 2012 and 2011 as a result of
salary and benefits expenses associated with increases in personnel to support our growth. Additionally, increases in the market
price of our common units and an increase in the number of awards outstanding due to increases in personnel affected expense
related to our equity-based compensation plans. A decrease in third party costs related to business and growth transactions
resulted in a decrease of approximately $2.7 million between the periods.
42
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,
2012
2011
(in thousands)
37,398
$
19,930
3,838
61,166
$
27,544
30,952
3,694
62,190
$
$
Depreciation and amortization expense decreased $1 million between 2012 and 2011 primarily as a result of decreases
in amortization of intangible assets, offset by an increase in depreciation expense. Amortization of intangible assets decreased
$11 million as we amortize our intangible assets over the period in which we expect them to contribute to our future cash flows.
Generally, the amortization we record on those assets is greater in the initial years following their acquisition because our
intangible assets are generally more valuable in the first years after an acquisition. Depreciation expense increased $9.9 million
primarily as a result of our recent acquisitions, including the black oil barge transportation assets in August 2011 and February
2012.
Interest expense, net
Year Ended December 31,
2012
2011
(in thousands)
Interest expense, senior secured credit facility (including commitment fees)
$
14,212
$
Interest expense, senior unsecured notes
Amortization and write-off of debt issuance costs and premium
Capitalized interest
Interest income
Net interest expense
26,578
4,037
(3,891)
(15)
40,921
$
$
12,986
19,961
2,940
(106)
(14)
35,767
Net interest expense increased $5.2 million during 2012, primarily as a result of increased borrowings associated with
acquisitions. Interest expense on our senior unsecured notes increased $6.6 million over the same period as a result of issuing
an additional $100 million of senior unsecured notes under the indenture in February 2012 to repay borrowings under our credit
facility. An increase in capitalized interest costs of $3.8 million attributable to our growth capital expenditures and investments
in the SEKCO pipeline joint venture (see below for more information) partially offset the increase in interest expense.
43
Year Ended December 31, 2011 Compared with Year Ended December 31, 2010
Pipeline Transportation Segment
Operating results and volumetric data for our pipeline transportation segment are presented below:
Crude oil tariffs and revenues from direct financing leases—onshore crude oil pipelines
$
24,870
$
20,351
Year Ended December 31,
2011
2010
(in thousands)
Segment margin from offshore crude oil pipelines, including pro-rata share of distributable
cash from equity investees
CO2 tariffs and revenues from direct financing leases of CO2 pipelines
Sales of crude oil pipeline loss allowance volumes
Onshore pipeline operating costs, excluding non-cash charges for equity-based
compensation and other non-cash expenses
Payments received under direct financing leases not included in income
Other
Segment Margin
Volumetric Data (barrels/day unless otherwise noted):
Onshore crude oil pipelines:
Texas
Jay
Mississippi
Offshore crude oil pipelines:
CHOPS (1) (2)
CO2 pipeline (Mcf/day):
Free State
15,772
26,334
7,756
(12,222)
4,615
783
2,185
26,413
5,519
(11,323)
4,202
958
$
67,908
$
48,305
45,183
16,900
20,629
28,748
15,646
23,537
120,723
149,270
169,962
167,619
(1) Volumes for our equity method investees are presented on a 100% basis.
(2) 2010 volumes for CHOPS represent the daily average since our acquisition date in November 2010.
During 2011, crude oil volumes shipped on our Texas System increased 16,435 barrels per day (or 57%) primarily as a
result of increased demand by one of the refiners connected to our system with capabilities for processing light crude oil such
as that being produced in the Eagle Ford Shale area. On CHOPS, crude oil volumes declined 28,547 barrels per day (or 19%)
during 2011 due to planned improvements to offshore field facilities by producers with fields connected to CHOPS that were
performed in the last three quarters of 2011. These field improvements by the producers are expected to increase volumes on
CHOPS in the future.
Pipeline transportation Segment Margin increased $19.6 million in 2011 as compared to 2010. The primary factors in
this increase are summarized below.
•
Segment margin from our offshore crude oil pipeline, CHOPS, increased $13.6 million during 2011 as a result of
owning our 50% interest for a full year in 2011. Despite the increase, planned improvements by producers of offshore
field facilities from the second quarter of 2011 through the fourth quarter of 2011 negatively impacted our revenue
generating volumes during the year.
• Crude oil tariff revenues of onshore crude oil pipelines increased $4.5 million reflecting increased volumes of 14,781
barrels per day transported on our onshore crude oil pipelines as described above.
• An increase in revenues from sales of pipeline loss allowance volumes increased Segment Margin by $2.2 million
related to the significant increase (an average of $16 per barrel) in crude oil prices.
•
Pipeline operating costs, excluding non-cash charges increased $0.9 million, primarily due to increased employee
compensation and related benefit costs.
44
Refinery Services Segment
Operating results for our refinery 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)
Raw material and processing costs as % of segment revenues
(1) Source: IHS Chemical
Year Ended December 31,
2011
2010
147,670
99,702
247,372
145,213
93,283
238,496
$
152,422
$
119,688
47,339
10,633
210,394
74,618
513
48%
$
$
$
29,578
9,190
158,456
62,923
353
37%
$
$
$
Refinery services Segment Margin for the year ended 2011 increased $11.7 million, or 19%, from 2010. The
significant components of this change were as follows:
• Revenues increased primarily as a function of the increase in the average index price for caustic soda. Average index
prices of caustic soda increased to an average of $513 per DST during 2011 as compared to $353 per DST in 2010.
Those price movements affect the revenues and costs related to our sulfur removal services as well as our caustic soda
sales activities. However, changes in caustic soda prices do not materially affect Segment Margin attributable to our
sulfur processing services because we generally pass those costs through to our NaHS sales customers. Additionally,
our bulk purchase and storage capabilities related to caustic soda allow us to mitigate the effects of changes in index
prices for caustic on our operating costs.
• The pricing in our sales contracts for NaHS includes adjustments for fluctuations in commodity benchmarks, freight,
labor, energy costs and government indexes. The frequency at which these adjustments are applied varies by contract,
geographic region and supply point. Our raw material costs related to NaHS increased correspondingly to the rise in
the average index price for caustic soda, although operating efficiencies at several of our sour gas processing facilities
as well as our favorable management of the acquisition and utilization of caustic soda in our operations and our
logistics management, as discussed below, helped offset these costs.
• NaHS sales volumes during 2011 increased 2% from 2010. Although there were decreased levels of activity by our
pulp and paper customers, the return of industrialization and urbanization in the world’s emerging economies
increased the demand for products requiring copper and molybdenum. These trends led to a noticeable increase in
NaHS demand from our mining customers primarily in North America in 2011 as compared to 2010.
• Caustic soda sales volumes increased 7%. Caustic soda is a key component in the provision of our sulfur-removal
service, from which we receive the by-product NaHS. Consequently, we are a very large consumer of caustic soda. In
addition, our economies of scale and logistics capabilities allow us to effectively purchase caustic soda for re-sale to
third parties.
45
Supply and Logistics Segment
Operating results for our supply and logistics segment were as follows:
Supply and logistics revenue
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
Year Ended December 31,
2011
2010
(in thousands)
$
2,825,768
$
1,894,612
(2,642,964)
(1,761,161)
(122,925)
96
$
59,975
$
(95,011)
(104)
38,336
Volumes of crude oil and petroleum products (barrels per day)
71,043
61,012
As discussed above in “Revenues, Costs and Expenses and Net Income,” the average market prices of crude oil
increased by approximately $16 per barrel, or approximately 20% between the two periods. Similarly, market prices for
petroleum products increased significantly between 2011 and 2010. Fluctuations in these prices, however, have a limited
impact on our Segment Margin. The increase in Segment Margin during 2011 versus 2010 resulted primarily from several
factors, including:
•
•
•
•
increased volumes of approximately 16% from 2010 primarily due to a greater availability of volumes of crude oil and
heavy-end petroleum products resulting from increased refinery utilization in our operating area;
increased production from new sources of crude oil, principally shale oil production, increased demand for our
services;
higher foreign demand for fuel oil and other heavy-end petroleum products helped sustain the price environment for
the products we sell;
operating efficiencies and modifications to our existing crude oil and petroleum products commercial arrangements;
and
•
the contribution from the additional black oil barges we acquired in August 2011.
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 IDR Restructuring, business development activities and growth
projects
Expenses related to change in owner of our general partner
Non-cash compensation expense related to management team
Total general and administrative expenses
Year Ended December 31,
2011
2010
(in thousands)
$
19,466
$
17,276
8,868
1,763
4,376
—
—
8,200
1,955
7,290
1,762
76,923
$
34,473
$
113,406
General and administrative expenses decreased $78.9 million in 2011 from 2010 primarily due to non-cash
compensation charges of $76.9 million in the prior year related to equity-based compensation arrangements between executive
management and our general partner. The decrease in general and administrative expenses was partially offset primarily by an
increase in personnel resulting in greater salaries and benefits expenses.
46
The non-cash compensation charges recorded in 2010 reflect the exchange of certain equity interests in our general
partner held by our executives for new common units (including waiver units). These charges were incurred in connection with
our IDR Restructuring. Although the compensation under these arrangements ultimately came from our general partner, we
recorded the fair value of the related compensation expense in our Consolidated Statements of Operations in general and
administrative expenses. See Note 15 to our Consolidated Financial Statements in Item 8 for more information concerning the
non-cash compensation costs incurred in connection with our IDR Restructuring.
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,
2011
2010
(in thousands)
27,544
$
30,952
3,694
62,190
$
22,510
26,805
4,254
53,569
$
$
Depreciation and amortization expense increased $8.6 million between 2011 and 2010 primarily as a result of an
adjustment in the useful lives of certain of our intangible assets in the first quarter of 2011 and depreciation expense related to
our black oil barge assets acquisition. In the first quarter of 2011, we adjusted the useful lives of our supply and logistics trade
names, which resulted in an increase of amortization expense of $7.7 million during the year. The impact of this change is not
expected to be material in future periods.
Interest expense, net
Genesis Facility and Notes:
Year Ended December 31,
2011
2010
(in thousands)
Interest expense, credit facility (including commitment fees)
$
12,986
$
10,624
Interest expense, senior unsecured notes
Amortization of credit facility and notes issuance costs
Bridge financing fees
Write-off of facility fees
DG Marine Facility:
Interest expense and commitment fees
Interest rate swaps settlement
Write-off of facility fees
Capitalized interest
Interest income
Net interest expense
19,961
2,940
—
—
—
—
—
(106)
(14)
35,767
$
2,406
1,551
3,219
402
2,512
1,553
794
(84)
(53)
22,924
$
Net interest expense increased $12.8 million during 2011, primarily reflecting increased interest expense on our senior
unsecured notes, which were outstanding for an entire year during 2011. Interest expense on our credit facility also increased
during 2011 as our average debt balance increased $8.1 million. The increase in the average outstanding balance under our
credit facility is attributable primarily to growth initiative projects during 2011, including expansion of our Texas pipeline
infrastructure and the acquisition of the Wyoming refinery and pipeline assets. The increase in net interest expense during 2011
was partially offset by the repayment of the DG Marine credit facility in July 2010.
47
Other Consolidated Results
Income Taxes
A portion of our operations are owned by wholly-owned corporate subsidiaries that are taxable as corporations. As a
result, a substantial portion of the income tax expense we record relates to the operations of those corporations, and will vary
from period to period based on the percentage of our income or loss that is derived from those corporations. The balance of the
income tax expense we record relates to state taxes imposed on our operations that are treated as income taxes under generally
accepted accounting principles and foreign income taxes. During 2012 and 2011, we recorded an income tax benefit of $9.2
million and $1.2 million, respectively. In 2010, we recorded income tax expense of $2.6 million. The benefit during 2012 is
primarily due to the reversal of $8.2 million in uncertain tax positions as a result of tax audit settlements and the expiration of
statutes of limitation. The benefit during 2011 reflects a net loss for those wholly-owned corporate subsidiaries that are taxable
as corporations.
Financial Measures
Segment Margin
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 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. A reconciliation of Segment Margin to
income before income taxes is included in our segment disclosures in Note 12 to our Consolidated Financial Statements in
Item 8.
Available Cash before Reserves
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 accounting principles generally accepted in the U.S., also
referred to as GAAP. The accompanying schedule below provides a reconciliation of this non-GAAP financial measure to its
most directly comparable GAAP financial measure. Our non-GAAP financial measure 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. We believe that investors benefit from having access to the same financial
measures being utilized by management, lenders, analysts and other market participants.
Available Cash before Reserves, also referred to as distributable cash flow, 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 assess: (1) the financial performance of our assets without regard to financing methods, capital
structures, or historical cost basis; (2) the ability of our assets to generate cash sufficient to pay interest costs and support our
indebtedness; (3) our operating performance and return on capital as compared to those of other companies in the midstream
energy industry, without regard to financing and capital structure; and (4) the viability of projects and the overall rates of return
on alternative investment opportunities. Because Available Cash before Reserves excludes some items that affect net income or
loss and because these measures may vary among other companies, the Available Cash before Reserves data presented in this
Annual Report on Form 10-K may not be comparable to similarly titled measures of other companies.
Available Cash before Reserves is a performance measure used by our management to compare cash flows generated
by us to the cash distribution paid to our common unitholders. This is an important financial measure to our public unitholders
since it is an indicator of our ability to provide a cash return on their investments. Specifically, this financial measure aids
investors in determining whether or not we are generating cash flows at a level that can support a quarterly cash distribution to
the partners. Lastly, Available Cash before Reserves is the quantitative standard used throughout the investment community
with respect to publicly-traded partnerships.
Available Cash before Reserves is net income as adjusted for specific items, the most significant of which are the
addition of non-cash expenses (such as depreciation and amortization), the substitution of distributable cash generated by our
equity investees in lieu of our equity income attributable to our equity investees, the elimination of gains and losses on asset
sales (except those from the sale of surplus assets) and unrealized gains and losses on derivative transactions not designated as
hedges for accounting purposes, the elimination of expenses related to acquiring or constructing assets that provide new
sources of cash flows, the subtraction of maintenance capital expenditures, which are expenditures that are necessary to sustain
existing (but not to provide new sources of) cash flows, and the elimination of earnings of DG Marine in excess of distributable
cash until July 2010 when DG Marine’s credit facility was repaid.
48
Available Cash before Reserves for the years ended December 31, 2012, 2011 and 2010 was as follows:
Year Ended December 31,
2012
2011
2010
(in thousands)
Net income (loss) attributable to Genesis Energy, L.P.
$
96,319
$
51,249
$
Depreciation and amortization
Cash received from direct financing leases not included in income
Cash effects of sales of certain assets
Effects of distributable cash generated by equity method investees not
included in income
Cash effects of equity-based compensation plans
Non-cash equity-based compensation expense
Expenses related to acquiring or constructing assets that provide new
sources of cash flow
Unrealized loss on derivative transactions excluding fair value hedges
Maintenance capital expenditures
Non-cash tax (benefit) expense
Earnings of DG Marine in excess of distributable cash
Other items, net
Available Cash before Reserves
Liquidity and Capital Resources
General
61,166
5,016
773
24,464
(3,280)
4,978
1,679
86
(4,430)
(9,222)
—
1,609
62,190
4,615
6,424
16,681
(2,394)
311
4,376
724
(4,237)
(2,075)
—
335
$
179,158
$
138,199
$
(48,459)
53,569
4,203
1,146
2,284
(1,349)
82,979
11,260
59
(2,856)
1,337
(848)
(1,826)
101,499
As of December 31, 2012, we believe our balance sheet and liquidity position remained strong. We had $483.3 million
of borrowing capacity available under our $1 billion senior secured revolving credit facility. As discussed in "Subsequent
Events Affecting Liquidity and Capital Resources" below, in February 2013, we issued an additional $350 million in aggregate
principal amount senior unsecured notes. The net proceeds were used to repay borrowings under our credit facility and for
general partnership purposes. We anticipate that our future internally-generated funds and the funds available under our credit
facility will allow us to meet our day-to-day capital needs, excluding, for example, major capital expenditures and/or
refinancings. Our primary sources of liquidity have been cash flows from operations, debt offerings and borrowing availability
under our credit facility.
Our primary cash requirements consist of:
• Working capital, primarily inventories;
• Routine operating expenses;
• Capital expansion 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 the necessary funds on satisfactory terms.
In July 2012, we amended and restated our senior secured credit facility with a syndicate of banks to, among other
things, increase the committed amount from $775 million to $1 billion and the accordion feature from $225 million to $300
49
million, giving us the ability to expand the size of the facility up to an aggregate of $1.3 billion for acquisitions or internal
growth projects, subject to lender consent. The inventory financing sublimit tranche was increased from $125 million to $150
million, and the term of our credit facility was extended to July 25, 2017. This inventory tranche is designed to allow us to
more efficiently finance crude oil and petroleum products inventory in the normal course of our operations, by allowing us to
exclude the amount of inventory loans from our total outstanding indebtedness for purposes of determining our applicable
interest rate. Our credit facility does not include a “borrowing base” limitation except with respect to our inventory loans.
The key terms for rates under our credit facility, which are dependent on our leverage ratio (as defined in the credit
agreement), are as follows:
• The applicable margin varies from 1.75% to 2.75% on eurodollar borrowings and from 0.75% to 1.75% on alternate
base rate borrowings.
• Letter of credit fees range from 1.75% to 2.75%.
• The commitment fee on the unused committed amount will range from 0.375% to 0.50%.
We do not anticipate any of the lenders that participate in our credit facility being unable to satisfy their obligations
under the credit facility.
In February 2012, we issued an additional $100 million of aggregate principal amount of senior unsecured notes under
our existing 7.875% senior notes indenture for which the net proceeds were used to repay borrowings under our credit facility.
The notes were issued at 101% of face value at an effective interest rate of 7.682%. The notes mature on December 15, 2018.
See Note 10 to our Consolidated Financial Statements in Item 8 for more information.
In March 2012, we issued 5,750,000 Class A common units in a public offering at a price of $30.80 per unit. We
received proceeds, net of underwriting discounts and offering costs, of $169.4 million from the offering. The net proceeds were
used for general corporate purposes, including the repayment of borrowings under our credit facility. See Note 11 to our
Consolidated Financial Statements in Item 8 for more information.
At December 31, 2012, long-term debt totaled $850.9 million, consisting of $500 million outstanding under our credit
facility (including $63.9 million borrowed under the inventory sublimit tranche) and $350.9 million of senior unsecured notes
due in 2018.
For additional information on our long-term debt and covenants see Note 10 to our Consolidated Financial Statements
in Item 8.
Subsequent Events Affecting Liquidity and Capital Resources
On February 8, 2013, we issued an additional $350 million in aggregate principal amount of 5.75% senior unsecured
notes. The notes mature on February 15, 2021. The net proceeds were used to repay borrowings under our credit facility and for
general partnership purposes.
Cash Flows from Operations
We generally utilize the cash flows we generate from our operations to fund our working capital needs. Excess funds
that are generated are used to repay borrowings from our credit facility and to fund 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, and we do not 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.
However, when the crude oil markets are in contango, we may store crude for future delivery utilizing futures contracts to
hedge our risk to fluctuations in prices.
In our petroleum products activities, we buy products and typically either move the products to one of our storage
facilities for further blending or we sell the product 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.
The storage of crude oil and petroleum products can have a material impact on our cash flows from operating
activities. In the month we pay for the stored oil or petroleum products, we borrow under our credit facility (or pay from cash
on hand) to pay for the oil or products, which negatively impacts 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 oil or products.
Additionally, we may be required to deposit margin funds with the NYMEX when prices increase as the value of the
50
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 $189.3 million and $58.3 million for 2012 and 2011,
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 and petroleum products can result in fluctuations in our operating cash flows between periods as the cost to
acquire a barrel of oil or products will require more or less cash. The increase in operating cash flow for 2012 compared to
2011 was primarily due to higher cash earnings and decreases 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 smaller internal growth projects and distributions
primarily with cash generated by our operations. Acquisition activities and large internal growth projects have historically been
funded with borrowings under our credit facility, equity issuances and the issuance of senior unsecured notes.
Capital Expenditures and Business and Asset Acquisitions
The following table summarizes our expenditures for fixed assets, business and other asset acquisitions in the periods
indicated:
Capital expenditures for fixed and intangible assets:
Maintenance capital expenditures:
Pipeline transportation assets
Refinery services assets
Supply and logistics assets
Total maintenance capital expenditures
Growth capital expenditures:
Pipeline transportation assets
Refinery services assets
Supply and logistics assets (1)
Information technology systems upgrade projects
Total growth capital expenditures
Total maintenance and growth capital expenditures
Capital expenditures for business combinations,
net of liabilities assumed:
Offshore pipelines (2)
Acquisition of FMT assets
Wyoming refinery and related pipeline
Total business combinations capital expenditures
Capital expenditures related to equity investees (3)
Total capital expenditures
Years Ended December 31,
2012
2011
2010
(in thousands)
$
376
$
247
$
1,183
2,871
4,430
59,009
1,509
92,025
1,631
154,174
158,604
205,576
—
—
205,576
63,749
1,200
2,790
4,237
7,382
646
11,056
4,128
23,212
27,449
194
143,479
20,000
163,673
—
522
1,433
901
2,856
573
—
839
10,613
12,025
14,881
332,462
—
—
332,462
—
$
427,929
$
191,122
$
347,343
(1) In 2012, amount includes the purchase of barge assets for $30.9 million (see below for more information).
(2) In 2012, amount represents the investment to acquire from Marathon Oil Company interests in several Gulf of Mexico
crude oil pipeline systems. In 2011 and 2010, amounts represent the investment to acquire our interest in CHOPS.
(3) Amount represents our investment in the SEKCO pipeline joint venture (see below for more information).
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.
51
Acquisitions
We continue to pursue a growth strategy that requires significant capital. In January 2012, we acquired from Marathon
Oil Company interests in several Gulf of Mexico crude oil pipeline systems. The acquired pipeline interests include a 28%
interest in Poseidon Oil Pipeline Company, L.L.C. (or “Poseidon”), a 100% interest in Marathon Offshore Pipeline, LLC
(subsequently re-named GEL Offshore Pipeline, LLC, or “GOPL”) and a 29% interest in Odyssey Pipeline L.L.C. (or
“Odyssey”). GOPL owns a 23% interest in the Eugene Island crude oil pipeline system and a 100% interest in two smaller
offshore pipelines. The purchase price, net of post-closing adjustments, was $205.6 million. We funded the purchase price with
cash available under our credit facility.
See Note 3 to our Consolidated Financial Statements in Item 8 for further information related to the acquisitions.
Growth Capital Expenditures
Total capital expenditures on projects currently under construction, and disclosed in the following discussion, are
estimated to be approximately $475 million, inclusive of capital expenditures incurred in prior quarters. We anticipate that
approximately $305 million of that total will be spent in 2013.
Gulf Coast Infrastructure
We plan to invest approximately $125 million to improve existing assets and develop new infrastructure in Louisiana,
including connecting to Exxon Mobil Corporation’s Baton Rouge refinery, one of the largest refinery complexes in North
America, with more than 500,000 barrels per day of refining capacity. Our investment includes improving our existing terminal
at Port Hudson, Louisiana, constructing a new 18-mile 20-inch diameter crude oil pipeline connecting Port Hudson to the
Baton Rouge Maryland Terminal and continuing downstream to the Anchorage Tank Farm and building a new crude oil unit
train facility at the Maryland Terminal. The Port Hudson upgrades and new crude oil pipeline are expected to be completed by
the end of 2013 and the Maryland Terminal completion is scheduled for the second quarter of 2014.
Texas City Projects
In the fourth quarter of 2012, we completed two projects to increase the services we provide to producers and refiners.
We acquired three above-ground storage tanks located in Texas City, Texas and an existing barge dock at the same location, all
approximately 1.5 miles from our existing Texas pipeline system. We also constructed a truck station and tankage in West
Columbia, Texas to provide incremental transportation service for the Eagle Ford Shale and other Texas production through our
pipeline system to refining markets in the greater Houston/Texas City area. We are able to handle approximately 40,000 barrels
per day of crude oil through the Texas City terminal. In addition, we have initiated construction of a 18-inch diameter loop of
our existing crude oil pipeline into Texas City, supported by a term contract with one of our refining customers, which we
expect will allow us to significantly expand our total service capabilities into the Texas City area by the late second quarter or
early third quarter of 2013.
HollyFrontier Tulsa Project
We are installing a new sour gas processing facility at Holly Refining and Marketing’s refinery complex located in
Tulsa, Oklahoma. The new facility, expected to be completed in mid-2013, will remove a portion of the sulfur from the crude
oil refined at Holly’s complex and is expected to result in potential additional capacity of 24,000 DST per year of NaHS.
Rail Projects
In August 2012, we completed construction on the first phase of a new crude-by-rail unloading terminal connected to
our existing crude oil pipeline at Walnut Hill, Florida. This facility is capable of handling unit train shipments of oil for direct
deliveries to an existing refinery customer and indirect deliveries (through third-party common carriers) to multiple other
markets in the Southeast at the option of the shippers. We anticipate the second phase of the terminal, which includes a 100,000
barrel storage tank and related equipment, will be fully operational in the first quarter of 2013.
In 2012, we completed initial phase construction of a crude oil rail loading facility in Wink, Texas, giving us the
capability to load Genesis and third party railcars designed to move West Texas production to more highly valued markets.
Additional expansion of this facility, which we estimate will be completed by late third quarter or early fourth quarter of 2013,
will allow us to increase the capacity of this system.
In 2012, we commenced construction on a crude oil rail unloading/loading facility at our existing terminal located in
Natchez, Mississippi, which is designed to facilitate the movement of Canadian bitumen/dilbit to Gulf Coast markets. The
facility will have the capability to unload bitumen/dilbit as well as loading diluent for backhauls to Canada. We estimate this
facility will be operational in the first quarter of 2013.
52
Wyoming Gathering Project
We are re-activating portions of the related gathering and transportation pipelines in Wyoming and constructing a new
pipeline which will connect to the Casper, Wyoming markets. We anticipate the re-activation of existing pipelines and the new
pipeline will be completed in the second quarter of 2013.
Purchase of FMT Barges
In February 2012, we purchased seven barges from Florida Marine Transporters, which previously had been subleased
to us in connection with the acquisition of the black oil barge assets in August 2011. The cost of the seven barges totaled $30.9
million, which was funded with borrowing under our credit facility.
Capital Expenditures Related to Equity Investees
SEKCO, a joint venture with Enterprise Products, is constructing a deepwater pipeline serving the Lucius
development area in southern Keathley Canyon of the Gulf of Mexico. The new pipeline is expected to begin service by
mid-2014. We expect to spend approximately $200 million for our share of the pipeline construction through 2014 and to
reimburse Enterprise Products for our portion of previously incurred costs. In 2012, we contributed $63.7 million to SEKCO
that was used to fund our share of the construction costs incurred during the year. Approximately $125 million of the total
estimate is expected to be paid in 2013. Most cost overruns and other costs incurred associated with weather related delays will
be the responsibility of the producers that have entered into transportation agreements with us.
Maintenance Capital Expenditures
Maintenance capital expenditures for 2013 are anticipated to total approximately $4 million to $5 million. We would
expect to spend similar amounts annually on maintenance capital projects in future years.
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 consists generally of all of our cash receipts less cash
disbursements adjusted for net changes to reserves. We have increased our distribution for each of the last thirty quarters,
including the distribution paid for the fourth quarter of 2012, as shown in the table below (in thousands, except per unit
amounts). Each quarter, our board of directors determines the distribution amount, or available cash, per unit based upon
various factors such as our operating performance, cash on hand, future cash requirements and the economic environment. As a
result, the historical trend of distribution increases may not be a good indicator of future increases.
Distribution For
2010
4th Quarter
2011
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
2012
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
Date Paid
Per Unit
Amount
Total
Amount
February 14, 2011
May 13, 2011
August 12, 2011
November 14, 2011
February 14, 2012
May 15, 2012
August 14, 2012
$
$
$
$
$
$
$
November 14, 2012
February 14, 2013
$
(1) $
0.4000
0.4075
0.4150
0.4275
0.4400
0.4500
0.4600
0.4725
0.4850
$
$
$
$
$
$
$
$
$
25,846
26,343
29,878
30,777
31,677
35,768
36,563
38,375
39,390
(1) This distribution was paid on February 14, 2013 to unitholders of record as of February 1, 2013.
53
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, 2012.
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 (3)
Unconditional purchase obligations (4)
Other Cash Commitments:
Asset retirement obligations (5)
Total
$
— $
— $
500,000
$
350,895
$
850,895
48,813
19,285
297,418
—
97,625
37,257
—
—
88,502
21,674
—
—
26,581
43,145
—
261,521
121,361
297,418
31,038
31,038
$
365,516
$
134,882
$
610,176
$
451,659
$
1,562,233
(1) Our credit facility allows us to repay and re-borrow funds at any time through the maturity date of July 25, 2017. Our
senior unsecured notes are due December 15, 2018. In February 2013, we issued an additional $350 million in
aggregate principal amount senior unsecured notes that mature in February 2021. The net proceeds were used for
general partnership purposes, including to repay borrowings under our credit facility, which will result in extending
the repayment of approximately $350 million of our long term debt obligations as of February 2013 from the 3 to 5
year payment period to the more than 5 year payment period.
(2) Interest on our long-term debt under our credit facility is at market-based rates. The interest rate on our senior
unsecured notes is 7.875%. The amount shown for interest payments represents the amount that would be paid if the
debt outstanding at December 31, 2012 under our credit facility remained outstanding through the final maturity date
of July 25, 2017 and interest rates remained at the December 31, 2012 market levels through the final maturity date.
Also included is the interest on our senior unsecured notes through the maturity date.
(3) Includes operating lease obligations on approximately 400 rail cars which we expect to receive in 2013.
(4) 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, 2012 were
used to value those obligations. The actual physical volumes and settlement prices may vary from the assumptions
used in the table. Uncertainties involved in these estimates include levels of production at the wellhead, changes in
market prices and other conditions beyond our control.
(5) Represents the estimated future asset retirement obligations on an undiscounted basis. The recorded asset retirement
obligation on our balance sheet at December 31, 2012 was $12.7 million and is further discussed in Note 6 to our
Consolidated Financial Statements.
In connection with our 50% interest in SEKCO as described above we have committed to share the required funding
with Enterprise Products to construct a deepwater pipeline serving the Lucius development area in southern Keathley Canyon
of the Gulf of Mexico. We expect to spend approximately $200 million for our share of the pipeline construction through 2014
and to reimburse Enterprise Products for our portion of previously incurred costs. In 2012, we paid $63.7 million.
Approximately $125 million of the total estimate is expected to be paid in 2013. Most cost overruns and other costs incurred
associated with weather related delays will be the responsibility of the producers that have entered into transportation
agreements with us. See “Significant Events” above for more information.
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.
54
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, 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 and intangible assets with indefinite lives are not amortized but
instead are 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 and Amortization of Long-Lived Assets and Intangibles
In order to calculate depreciation and amortization we must estimate the useful lives of our fixed assets 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.
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.
55
During 2011, we adopted new accounting guidance, which provides the option to make a qualitative evaluation about
the likelihood of goodwill impairment. After performing a qualitative assessment of relevant events and circumstances, 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. 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, 2012, our market capitalization exceeded the book value
of our equity; 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, 2012. We did not have any goodwill
impairments in 2012, 2011 or 2010.
For additional information regarding our goodwill, see Note 9 to our Consolidated Financial Statements in Item 8.
Equity Compensation Plan Accruals
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, 2012, we had
354,713 phantom units outstanding and recorded $6.7 million of expense during 2012. The liability recorded for phantom units
expected to vest fluctuates with the market price of our common units. At the date of vesting, any difference between the
estimates recorded and the actual cash paid to the grantee will be charged to expense. At December 31, 2012, we estimated
approximately $7.5 million of compensation costs to be recognized over a weighted average period of approximately two years
for these awards. Changes in our assumptions may impact our liabilities and expenses related to these awards.
We accrue for the fair value of our liability for the stock appreciation rights, or SAR, awards we have issued to our
employees and directors. Under our SAR plan, grantees receive cash for the difference between the market value of our
common units and the strike price of the award at the time of exercise. We estimate the fair value of SAR awards at each
balance sheet date using the Black-Scholes option pricing model. The Black-Scholes valuation model requires the input of
somewhat subjective assumptions, including expected stock price volatility and expected term. Other assumptions required for
estimating fair value with the Black-Scholes model are the expected risk-free interest rate and our expected distribution yield.
The risk-free interest rates used are the U.S. Treasury yield for bonds matching the expected term of the option on the date of
grant. We recognize the equity-based compensation expense on a straight-line basis over the requisite service period for the
awards. The expense we recognize is net of estimated forfeitures. We estimate our forfeiture rate at each balance sheet date
based on prior experience. As of December 31, 2012, there was less than $0.1 million of total compensation cost to be
recognized in future periods related to non-vested SARs. The cost is expected to be recognized in the first quarter of 2013. We
also record compensation cost for changes in the estimated liability for vested SARs. The liability recorded for vested SARs
fluctuates with the market price of our common units. Changes in our assumptions may impact our liabilities and expenses
related to these awards.
See Note 15 to our Consolidated Financial Statements in Item 8 for further discussion regarding our equity
compensation plans.
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
56
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, 2012, 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
Recent and Proposed Accounting Pronouncements
Recently Issued
In July 2012, the Financial Accounting Standards Board ("FASB") issued guidance intended to simplify the
impairment test for indefinite-lived intangible assets other than goodwill by giving entities the option to first assess qualitative
factors to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired. The results of the
qualitative assessment would be used as a basis in determining whether it is necessary to perform the two-step quantitative
impairment testing. An entity can choose to perform the qualitative assessment on none, some or all of its indefinite-lived
intangible assets, or may bypass the qualitative assessment and proceed directly to the quantitative impairment test. This
guidance will be effective for annual and interim impairment tests performed for fiscal years beginning after September 15,
2012, with early adoption permitted in certain circumstances. We will adopt this guidance on January 1, 2013. Our adoption is
not expected to have a material impact on our financial position, results of operations or cash flows.
Recently Adopted
In December 2011, the FASB issued guidance requiring new disclosures for financial instruments and derivative
instruments that are eligible for offset in the statement of financial position or subject to a master netting arrangement. The new
guidance is effective for us beginning January 1, 2013 and is not expected to have a significant impact on our financial
position, results of operations or cash flows.
In June 2011, the FASB issued guidance that modified how comprehensive income is presented in an entity’s financial
statements. The guidance issued requires an entity to present the total comprehensive income, the components of net income,
and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two
separate but consecutive statements and eliminates the option to present the components of other comprehensive income as part
of the statement of equity. We adopted the revised financial statement presentation for comprehensive income beginning
January 1, 2012 and it did not have a significant impact on our financial position, results of operations or cash flows. The
guidance pertaining to reclassifying items out of accumulated other comprehensive income has been deferred and will be
effective for us beginning January 1, 2013. The adoption of this guidance is not expected to have a significant impact on our
financial position, results of operations or cash flows.
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,
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 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, 2012 were categorized as non-
trading. On December 31, 2012 we had entered into NYMEX future contracts that will settle between January and March 2013
and NYMEX options contracts that will settle during February and April 2013. This accounting treatment is discussed further
in Note 17 to our Consolidated Financial Statements.
The table below presents information about our open derivative contracts at December 31, 2012. 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
57
open positions are presented below. Fair values were determined by using the notional amount in barrels or gallons multiplied
by the December 31, 2012 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.
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
Heating Oil
#6 Fuel Oil
Buy (Long) Contracts:
Crude Oil
#6 Fuel Oil
NYMEX Option Contracts (2)
Written Contracts:
Crude Oil
Purchased Contracts:
Crude Oil
NYMEX Swap Contracts
Crude Oil
Bbl
Bbl
Bbl
Bbl
Bbl
Bbl
Bbl
Bbl
316
62
765
199
160
Bbl
$
Gal (1) $
$
Bbl
91.82
$ 27,919
3.03
$
7,864
94.65
$ 70,666
Bbl
Bbl
91.84
$ 17,842
94.65
$ 14,890
$
$
$
$
$
1,096
30
1,741
434
255
$
$
$
$
$
29,015
7,894
72,407
18,276
15,145
325
Bbl
85
Bbl
1.24
$
523
$
(121) $
402
0.58
$
46
$
3
$
49
100
Bbl
$
17.94
$
1,725
$
69
$
1,794
$
$
$
$
(1) Prices and volumes are 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.
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, 2012, we had $500 million of
debt outstanding under our credit facility. For the year ended December 31, 2012, a 10% change in LIBOR would have resulted
in approximately a $1.2 million change in net income.
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” on page 86.
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
58
financial officer, with the participation of our management, have evaluated our disclosure controls and procedures as of the end
of the period covered by this Annual Report on Form 10-K and have determined that such disclosure controls and procedures
are effective in providing assurance of the timely recording, processing, summarizing and reporting of information, and in
accumulation and communication to management on a timely basis material information relating to us (including our
consolidated subsidiaries) required to be disclosed in this Annual Report on Form 10-K.
Changes in Internal Controls over Financial Reporting
There were no changes during our last fiscal quarter that materially affected, or are reasonably likely to materially
affect, our internal control over financial reporting.
Management’s Report on Internal Control over Financial Reporting
Management of the Partnership is responsible for establishing and maintaining effective internal control over financial
reporting as defined in Rules 13a-15(f) under the Securities Exchange Act of 1934. The Partnership’s internal control over
financial reporting is designed to provide reasonable assurance to the Partnership’s management and board of directors
regarding the preparation and fair presentation of published financial statements.
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, 2012. 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. Based on our assessment, we
believe that, as of December 31, 2012, the Partnership’s internal control over financial reporting is effective based on those
criteria.
Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, our management included a report of their assessment of
the design and effectiveness of our internal controls over financial reporting as part of this Annual Report on Form 10-K for the
fiscal year ended December 31, 2012. Deloitte & Touche 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. Deloitte &
Touche’s attestation report on the Partnership’s internal control over financial reporting appears in Item 8. “Financial
Statements and Supplementary Data.”
Item 9B. Other Information
None.
Part III
Item 10. Directors, Executive Officers and Corporate Governance
Management of Genesis Energy, L.P.
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.
As is common with MLPs, our partnership structure does not allow our unitholders (of our Class A and Class B
Common Units and Waiver Units) to directly or indirectly participate in our management or operations. The board of directors
of our general partner must approve significant matters (such as business strategies, mergers, business combinations,
acquisitions or dispositions of significant assets, issuances of common units, incurrence of debt or other financing and the
payment of distributions.) The holders of our Waiver Units are not, generally, entitled to vote on any matters. The holders of
Class B Common Units are entitled to (i) vote in the election of the board of directors of our general partner (which we refer to
as “our board of directors”), subject to the Davison family’s rights 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 the removal of
our general partner (or the director election rights of our Class B Common Unitholders) under specified circumstances. For
example, our unitholders may remove our general partner by a vote of the holders of not less than a majority of the outstanding
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common units, excluding units held by our general partner and its affiliates. Any removal of our general partner is also subject
to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units.
Collectively, members of the Davison family own approximately 17% of our Class A Common Units and 76.9% of our
Class B Common Units. The Davison family is entitled to elect up to three directors under terms of its unitholders rights
agreement. If members of the Davison family own (i) 15% or more of our common units, they have the right to appoint three
directors, (ii) less than 15% but more than 10%, they have the right to appoint two directors, and (iii) less than 10%, they have
the right to appoint one director. So long as the Davison family has the right to elect three directors, our board of directors
cannot have more than 11 directors without the Davison family’s consent.
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., Donald L.
Evans, Corbin J. Robertson III, Kenneth M. Jastrow II, and Mr. Sims. Our board of directors has determined that each of
Ms. Gasaway and Messrs. Evans, Robertson and Jastrow 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 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. As a result, Mr. Sims serves as
Chairman and Chief Executive Officer. 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 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.
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, 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.
Risk Oversight
We face a number of risks, including environmental and regulatory risks, and others, such as the impact of competition
and weather conditions. Management is responsible for the day-to-day management of 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 is available to address any questions or
60
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
compensation committee assists our board of directors with risk management relating to our compensation policies and
programs.
Our board of directors believes it is in our best interest for the interests of the members of our board of directors and
certain of our officers to be aligned (when practical) 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 buying, selling or engaging in transactions with respect to our common units while they
are aware of material non-public information and 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 and/or held in broker margin accounts. See Item 12.
"Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters."
Independence Determinations and 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, Corbin J.
Robertson III and Kenneth M. Jastrow II serve as the members of the audit committee. Ms. Gasaway is the chairperson. Our
board of directors believes that Ms. Gasaway qualifies as an audit committee financial expert 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.
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.
The following individuals constitute the G&C Committee:
Kenneth M. Jastrow II, Chairman
James E. Davison
James E. Davison, Jr.
Sharilyn S. Gasaway
Donald L. Evans
Corbin J. Robertson III
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
our general partner or any of its 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
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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,
2013. All executive officers serve at the discretion of our general partner.
Name
Grant E. Sims
James E. Davison
James E. Davison, Jr.
Donald L. Evans
Sharilyn S. Gasaway
Kenneth M. Jastrow II
Corbin J. Robertson III
Steven R. Nathanson
Robert V. Deere
Paul A. Davis
Stephen M. Smith
Karen N. Pape
Age
57
75
46
66
44
65
42
57
58
49
36
54
Director, Chairman of the Board, and Chief Executive Officer
Position
Director
Director
Director
Director
Director
Director
President and Chief Operating Officer
Chief Financial Officer
Senior Vice President
Vice President
Senior Vice President and Controller
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 is also a director of Texas Capital Bancshares, Inc.
Mr. Sims had been a private investor since 1999. He was affiliated with Leviathan Gas Pipeline Partners, L.P. 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 an NYSE-listed MLP that merged with Enterprise Products Partners, L.P. on September 30, 2004. 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.
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 Storage, Inc. Mr. Davison has
over forty years experience in the energy-related transportation and refinery services businesses. Mr. Davison brings to our
board of directors significant energy-related transportation and refinery services 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
Community Trust Financial Corporation 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.
Donald L. Evans has served as a director of our general partner since February 5, 2010. Mr. Evans has served as
President of The Don Evans Group, Ltd. since 2005 and served as the 34th Secretary of the U.S. Department of Commerce
from 2001 to 2005. Since 2007, Mr. Evans has also served as the Non-Executive Chairman of Energy Future Holdings Corp., a
provider of electricity and related services. We believe that Mr. Evans’ background and knowledge coupled with the leadership
qualities demonstrated by his executive background bring important experience and skill to our board of directors.
Sharilyn S. Gasaway has served as a director of our general partner since March 1, 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
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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 both companies. Additionally, Ms. Gasaway serves on the
nominating committee of JB Hunt and the nominating and corporate governance committee and investment committees 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 1, 2010, and serves as chairperson
of the G&C Committee. Mr. Jastrow is Non-Executive Chairman of Forestar Group, Inc., a real estate and natural resources
company. He served as Chairman and Chief Executive Officer of Temple-Inland, Inc., a manufacturing company and the
former parent of Forestar Group, from 2000 to 2007. Prior to that, Mr. Jastrow served in various roles at Temple-Inland,
including President and Chief Operating Officer, Group Vice President and Chief Financial Officer. Mr. Jastrow is also a
director of KB Home and MGIC Investment Corporation, where he also serves on the compensation committee. 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.
Corbin J. Robertson III has served as a director of our general partner since February 5, 2010. Mr. Robertson is a
Managing Partner of LKCM Headwater Investments GP, LLC and LKCM Headwater Investments I, L.P., a private equity fund.
Mr. Robertson is also an owner of various interests associated with the Robertson family holding company and Quintana
Capital Group, an energy focused private equity firm he co-founded. Mr. Robertson currently serves on various boards of
Quintana and LKCM Headwater affiliated portfolio companies. Previously, Mr. Robertson was a Vice President for Reservoir
Capital Group, a New York-based investment firm, and prior to that, he worked for three years as a Vice President for Sandefer
Capital Partners, an energy investment fund. We believe that Mr. Robertson's experience with investment in a variety of energy
businesses provides a valuable resource to our board of directors.
Steven R. Nathanson became President and Chief Operating Officer in December 2010 and an executive officer of our
general partner in February 2010. He had served as President of our refinery services subsidiary, TDC, LLC since 2002.
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.
Paul A. Davis has served as Senior Vice President of our general partner since March 2012. Mr. Davis is responsible
for the commercial development of Genesis. Mr. Davis spent approximately 19 years in the investment banking industry with a
focus in the midstream and master limited partnership sector, serving in various roles, including Managing Director at Bank of
America Merrill Lynch.
Stephen M. Smith has served as Vice President of our general partner since February 2010. Mr. Smith is responsible
the commercial aspects of our Supply and Logistics segment. Since 2009, Mr. Smith has served in various capacities within our
commercial development and finance groups. He was a Principal for the energy investment banking group at Banc of America
Securities from 2006 to 2009.
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.
Common Unit Ownership by Directors and Executive Officers
We encourage our directors and officers to own our common units, although we do not feel it is necessary to require
them to own a minimum number. Certain of our directors and officers own substantial amounts of our securities, although any
(or all) of them may sell, pledge or otherwise dispose of all or a portion of those securities at any time, subject to any applicable
legal and company policy requirements. See Item 10. “Directors, Executive Officers and Corporate Governance-Board
Leadership Structure and Risk Oversight-Risk Oversight.”
Code of Ethics
We have adopted a code of ethics that is applicable to, among others, the principal financial officer and the principal
accounting officer. The Genesis Energy Financial Employee Code of Professional Conduct 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
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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.
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, 2012.
Compensation Discussion and Analysis
Named Executive Officers
Our NEOs for 2012 were:
•
•
•
•
•
Grant E. Sims, Chief Executive Officer;
Steven R. Nathanson, President and Chief Operating Officer;
Robert V. Deere, Chief Financial Officer;
Paul A. Davis, Senior Vice President; and
Stephen M. Smith, Vice President
Board and Governance, Compensation and Business Development Committee
Our board of directors is responsible for, and effectively determines, compensation matters. Our board of directors
has delegated to the G&C Committee, a majority of the members of which are "independent," the authority and responsibility
to regularly analyze and reconsider our compensation policies, to determine the annual compensation of our employees, 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” 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 by the G&C Committee are effectively determinations
by our board of directors. 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 as to the compensation of the other NEOs, which proposal is based on (among other things)
our financial results for the prior year, the individual executive’s areas of responsibility, as well as recommendations from that
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 with our board of directors
regarding compensation of our NEOs. Depending on the nature and quantity of changes made to that proposal, there may be
additional G&C Committee meetings and discussions with our CEO in advance of that determination.
Committee/Board Approval
The G&C Committee determines compensation and long-term awards for executive officers, taking into
consideration the CEO’s recommendation regarding the NEOs. Following approval of the entire annual compensation
program in the first quarter of each year, any applicable salary increases and long-term incentive awards are made or granted.
Bonuses are paid in March.
Role of Compensation Consultant
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 2012, 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 listings 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 prepared for and circulated to the G&C Committee and management’s proposed executive compensation
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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 does not determine or recommend the amount of compensation.
The peer group used for this analysis consisted of the following 18 companies in the energy industry: Blueknight
Energy Partners, Buckeye Partners, Copano Energy, LLC, Crosstex Energy Partners, DCP Midstream Partners, Eagle Rock
Energy Partners, Holly Energy Partners, Magellan Midstream Partners, NuStar Energy, LP, Penn Virginia Resource Partners,
Regency Energy Partners, Sunoco Logistics, LP, Targa Resource Partners, Amerigas Partners, Calumet Specialty Products
Partners, HollyFrontier Corporation, Natural Resource Partners and Western Refining. These companies were selected as the
compensation peer group because: they
1) reflect our industry competitors for products and services;
2) operate in similar markets or have comparable geographical reach;
3) are of similar size and maturity to us; or
4) are companies that had similar credit profiles, comparable debt and equity markets or similar growth or capital
programs to us.
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 maximizing cash distributions and growth in 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 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 compensating 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 targeted a specific percentile of peer company pay as a target. Rather, we use market information as one
consideration in setting compensation along with individual performance, our financial and operational performance and our
safety performance.
We pay base salaries at levels that we feel are appropriate for the skills and qualities of the individual NEOs based on
their past performance, current scope of responsibilities and future potential. The incentive-based components of each NEO’s
compensation include annual cash incentive 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-term and long-term incentives, cash and non-cash based compensation
and an alignment of the incentives for our executives, including our NEOs, with the interests of our common unitholders.
Compensation that is earned over the long-term through service and performance-based opportunities aims to assure an
alignment between executives and investors in the organization. The amount of compensation contingent on performance is
weighted with a significant emphasis of performance as a percentage of total compensation, therefore ensuring business
decisions and actions lead to the long-term growth and sustainability of the organization. Our bonus plan is driven by the
generation of Available Cash before Reserves (which is an important metric of value for our unitholders) and our safety
record. Our long term incentive plan is linked primarily to the appreciation in our common unit price and increases in the
distribution rate on our common units, which we believe links pay with performance and creates an alignment of interest
between our NEOs and our unitholders.
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Elements of Our Compensation Program and Compensation Decisions for 2012
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, 2012, the elements of our compensation program for the NEOs
consisted of the following:
•
•
•
annual cash base salary
discretionary annual cash 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, as well as 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 based on recommendations from our CEO. 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 analyses of peer group
practices as described above.
In April 2012, 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 and, as a result, approved market adjustments
for the following NEOs: Mr. Sims’ salary was increased 5% to $500,000, Mr. Nathanson's salary was increased 14% to
$375,000, Mr. Deere's salary was increased 5% to $440,000, Mr. Smith’s salary was increased 14% to $250,000. Mr. Davis'
salary was not adjusted as he was hired in March 2012 at a salary that we felt was appropriate based on the scope of his
responsibilities, future potential and market levels. The G&C Committee determined that such increases were necessary to
align salaries to comparable market levels and were warranted in light of their individual performance and increased levels of
responsibility related to the management of the company.
Bonuses
Our NEOs participate in a bonus program, or the Bonus Plan, in which 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 set following the analysis of market practices of the peer group and consideration of the level
of salary and targeted long-term incentives for each NEO. For 2012, the G&C Committee set each NEO’s bonus target as a
percentage of salary as follows:
Name
Grant E. Sims
Steven R. Nathanson
Robert V. Deere
Paul A. Davis
Stephen M. Smith
2012
Bonus Target
(% of base salary)
100%
100%
50%
100%
100%
The Bonus Plan is designed to reward employees on a basis that is aligned with the interests of our unitholders. We
believe the Bonus Plan generates a bonus that represents a meaningful level of compensation for the employee population and
encourages employees to operate as a unified team to generate results that are aligned with the interests of our unitholders.
The G&C Committee therefore designed the Bonus Plan to enhance our financial performance by rewarding our NEOs and
other employees for achieving (i) financial performance and (ii) safety objectives. Attainment of these two goals is measured
by, respectively, Available Cash before Reserves (before subtracting bonus expense and related employer tax burdens) and
company-wide safety incident rates. Available Cash before Reserves, which is a "non-GAAP" measure, is an important factor
in determining the amount of distributions to our unitholders and is a significant factor in the market’s perception of the value
of common units of an MLP. Safety objectives encourage our employees to focus on the impact their job performance has on
66
the environment in which we operate. Both of these measures are used to calculate the recommended bonus payout (or general
bonus pool) described below. However, bonuses are paid at the discretion of the G&C Committee based on quantitative and
qualitative measures relating to: our financial and operational performance relative to our peers; industry expectations;
progress in attaining strategic goals; and individual performance. Because the determination of whether bonuses will be paid
each year and in what amounts they will be paid is determined by the G&C Committee on a company-wide basis, NEOs only
receive bonuses if other employees receive bonuses. See Item 7. “Management’s Discussion and Analysis of Financial
Condition and Results of Operations” for a description of Available Cash before Reserves.
The general bonus pool was weighted and calculated as follows: the level of Available Cash before Reserves
generated for the year as a percentage of a target set by the G&C Committee was weighted 90% and the achieved level of the
safety incident rate was weighted 10%. The sum of the weighted percentage achievement of these targets was multiplied by
the eligible compensation and the target percentages established by the G&C Committee for the various levels of our
employees to determine the maximum general bonus pool.
The total 2012 pool approved for such bonuses, inclusive of other discretionary downward adjustments, was
approximately $7.8 million. From the general bonus pool amount, the G&C Committee approved 2012 bonuses of $425,000,
$375,000, $200,000, $200,000 and $250,000 to Messrs. Sims, Nathanson, Deere, Davis, and Smith, respectively. The bonuses
were approved based on the G&C Committee’s review of the operational and financial performance of the company, industry
expectations and individual performance. The bonuses will be paid in March 2013.
Long-Term Incentive Compensation
We provide equity-based, long-term compensation for employees, including executives and directors, 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 sale, pledge or hedge) any of their LTIP Awards. The 2010 LTIP provides for the awards of phantom units and
DERs to directors of our general partner, and employees and other representatives of our general partner and its affiliates 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. 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 the phantom units had they been limited partner units issued by us.
The G&C Committee administers the 2010 LTIP. Under the 2010 LTIP, the G&C Committee (at its discretion) 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.
Long-term incentive awards are expressed as a percentage of base salary. This percentage reflects the expected fair
value of the awards to be granted in aggregate each year. The targeted amount for the NEOs is set following the analysis of
market practices of the peer group and consideration of the level of salary and targeted bonus for each NEO. For 2012, the
G&C Committee established the following long-term incentive target percentages (expressed as a percent of base salary) for
each of our NEOs:
Name
Grant E. Sims
Steven R. Nathanson
Robert V. Deere
Stephen M. Smith
2012
Long-Term Incentive Target
(% of base salary)
225%
200%
100%
125%
In April 2012, phantom units were granted to certain NEOs (Mr. Davis was not granted a phantom unit award due to
his recent hiring in March 2012) and certain non-officer employees under the 2010 LTIP. The 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
67
date of vesting. The phantom units granted to our NEOs in April 2012 were all performance-based awards while phantom
units granted to our non-officer employees, were apportioned 60% to performance-based awards and 40% to service-based
awards. The service-based awards vest on the third year anniversary from the date of grant.
Between 50% and 150% of the number of performance-based awards granted to our NEOs and non-officer
employees will vest on the third anniversary of issuance if certain quarterly cash distribution targets are achieved in the fourth
quarter of 2014. Should the quarterly cash distribution on the common units fall between the range of $0.49 per unit and $0.57
per unit, the phantom units will vest between 50% and 150% of the number granted on a pro rata basis. If the quarterly cash
distribution is below $0.49 per unit for the fourth quarter of 2014, all of the performance-based phantom units granted will be
forfeited. In order to align the interests of our NEOs with our common unitholders and incentivize the NEOs to meet targeted
distribution annual growth rates ranging between approximately 5% and 9%, these awards will vest as follows:
(i) if the quarterly cash distribution on the common units is $0.49 per unit, 50% of the phantom units granted will
vest, and the remainder will be forfeited;
(ii) if the quarterly cash distribution on the common units is $0.53 per unit, 100% of the phantom units granted will
vest; or
(iii) if the quarterly cash distribution on the common units is $0.57 per unit or greater, 150% of the phantom units
granted will vest.
Should the quarterly cash distribution on the common units fall between the range of $0.49 per unit and $0.57 per
unit, the phantom units will vest between 50% and 150% of the number granted on a proportionately adjusted basis (for
example, if the quarterly cash distribution on the common units is $0.51 per unit, 75% of the phantom units granted will vest
or if the quarterly cash distribution on the common units is $0.55 per unit, 125% of the phantom units granted will vest). If the
quarterly cash distribution is below $0.49 per unit for the fourth quarter of 2014, 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 service-based awards to our non-officer employees will be paid quarterly in connection with the
related phantom units. DERs on all granted performance-based awards to our NEOs are accumulated and paid upon vesting
when the number of phantom units earned is determined.
Equity Award Granted to Paul A. Davis
In connection with Mr. Davis' appointment as Senior Vice President of our general partner in March 2012, he
received, and fully vested in, a one-time new-hire equity award equivalent to $500,000 of grant date fair market value, which
we determined was appropriate based on our assessment of the competitive compensation market and Mr. Davis' experience in
the industry and the scope of his responsibilities. Mr. Davis' equity award consisted of 12,206 Class A Units and 2,946 Waiver
Units.
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 that this uncertainty may 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 agreements of Messrs. Sims,
Nathanson, Deere and Davis provide certain compensation and benefits as an incentive for the executive to remain in our
employ and enhance our ability to call on and rely upon the executive in the event of a change of control. None of these NEOs
would be entitled to severance benefits if terminated by our general partner 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
“Employment Agreements” below for further discussion of employment agreements, 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.
For more details on the benefits and payouts under various termination scenarios, including in connection with a
change of control, see “Potential Payments upon Termination or Change of Control.”
68
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, and we do not provide post-retirement medical benefits to our
employees.
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 15 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 the review and discussions, 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
Donald L. Evans
Corbin J. Robertson III
The information contained in this report shall not be deemed to be soliciting material or filed with the SEC or subject
to the liabilities of Section 18 of the Exchange Act, except to the extent that we specifically incorporate it by reference into a
document filed under the Securities Act or the Exchange Act.
Compensation Risk Assessment
Our board of directors does not believe that our compensation policies and practices for employees are reasonably
likely to have a material adverse effect on us. We compensate all employees with a combination of competitive base salary
and incentive compensation. Our board of directors believes that the mix and design of the elements of employee
compensation do not encourage employees to assume excessive or inappropriate risk taking.
Our board of directors concluded that the following risk oversight and compensation design features guard against
excessive risk-taking:
•
•
•
•
•
•
•
the company has strong internal financial controls;
base salaries are consistent with employees’ responsibilities so that they are not motivated to take excessive
risks to achieve a reasonable level of financial security;
the determination of incentive awards is based on a review of a variety of indicators of performance as well
as a meaningful subjective assessment of personal performance, thus diversifying the risk associated with
any single indicator of performance;
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.
69
Summary Compensation Table
The following Summary Compensation Table summarizes the total compensation paid or accrued to our NEOs in
2012, 2011 and 2010.
Name & Principal Position
Grant E. Sims
Chief Executive Officer
(Principal Executive Officer)
Steven R. Nathanson
President and
Chief Operating Officer
Robert V. Deere
Chief Financial Officer
(Principal Financial Officer)
Paul A. Davis (3)
Senior Vice President
Stephen M. Smith
Vice President
Year
2012
2011
2010
2012
2011
2010
2012
2011
2010
2012
2012
2011
2010
Salary ($)
Bonus ($) (1)
Stock
Awards ($) (2)
All Other
Compensation ($) (4)
Total ($)
$ 492,308
$ 425,000
$ 1,198,716
$
147,882
$ 2,263,906
460,962
440,000
361,154
323,654
320,067
433,846
411,923
413,167
215,385
240,769
209,231
226,247
450,000
446,200
375,000
420,000
320,100
200,000
130,000
101,850
200,000
250,000
220,000
194,000
839,346
4,186,488
556,336
499,807
2,259,069
468,817
424,085
805,066
500,000
332,973
222,149
1,097,914
74,978
72,262
94,671
58,087
66,187
77,737
37,285
61,696
10,581
56,343
23,091
38,766
1,825,286
5,144,950
1,387,161
1,301,548
2,965,423
1,180,400
1,003,293
1,381,779
925,966
880,085
674,471
1,556,927
(1) Bonuses are paid in March of the following year (e.g., the bonuses with respect to 2012 will be paid in March 2013).
(2) The amounts shown in this column represent the aggregate grant date fair value for each NEO’s phantom units
granted in 2011 and 2012 under our 2010 Long-Term Incentive Plan, excluding the amount shown for Mr. Davis. The
amount for Mr. Davis represents the grant date fair value of an award of 12,206 Class A Units and 2,946 Waiver
Units issued on the first day of Mr. Davis' employment in March 2012. Amounts in 2010 also include the aggregate
grant date fair value for each NEO’s Series B Award. The Series B Awards provided for the conversion into Series A
units in our general partner under certain conditions. These awards were ultimately exchanged for our Class A Units
and Waiver Units in connection with our IDR Restructuring. For additional information on these awards and our IDR
Restructuring see Note 15 to our Consolidated Financial Statements in Item 8. 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 15 to our Consolidated Financial Statements in Item 8.
(3) Mr. Davis became an executive officer of our general partner in March 2012.
(4) The following table presents the components of "All Other Compensation" for each NEO for the year ended
December 31, 2012.
Name
Grant E. Sims
Steven R. Nathanson
Robert V. Deere
Paul A. Davis
Stephen M. Smith
401(k) Matching
and Profit
Sharing
Contributions (a)
Insurance
Premiums
(b)
Other
Compensation
(c)
$
$
$
$
$
7,500
20,515
17,654
9,046
20,700
$
$
$
$
$
2,700
2,700
2,700
1,535
2,183
$
$
$
$
$
137,682
71,456
57,383
$
$
$
— $
33,460
$
Totals
147,882
94,671
77,737
10,581
56,343
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.
70
Grants of Plan-Based Awards in Fiscal Year 2012
The following table shows equity incentive plan awards granted to our NEOs in 2012.
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
Steven R. Nathanson
Robert V. Deere
Stephen M. Smith
4/10/2012
4/10/2012
4/10/2012
4/10/2012
19,100
8,865
7,470
5,306
38,200
17,729
14,940
10,611
57,300
26,594
22,410
15,917
$
$
$
$
29.45
29.45
29.45
29.45
$
$
$
$
1,198,716
556,336
468,817
332,973
(1) Represents the number of phantom units that each NEO can earn of grant awarded on April 10, 2012, if the company
meets certain performance conditions (threshold, target and maximum) during the fourth quarter of 2014. Upon
achieving either the threshold, target or maximum levels during the fourth quarter of 2014 the NEO earns either 50%
of the initial grant, 100% of the initial grant or 150% of the initial grant, respectively. The target level represents the
number of phantom units initially issued on the grant date. The performance targets are as follows: (i) at threshold, if
the quarterly cash distribution on the common units is $0.49 per unit, 50% of the phantom units granted will vest and
the remainder will be forfeited; (ii) at target, if the quarterly cash distribution on the common units is $0.53 per unit,
100% of the phantom units granted will vest; or (iii) at maximum, if the quarterly cash distribution on the common
units is $0.57 per unit or greater, 150% of the phantom units granted will vest. Should the quarterly cash distribution
on the common units fall between the range of $0.49 per unit and $0.57 per unit, the phantom units will vest between
50% and 150% of the number granted on a proportionately adjusted basis (for example, if the quarterly cash
distribution on the common units is $0.51 per unit, 75% of the phantom units granted will vest or if the quarterly cash
distribution on the common units is $0.55 per unit, 125% of the phantom units granted will vest). If the quarterly cash
distribution is below $0.49 per unit for the fourth quarter of 2014, all of the phantom units granted will be forfeited.
(2) Represents the closing market price of our common units on the date of the phantom unit award on April 10, 2012.
(3) The amounts in this column for each NEO represent the fair value of the award on the date of the grant, based on a
target performance payout (as calculated in accordance with accounting guidance for equity-based compensation)
using the twenty day average closing price of our common units through the date of grant ($31.38).
Employment Agreements
Grant E. Sims and Robert V. Deere
In December 2008, each of Messrs. Sims and Deere entered into four-year employment agreements, which were amended
in February 2010 and automatically terminated by their terms on December 31, 2012. As of December 31, 2012, the annual
base salaries of Messrs. Sims and Deere were $500,000 and $440,000, respectively.
Each 2008 employment agreement contained customary non-solicitation and non-competition provisions that prohibits
the executive from competing with us for a period of one year after termination of the employment agreement. Under those
employment agreements, Messrs. Sims and Deere were entitled to specified severance benefits under certain circumstances
described below.
Each of Messrs. Sims and Deere (or his respective family) would have been entitled to continued health benefits for 18
months after his termination and to the payment of his base salary through December 31, 2012 if he had died or had been
terminated due to a disability or if he had terminated his employment for good reason. If our general partner had terminated
Mr. Sims or Mr. Deere (other than for cause) within two years after a change of control, he would have been entitled to
continued health benefits for 18 months after his termination to the extent that such benefits were subsidized by the
Partnership for its active employees and to the payment of his base salary up through the third year from his date of
termination. As of January 1, 2013, neither of Messrs. Sims nor Deere are entitled to the benefits under his terminated
employment agreement. As used in the employment agreements of Messrs. Sims and Deere, the terms “cause,” “good reason”
and “disability” were generally described below:
•
“Cause” means, in general, if an executive commits willful fraud or theft of our assets, is convicted of a felony or
crime of moral turpitude, materially violates certain provisions of his employment agreement, substantially fails
to perform, is grossly negligent, acts with willful misconduct, acts in a way materially injurious to us, willfully
71
•
•
violates material written rules, regulations or policies, or fails to follow reasonable instructions from the audit
committee, and such failure to follow instructions could reasonably be expected to be materially injurious to us.
“Good reason” means, in general, an executive's duties, responsibilities, base salary, or benefits are materially
diminished, if either our principal executive office or that executive is based anywhere outside of metropolitan
Houston without his consent, if our general partner fails to make a material payment under, or perform a material
provision of, his employment agreement, or our general partner amends or changes certain equity interests in a
manner that materially and adversely affects the executive's right to distributions or redemptions payable because
of such amendment or change, subject to certain exceptions.
“Disability” means, in general, if the executive has been absent from his duties with us on a full-time basis for
180 out of any 220 consecutive calendar days as a result of incapacity due to mental or physical illness or injury
that is determined to be total and permanent by a selected physician or if the Social Security Administration has
determined that executive is totally disabled.
Steven R. Nathanson
Mr. Nathanson entered into an employment agreement with our general partner in July 2007, at a base salary which is
subject to discretionary upward adjustments. Currently, the annual base salary of Mr. Nathanson is $375,000. The agreement
also provides that Mr. Nathanson 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. Mr. Nathanson’s employment arrangement
includes customary non-competition restrictions following his termination and severance benefits in the event of termination
by the company for reasons other than cause or a termination of Mr. Nathanson for cause. See additional discussion in
"Potential Payments upon Termination or Change in Control" below.
Paul A. Davis
Mr. Davis entered into a letter agreement in March 2012, at a base salary which is subject to discretionary upward
adjustments. Currently, the annual base salary of Mr. Davis is $280,000. The agreement also provides that Mr. Davis is
eligible to participate in all other benefit programs (e.g. health, dental, disability, life and/or other insurance plans) for which
executive officers are generally eligible and severance benefits as disclosed in "Potential Payments upon Termination or
Change in Control" below.
Stephen M. Smith
Mr. Smith does not have an employment agreement with us.
72
Outstanding Equity Awards at December 31, 2012
The following table presents the information regarding the outstanding equity awards to our NEOs at December 31,
2012.
Stock Appreciation Rights
Stock Awards
Number of
Securities
Underlying
Stock
Appreciation
Rights
Exercisable
(#) (1)
Stock
Appreciation
Rights
Exercise
Price ($)
Stock
Appreciation
Rights
Expiration
Date
Number of
Phantom
Units That
Have Not
Vested (#)
(2)
Market
Value of
Phantom
Units That
Have Not
Vested ($)
(3)
Name
Grant Date
Grant E. Sims
Steven R. Nathanson
Robert V. Deere
Stephen M. Smith
4/10/2012
4/29/2011
4/20/2010
4/10/2012
4/29/2011
4/20/2010
2/14/2008
4/10/2012
4/29/2011
4/20/2010
4/10/2012
4/29/2011
4/20/2010
16,465 $
20.92
2/14/2018
16,795 $ 586,523
8,030 $ 280,428
5,110 $ 178,454
2,430 $
84,862
Equity
Incentive
Plan
Awards:
Number of
Unearned
Phantom
Units That
Have Not
Vested (#)
(4)
Equity
Incentive
Plan
Awards:
Market
Value of
Unearned
Phantom
Units That
Have Not
Vested ($)
(3)
19,100 $
667,020
14,887 $
519,891
8,865 $
309,588
8,865 $
309,588
7,470 $
260,871
7,522 $
262,687
5,306 $
185,299
3,940 $
137,595
(1) All rights in this column were vested at December 31, 2012.
(2) The phantom unit awards granted in 2010 vest on April 20, 2013.
(3) 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.
(4) The number of performance units reflected in the table assumes a threshold performance payout during the fourth
quarter of 2013 for units granted on April 29, 2011 and the fourth quarter of 2014 for units granted on April 10, 2012
(at which 50% of the initial phantom units awarded will vest on the third year anniversary from the date of grant).
The phantom units will vest at the end of three years between 50% and 150% of the number granted, if certain
quarterly cash distribution target levels for the fourth quarter of 2013 and fourth quarter of 2014 are achieved.
Potential Payments upon Termination or Change in Control
Each of Messrs. Sims, Nathanson, Deere and Davis is entitled under his employment agreement to specified
severance benefits under certain circumstances as discussed above under “Employment Agreements.” As further discussed
above, Messrs. Sims and Deere's employment agreements terminated by their terms on December 31, 2012. As of January 1,
2013, neither of Messrs. Sims nor Deere are entitled to the benefits under his terminated employment agreement. Under a
change in control and certain termination circumstances, our NEOs also will vest in any outstanding awards under our 2010
LTIP. Under the 2010 LTIP, a change in 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.
After his termination other than a voluntary termination or for cause, including in the event of a change of control,
during the initial term of Mr. Nathanson’s employment agreement, Mr. Nathanson would be entitled to (i) continued health
benefits for the remainder of the term of his employment agreement for up to 18 months and (ii) the greater of (x) payment of
73
his base salary for one year and (y) payment of his base salary for the remainder of the term of his employment agreement, but
in no event for more than 18 months.
As used in the employment agreement of Mr. Nathanson, the terms “cause” and “change of control” 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.
“Change of control” means, in general, any sale of equity of us or our general partner or substantially all of the
assets of us or our general partner, merger, conversion or consolidation of us or our general partner, or other
event that, in each case, results in any person or entity (or other persons or entities acting in concert) having the
ability to elect a majority of the members of our board of directors.
After his termination other than a voluntary termination or for cause, including in the event of a change of control,
Mr. Davis would be entitled to (i) continued health benefits for the remainder of the term of his employment agreement for up
to 18 months, (ii) the greater of (x) payment of his base salary for one year and (y) payment of his base salary for the
remainder of the term of his employment agreement, but in no event for more than 24 months; and (iii) to the greater of (x) a
bonus payment of 100% of his base salary for one year and (y) a bonus payment of 100% of his base salary for the remainder
of the term of his employment agreement, but in no event for more than 200% of his base salary for one year.
As used in the employment agreement of Mr. Davis, the terms “cause” and “change of control” 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.
“Change of control” means, in general, any sale of equity of us or our general partner or substantially all of the
assets of us or our general partner, merger, conversion or consolidation of us or our general partner, or other
event that, in each case, results in any person or entity (or other persons or entities acting in concert) having the
ability to elect a majority of the members of our board of directors.
Based upon a hypothetical termination date of December 31, 2012, the termination benefits for Messrs. Sims,
Nathanson, Deere, Davis and Smith for voluntary termination or termination for cause would be zero.
Based upon a hypothetical termination date of December 31, 2012, the termination benefits for Messrs. Sims,
Nathanson, Deere and Davis for termination without cause or for good reason, including death or disability would have been:
Severance pursuant to employment agreement
Healthcare
Total
Grant E. Sims
500,000
$
24,180
524,180
$
Steven R.
Nathanson
$
$
375,000
20,551
395,551
Robert V.
Deere
440,000
30,826
470,826
$
$
Paul A. Davis
$ 1,120,000
30,826
$ 1,150,826
If termination occurs due to death or disability, Messrs. Sims, Nathanson, Deere and Smith 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, 2012 would result in payments under the 2010 LTIP of the following amounts upon death or disability:
Grant E. Sims
Steven R. Nathanson
Robert V. Deere
Stephen A. Smith
$
$
$
$
2,960,310
1,518,710
1,225,535
730,614
74
Based on a hypothetical simultaneous change of control and termination date of December 31, 2012, the change of
control termination benefits for Messrs. Sims, Nathanson, Deere, Davis and Smith would have been as follows:
Severance pursuant to employment agreement
$ 1,500,000
$
375,000
$ 1,320,000
$ 1,026,667
$
Healthcare
24,180
20,551
30,826
30,826
—
—
Grant E.
Sims
Steven R.
Nathanson
Robert V.
Deere
Paul A. Davis
Stephen M.
Smith
Cash payment for vested phantom units under 2010
LTIP
Total
2,960,310
1,518,710
1,225,535
—
730,614
$ 4,484,490
$ 1,914,261
$ 2,576,361
$ 1,057,493
$
730,614
Director Compensation in Fiscal Year 2012
The table below reflects compensation for the directors.
Current Directors
James E. Davison
James E. Davison, Jr.
Donald L. Evans (6)
Sharilyn S. Gasaway
Kenneth M. Jastrow II
Corbin J. Robertson III (6)
Former Directors (5)
S. James Nelson
William K. Robertson (6)
Robert C. Sturdivant (6)
Carl A. Thomason
Fees Earned or
Paid in Cash
($) (1)
Stock
Awards
($) (2) (3)
All Other
Compensation
($) (4)
$
$
$
$
$
$
$
$
$
$
77,000
77,000
78,500
96,000
85,625
77,125
69,625
58,250
58,250
64,875
$
$
$
$
$
$
$
$
$
$
75,000
75,000
75,000
85,000
80,625
75,625
60,625
56,250
56,250
56,875
$
$
$
$
$
$
$
$
$
$
13,096
13,096
13,096
14,836
13,878
13,104
9,913
9,289
9,289
9,299
$
$
$
$
$
$
$
$
$
$
Total
165,096
165,096
166,596
195,836
180,128
165,854
140,163
123,789
123,789
131,049
(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, 2012 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 8,057 outstanding phantom units and 1,000 stock appreciation rights. Messrs. Evans, Jastrow, C.
Robertson and Ms. Gasaway hold 8,057, 8,612, 8,075, and 9,128 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) In October 2012, certain directors resigned from the board of directors of our general partner. In connection with
those directors' resignations, we paid Messrs. Nelson, W. Robertson, Sturdivant and Thomason $268,750, $251,392,
$251,392 and $252,129, respectively, related to phantom units granted under our 2010 LTIP that were outstanding as
of September 30, 2012. Proceeds from the phantom units held by Messrs. W. Robertson and Sturdivant were paid to
an affiliate of Quintana.
(6) Prior to September 30, 2012, all fees paid and amounts paid for DERs related to phantom unit awards for these
directors were paid to an affiliate of Quintana. After September 30, 2012, all fees paid and amounts paid for DERs
related to phantom unit awards for Messrs. Evans and C. Robertson, were paid directly to the individuals.
Directors who are not officers of our general partner are entitled to a base compensation of $150,000 per year, with
$75,000 paid in cash and $75,000 paid in phantom units. Cash is paid, and phantom units are awarded, on the first day of each
calendar quarter. All phantom units awarded to directors are service-based and vest on the third anniversary from the date of
grant. The determination of 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 quarterly amount to be paid in phantom units. So long as he or she is a director on the
75
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.
Chairpersons of the audit committee as well as the G&C Committee receive an additional amount of base
compensation split equally between cash and phantom units, which compensation is paid in equal quarterly installments. Such
additional amount is $20,000 for the chair of the audit committee and $10,000 for the chair of the G&C Committee.
In addition, each 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 $2,000 per meeting, and participation by a director by means of telecommunication will entitle her/him to
additional compensation of $1,500 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.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Securities Authorized for Issuance Under Equity Compensation Plans
Equity Compensation plans approved by security holders:
2007 Long-term Incentive Plan (2007 LTIP)
Number of securities
remaining available for
future issuance under
equity compensation plans
832,928
There were no outstanding phantom units under this plan as of December 31, 2012, 2011 or 2010. For additional
discussion of our 2007 LTIP, see Note 15 to our Consolidated Financial Statements in Item 8.
76
Beneficial Ownership of Partnership Units
The following table sets forth certain information as of February 22, 2013, regarding the beneficial ownership of our
Class A Common Units and Class B Common Units by beneficial owners of 5% or more of such units, 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
Class 3 Waiver Units
Class 4 Waiver Units
Amount and
Nature of
Beneficial
Ownership (1)
Amount and
Nature of
Beneficial
Ownership
Percent
of Class
Amount and
Nature of
Beneficial
Ownership
Percent
of Class
Amount and
Nature of
Beneficial
Ownership
Percent
of Class
Percent
of Class
3,536,256
5,140,286
(2)
(3)
44,451
238,839
—
1,590,765
2,591,029
854,307
653,637
13,188
362,200
134,323
(6)
(8)
(9)
(10)
4.4%
6.3%
*
*
—
2.0%
3.2%
1.1%
*
*
*
*
9,453
13,648
—
1,081
—
—
23.6%
34.1%
—
2.7%
—
—
(4)
91,823
91,823
7,652
15,303
—
5.3%
5.3%
*
*
—
(4)
91,823
91,823
7,652
15,303
—
110,401
(7)
6.4%
110,401
(7)
7,087
17.7%
198,459
11.4%
198,459
—
1,052
—
—
—
—
2.6%
—
—
—
53,944
48,675
982
26,972
8,904
3.1%
2.8%
*
1.6%
*
53,944
48,675
982
26,972
8,904
5.3%
5.3%
*
*
—
6.4%
11.4%
3.1%
2.8%
*
1.6%
*
15,159,281
18.7%
32,321
80.8%
654,938
37.7%
654,938
37.7%
Name and Address of
Beneficial Owner
James E. Davison
James E. Davison, Jr.
Donald L. Evans (5)
Sharilyn S. Gasaway
Kenneth M. Jastrow II
Corbin J. Robertson III
Grant E. Sims
Steven R. Nathanson
Robert V. Deere
Paul A. Davis
Stephen M. Smith
Karen N. Pape
All directors and executive
officers as a group (12 in
total)
Steven K. Davison
2,785,195
(11)
3.4%
7,676
19.2%
91,822
(12)
5.3%
91,822
(12)
5.3%
* Less than 1%
(1) The Class B Common Units, which are included in the Class A Common Unit total, are identical to the Class A
Common Units and, accordingly, have voting and distribution rights equivalent to those of the Class A Common Units,
and, 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. James E. Davison
is the sole stockholder of Davison Terminal Service, Inc., which directly owns 1,010,835 Class A Common Units.
(3) Mr. Davison, Jr. pledged 2,972,711 of these Class A Common Units as collateral for a loan from a bank. 1,155,737 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) 91,823 of each class of our outstanding Waiver Units are held by trusts for Mr. Davison's children.
(5) Mr. Evans is a member of the board of managers of QEP Management Co. GP, LLC, a Delaware limited liability
company (“Management Co GP”), a member of the board of directors and senior partner of Quintana Capital Group
GP, Ltd., a Cayman Islands company (“QCG GP”), and partner of Quintana Capital Group II, L.P., a Cayman Islands
limited partnership (“QCG II”); Each of Quintana Energy Partners II, L.P., a Cayman Islands limited partnership
(“QEP II”), and QEP II Genesis TE Holdco, LP, a Delaware limited partnership (“Holdco”), has (i) QCG II as its
general partner (with QCG GP as the general partner of QCG II), (ii) management services provided by QEP
Management Co., L.P., a Delaware limited partnership (“QEP Management”) (with Management Co GP as the general
partner of QEP Management) and (iii) membership interests in Q GEI. Mr. Robertson, III is the chief executive officer,
president and a member of the board of managers of Q GEI, a manager of Management Co GP, a member of the board
of directors and managing director of QCP GP, a member of Q GEI and a partner in QCG II; The Corbin J. Robertson
III 2009 Family Trust is a member of Q GEI. Each such person disclaims beneficial ownership of all the units reported
by such entities.
(6) Mr. C. Robertson pledged 1,300,000 of these Class A Common Units as collateral for a loan from a bank. Includes
172,951 Class A Common Units held by The Corbin J. Robertson III 2009 Family Trust and 5,743 Class A Common
Units held by Corby & Brooke Robertson 2006 Family Trust.
77
(7) The Corbin J. Robertson III 2009 Family Trust holds 12,917 of each class of our outstanding Waiver Units and Mr. C.
Robertson III holds 97,484 of each class of our outstanding Waiver Units.
(8) Mr. Sims pledged 866,334 of these Class A Common Units as collateral for a loan from a bank. Includes 1,000 Class A
Common Units held by Mr. Sims’ father, of which Mr. Sims disclaims beneficial ownership.
(9) Includes 291,208 Class A Common Units held in trusts in the names of Mr. Nathanson's children, of which Mr.
Nathanson disclaims beneficial ownership.
(10) Includes 100,000 Class A Common Units that are held in a margin brokerage account.
(11) Includes 132,245 Class A Common units held by the Steven Davison Family Trust.
(12) The Steven Davison Family Trust holds 22,848 of each class of our outstanding Waiver Units and Mr. S. Davison
holds 68,974 of each class of our outstanding Waiver Units. The mailing address for Mr. S. Davison is 2000
Farmerville Highway, Ruston, Louisiana, 71270.
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.
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
The Quintana Group monetized all of its remaining investment in us on October 5, 2012, with members of the
Davison family, our CEO, Mr. Sims, and certain members of our board of directors purchasing an aggregate 34,998 (or 87.5%)
of our Class B Common Units at a price of $30.00 per unit in a private placement transaction. See Item 10. “Directors,
Executive Officers and Corporate Governance” for a discussion of certain arrangements with the members of the Davison
family to appoint directors and Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters” for a description of such investors’ ownership interest in us.
During 2012, we sold $1.3 million of petroleum products to businesses owned and operated by members of the
Davison family in the ordinary course of our operations.
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
$0.6 million, during 2012. Based on current market rates for chartering of private aircraft, we believe that the terms of this
arrangement are no worse than what we could have obtained in an arms-length transaction.
Family members of certain of our executive officers and directors may work for us from time to time. In 2012, each of
Messrs. Sims (our CEO and a director) and James Davison, Sr. (a director) had a son (in the case of James Davison, Sr., who is
also a brother of James E. Davison, Jr. a director), that worked as a non-executive employee in our business development and
supply and logistics departments, respectively, and received total W-2 compensation of greater than $120,000 but less than
$300,000.
Review or Special Approval of Material Transactions with Related Persons
Before we consider entering into a material transaction with our general partner or any of its affiliates, we determine
whether the proposed transaction (1) would comply with the requirements under our credit facility, (2) would comply with
substantive law, (3) would comply with our partnership agreement, and (4) would be fair to us and our limited partners. For
transactions that are not material, we use “review and approval procedures” that we believe are commensurate with the size and
nature of the underlying transaction, which could involve obtaining appraisals from third parties, having informal discussions
with board members and/or management or other process that we determine suitable. In addition, our board of directors may
form a conflicts committee to review specific matters that our board of directors believes may involve conflicts of interest
between our general partner or any of its affiliates and us. In which case, the conflicts committee:
• would evaluate and, where appropriate, negotiate certain material terms of the proposed transaction;
78
• may engage an independent legal counsel and, if it deems appropriate, an independent financial adviser to assist with
its evaluation of the proposed transaction; and
• would determine whether to reject or approve and recommend the proposed transaction.
For example, a conflicts committee was formed and approved our acquisition of the 51% economic interest in DG
Marine that we did not own in July 2010. Additionally, a conflicts committee was formed and approved our IDR Restructuring
(see Note 11 to our Consolidated Financial Statements in Item 8).
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 under the NYSE
rules, or a nominating or 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. Robertson and Jastrow, each of whom is a member of the audit committee, is an independent director under the NYSE
rules. See Item 10. “Directors, Executive Officers and Corporate Governance” for additional discussion of director
independence.
79
Item 14. Principal Accounting Fees and Services
The following table summarizes the fees for professional services rendered by Deloitte & Touche LLP for the years
ended December 31, 2012 and 2011.
Audit Fees (1)
Audit-Related Fees (2)
Tax Fees (3)
All Other Fees (4)
Total
2012
2011
(in thousands)
2,524
$
2,555
20
768
4
220
938
4
3,316
$
3,717
$
$
(1) Includes fees for the annual audit and quarterly reviews (including internal control evaluation and reporting), SEC
registration statements and accounting and financial reporting consultations and research work regarding Generally
Accepted Accounting Principles.
(2) Includes fees related to (i) reviewing our documentation of controls and process for conversion related to our project
to upgrade our information technology systems and (ii) review of correspondence with the SEC. 2011 also includes
fees for the audit of our employee benefit plan.
(3) Includes fees for tax return preparation and tax consultations.
(4) Includes fees associated with licenses for accounting research software.
Pre-Approval Policy
The services by Deloitte in 2012 and 2011 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 Deloitte in 2012 and 2011, the audit committee
determined that such services are compatible with the provision of independent audit services. The audit committee discussed
these services with 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.
80
Item 15. Exhibits and Financial Statement Schedules
(a)(1) Financial Statements
Part IV
See “Index to Consolidated Financial Statements and Financial Statement Schedules” set forth on page 86.
(a)(2) Financial Statement Schedules.
See “Index to Consolidated Financial Statements and Financial Statement Schedules” set forth on page 86.
(a)(3) Exhibits
2.1
2.2
2.3
2.4
2.5
2.6
2.7
3.1
3.2
3.3
3.4
3.5
3.6
4.1
4.2
Purchase and Sale Agreement by and between Valero Energy Corporation, Valero Services, Inc., Valero
Unit Investments, LLC, Genesis Energy, LP, Genesis CHOPS I, LLC and Genesis CHOPS II, LLC
dated October 22, 2010 (incorporated by reference to Exhibit 2.2 to Form 10-Q for the quarter ended
September 30, 2010).
Agreement and Plan of Merger by and among Genesis Energy, L.P., Genesis Acquisition, LLC and
Genesis Energy, LLC dated as of December 28, 2010 (incorporated by reference to Exhibit 2.1 to the
Company’s Current Report on Form 8-K dated January 3, 2011, File No. 001-12295).
Purchase and Sale Agreement by and among Florida Marine Transporters, Inc., FMT Heavy Oil
Transportation, LLC, FMT Industries, LLC, JAR Assets, Inc., Pasentine Family Enterprises, LLC, PBC
Management, Inc., and GEL Marine, LLC dated June 24, 2011 (incorporated by reference to Exhibit 2.1
to the Company’s Current Report on Form 8-K dated June 30, 2011, File No. 001-12295).
Purchase and Sale Agreement, dated October 28, 2011, by and between Marathon Oil Company and
Genesis Energy, L.P. regarding interest in Poseidon Oil Pipeline Company, L.L.C. (incorporated by
reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K dated January 9, 2012, File No.
001-12295).
Purchase and Sale Agreement, dated October 28, 2011, by and between Marathon Oil Company and
Genesis Energy, L.P. regarding interest in Odyssey Pipeline L.L.C. (incorporated by reference to
Exhibit 2.2 to the Company’s Current Report on Form 8-K dated January 9, 2012, File No. 001-12295).
Purchase and Sale Agreement, dated October 28, 2011, by and between Marathon Oil Company and
Genesis Energy, L.P. regarding interests in Eugene Island Pipeline System and certain related pipelines
(incorporated by reference to Exhibit 2.3 to the Company’s Current Report on Form 8-K dated
January 9, 2012, File No. 001-12295).
Purchase and Sale Agreement between Denbury Onshore, LLC and Genesis Free State Pipeline, LLC
dated May 30, 2008 (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on
Form 8-K dated June 5, 2008, 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).
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 3, 2011, 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).
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).
Indenture 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).
81
4.3
4.4
4.5
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
Supplemental Indenture, 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, 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, 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, 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, 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, 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, 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, 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, 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)
Tenth Supplemental Indenture, 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.
Eleventh Supplemental Indenture, 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.
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 February 1, 2012 among Genesis Energy L.P., Genesis Energy
Finance Corporation, certain subsidiary guarantors named therein and Deutsche Bank Securities Inc.,
BMO Capital Markets Corp., Citigroup Global Markets Inc., RBC Capital Markets, LLC and Merrill
Lynch, Pierce, Fenner & Smith Incorporated, as representatives of the initial purchasers (incorporated
by reference to the Company’s Current Report in Form 8-K dated February 2, 2012, File No.
001-12295).
Registration Rights Agreement dated February 8, 2013 among Genesis Energy, L.P., Genesis Energy
Finance Corporation, certain subsidiary guarantors named therein and Wells Fargo Securities, LLC, as
representative of the initial purchasers (incorporated by reference to Exhibit 4.2 to the Company’s
Current Report on Form 8-K dated February 11, 2013, File No. 001-12295).
Davison Registration Rights Agreement (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).
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 to Form 8-K dated
November 16, 2007, File No. 001-12295).
82
4.19
4.20
4.21
4.22
4.23
10.1
10.2
10.3
10.4
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 12, 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).
Unitholder Rights Agreement (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 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 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).
Third Amended and Restated Credit Agreement, dated as of July 25, 2012, 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
31, 2012, File No. 001-12295).
Pipeline Financing Lease Agreement by and between Genesis NEJD Pipeline, LLC, as Lessor and
Denbury Onshore, LLC, as Lessee for the North East Jackson Dome Pipeline dated May 30, 2008
(incorporated by reference to Exhibit 10.1 to Form 8-K dated June 5, 2008, File No. 001-12295).
Transportation Services Agreement between Genesis Free State Pipeline, LLC, as Lessor and Denbury
Onshore, LLC dated May 30, 2008 (incorporated by reference to Exhibit 10.2 to Form 8-K dated
June 5, 2008, File No. 001-12295).
Form of Indemnity Agreement, among Genesis Energy, L.P., Genesis Energy, LLC and Quintana
Energy Partners II, L.P. 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).
10.5
+ 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).
10.6
10.7
10.8
+ 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).
+ Genesis Energy, Inc. 2007 Long Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the
Company’s Current Report on Form 8-K dated December 21, 2007, File No. 001-12295).
+ Genesis Energy, L.P. 2010 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the
Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No.
001-12295).
10.9
+ Genesis Energy, LLC 2010 Long-Term Incentive Plan Form of Directors Phantom Unit with DERs
Agreement (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-
Q for the quarter ended March 31, 2010, File No. 001-12295).
10.10
+ 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).
10.11
+ 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).
10.12
+ Form of 2007 Phantom Unit Grant Agreement (3-Year Graded) (incorporated by reference to Exhibit
10.2 to the Company’s Current Report on Form 8-K dated December 21, 2007, File No. 001-12295).
10.13
+ Form of 2007 Phantom Unit Grant Agreement (3-Year Cliff) (incorporated by reference to Exhibit 10.3
to the Company’s Current Report on Form 8-K dated December 21, 2007, File No. 001-12295).
10.14
+ Employment Agreement by and between Genesis Energy, LLC and Grant E. Sims, dated December 31,
2008 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated
January 7, 2009, File No. 001-12295).
10.15
+ Employment Agreement by and between Genesis Energy, LLC and Robert V. Deere, dated
December 31, 2008 (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on
Form 8-K dated January 7, 2009, File No. 001-12295).
83
10.16
+ Employment Agreement by and between Genesis Energy, Inc. and Steve Nathanson dated July 25, 2007
(incorporated by reference to Exhibit 10.30 to the Company’s Current Report on Form 10-K for the
year ended December 31, 2009, File No. 001-12295).
*
10.17
+ Employment Agreement by and between Genesis Energy, LLC and Paul A. Davis, dated March 5, 2012.
10.18
+ Waiver Agreement (Sims), dated February 5, 2010 (incorporated by reference to Exhibit 10.5 to the
Company’s Current Report on Form 8-K dated February 11, 2010, File No. 001-12295).
10.19
+ Waiver Agreement (Deere), dated February 5, 2010 (incorporated by reference to Exhibit 10.5 to the
Company’s Current Report on Form 8-K dated February 11, 2010, File No. 001-12295).
*
*
*
*
*
*
*
*
*
*
*
*
*
*
+
10.20
10.21
10.22
11.1
21.1
23.1
23.2
31.1
31.2
32.1
32.2
Purchase Agreement dated November 12, 2010 relating to 7.875% Senior Notes due 2018 (incorporated
by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated November 18, 2010,
File No. 001-12295).
Purchase Agreement dated February 1, 2012 relating to 7.875% Senior Notes due 2018 (incorporated
by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated February 2, 2012,
File No. 001-12295).
Purchase Agreement dated February February 5, 2013 relating to 5.750% Senior Notes due 2021
(incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated
February 11, 2013, 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 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.
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.
101.DEF
XBRL Definition Linkbase Document.
Filed herewith
A management contract or compensation plan or arrangement.
84
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, 2013
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
(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, 2013
February 26, 2013
February 26, 2013
February 26, 2013
February 26, 2013
February 26, 2013
February 26, 2013
February 26, 2013
February 26, 2013
/s/ GRANT E. SIMS
Grant E. Sims
/s/ ROBERT V. DEERE
Robert V. Deere
/s/ KAREN N. PAPE
Karen N. Pape
/s/ JAMES E. DAVISON
James E. Davison
/s/ JAMES E. DAVISON, JR.
James E. Davison, Jr.
/s/ DONALD L. EVANS
Donald L. Evans
/s/ SHARILYN S. GASAWAY
Sharilyn S. Gasaway
/s/ KENNETH M. JASTROW, II
Kenneth M. Jastrow, II
/s/ CORBIN J. ROBERTSON, III
Corbin J. Robertson, III
*
Genesis Energy, LLC is our general partner.
85
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
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Income (Loss)
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 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 and Distributions
12. Business Segment Information
13. Transactions with Related Parties
14. Supplemental Cash Flow Information
15. Equity-Based Compensation Plans and Employee Benefit Plans
16. Major Customers and Credit Risk
17. Derivatives
18. Fair-Value Measurements
19. Commitments and Contingencies
20. Income Taxes
21. Subsequent Events (Unaudited)
22. Quarterly Financial Data (Unaudited)
23. Condensed Consolidating Financial Information
Financial Statements of Significant Equity Investee – Cameron Highway Oil Pipeline Company (1)
Balance Sheet
Statement of Operations
Statement of Cash Flows
Statement of Partners’ Capital
Notes to Financial Statements
Page
F-1
F-2
F-3
F-4
F-5
F-6
F-7
F-7
F-7
F-11
F-14
F-14
F-15
F-15
F-16
F-17
F-18
F-19
F-21
F-24
F-25
F-25
F-28
F-29
F-31
F-33
F-33
F-35
F-36
F-36
F-47
F-48
F-49
F-50
F-51
86
Financial Statements of Significant Equity Investee – Cameron Highway Oil Pipeline Company
Independent Auditors’ Report
Balance Sheet
Statement of Operations
Statement of Cash Flows
Statement of Partners’ Capital
Notes to Financial Statements
F-57
F-58
F-59
F-60
F-61
F-62
All financial statement schedules have been omitted because they are not applicable or the required information
is presented in the Consolidated Financial Statements or the Notes to the Consolidated Financial Statements.
(1) The financial statements as of and for the years ended December 31, 2012 and 2011 were included for
informational purposes but did not meet the significance test under Regulation S-X Rule 3-09.
87
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, 2012 and 2011, and the related consolidated statements of operations, comprehensive income (loss), partners'
capital, and cash flows for each of the three years in the period ended December 31, 2012. We also have audited the Partnership's
internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Partnership's management
is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment
of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal
Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the
Partnership's internal control over financial reporting 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 and whether effective internal control over financial reporting was maintained in all material
respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures
in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating
the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an
understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and
evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing
such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for
our opinions.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the Partnership's
principal executive and principal financial officers, or persons performing similar functions, and effected by the Partnership's
board of directors, management, and other personnel 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 the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper
management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis.
Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject
to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.
In our opinion, the 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, 2012 and 2011, and the results of their operations and their cash flows
for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted
in the United States of America. Also, in our opinion, the Partnership maintained, in all material respects, effective internal control
over financial reporting as of December 31, 2012, based on the criteria established in Internal Control - Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 26, 2013
F-1
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
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
DEFERRED TAX LIABILITIES
OTHER LONG-TERM LIABILITIES
COMMITMENTS AND CONTINGENCIES (Note 19)
PARTNERS’ CAPITAL:
Common unitholders, 81,202,752 and 71,965,062 units issued and outstanding at
December 31, 2012 and 2011, respectively
TOTAL LIABILITIES AND PARTNERS’ CAPITAL
December 31,
2012
December 31,
2011
$
11,282
$
270,925
87,050
34,777
404,034
723,225
(157,944)
565,281
157,385
549,235
75,065
325,046
33,618
10,817
237,989
101,124
26,174
376,104
541,138
(124,213)
416,925
162,460
326,947
93,356
325,046
30,006
$
2,109,664
$
1,730,844
$
258,053
$
199,357
54,598
312,651
500,000
350,895
13,810
15,813
50,071
249,428
409,300
250,000
12,549
16,929
916,495
792,638
$
2,109,664
$
1,730,844
The accompanying notes are an integral part of these consolidated financial statements.
F-2
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
REVENUES:
Supply and logistics
Refinery services
Pipeline transportation services
Total revenues
COSTS AND EXPENSES:
Supply and logistics product costs
Supply and logistics operating costs
Refinery services operating costs
Pipeline transportation operating costs
General and administrative
Depreciation and amortization
Total costs and expenses
OPERATING INCOME (LOSS)
Equity in earnings of equity investees
Interest expense
Income (loss) before income taxes
Income tax benefit (expense)
NET INCOME (LOSS)
Year Ended December 31,
2012
2011
2010
$
3,797,750
$
2,825,768
$
1,894,612
196,017
76,290
201,711
62,190
151,060
55,652
4,070,057
3,089,669
2,101,324
3,541,647
2,643,687
1,761,161
165,764
123,477
21,894
42,419
61,166
3,956,367
113,690
14,345
(40,921)
87,114
9,205
96,319
—
123,121
126,782
16,964
34,473
62,190
3,007,217
82,452
3,347
(35,767)
50,032
1,217
51,249
—
96,319
$
51,249
$
97,701
88,094
14,777
113,406
53,569
2,128,708
(27,384)
2,355
(22,924)
(47,953)
(2,588)
(50,541)
2,082
(48,459)
1.23
$
0.75
$
0.49
Net loss attributable to noncontrolling interests
NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.
NET INCOME ATTRIBUTABLE TO
GENESIS ENERGY, L.P. PER COMMON UNIT:
Basic and Diluted
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
$
$
Basic and Diluted
78,363
67,938
40,560
The accompanying notes are an integral part of these consolidated financial statements.
F-3
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)
Net income (loss)
Change in fair value of derivatives:
Year Ended December 31,
2012
2011
2010
$
96,319
$
51,249
$
(50,541)
Current period reclassification to earnings—interest rate swaps
Changes in derivative financial instruments—interest rate swaps
Comprehensive income (loss)
Comprehensive loss attributable to noncontrolling interests
Comprehensive income (loss) attributable to Genesis Energy, L.P.
$
—
—
96,319
—
96,319
$
—
—
51,249
—
51,249
$
2,112
(424)
(48,853)
1,223
(47,630)
The accompanying notes are an integral part of these consolidated financial statements.
F-4
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(In thousands)
Partners’ Capital
Number of
Common
Units
Common
Unitholders
General
Partner
Accumulated
Other
Comprehensive
Loss
Non-
controlling
Interests
Total
Capital
39,488
$
585,554
$
11,152
$
(829) $
23,056
$
618,933
17,933
(66,392)
—
(2,082)
(50,541)
December 31, 2009
Comprehensive income:
Net income (loss)
Interest rate swap losses
reclassified to interest
expense
Interest rate swap loss
Cash contributions
Contribution for management
compensation (Note 11)
Cash distributions
Acquisition of noncontrolling
interest in DG Marine (Note 3)
Issuance of units for cash
Issuance of units in exchange for
general partner interest (Note 11)
Issuance of units under LTIP
December 31, 2010
Comprehensive income:
Net income
Cash distributions
Issuance of units for cash, net
(Note 11)
December 31, 2011
Net income
Cash distributions
Issuance of common units for cash,
net (Note 11)
Conversion of waiver units (Note
11)
Other
—
—
—
—
—
—
—
5,175
19,854
98
—
—
—
—
(58,983)
(4,920)
116,347
13,313
20
—
—
2,528
76,923
(11,369)
(100)
—
(12,742)
—
64,615
669,264
—
—
7,350
71,965
—
—
51,249
(112,844)
184,969
792,638
96,319
(142,383)
5,750
169,421
3,476
12
—
500
—
—
—
—
—
—
—
—
—
—
1,035
(206)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1,077
(218)
13
—
(7)
(21,268)
—
(571)
—
—
—
—
—
—
—
—
—
—
—
2,112
(424)
2,541
76,923
(70,359)
(26,288)
116,347
—
20
669,264
51,249
(112,844)
184,969
792,638
96,319
(142,383)
169,421
—
500
December 31, 2012
81,203
$
916,495
$
— $
— $
— $
916,495
The accompanying notes are an integral part of these consolidated financial statements.
F-5
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)
Adjustments to reconcile net income to net cash provided by
operating activities -
Depreciation and amortization
Amortization and write-off of debt issuance costs and premium
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
Non-cash compensation charge
Deferred and other tax (benefits) liabilities
Unrealized losses on derivative transactions
Other, net
Net changes in components of operating assets and liabilities, net
of acquisitions (See Note 14)
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
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, including premium
Debt issuance costs
Issuance of common units for cash, net
General partner contributions
Distributions to common unitholders
Distributions to general partner interest
Acquisition of noncontrolling interest in DG Marine
Other, net
Net cash provided by financing activities
Net increase in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
Year Ended December 31,
2012
2011
2010
$
96,319
$
51,249
$
(50,541)
61,166
4,037
(16,788)
21,804
(14,345)
23,900
7,197
—
(9,222)
86
2,085
13,065
189,304
62,190
2,940
(17,237)
21,852
(3,347)
8,592
(15)
—
(2,075)
1,002
87
(66,931)
58,307
53,569
3,082
(17,651)
21,854
(2,355)
3,623
4,706
76,923
1,337
1,562
(159)
(5,487)
90,463
(146,456)
(27,992)
(12,400)
14,909
(63,749)
(205,576)
773
(1,508)
(401,607)
1,674,400
(1,583,700)
101,000
(7,105)
169,421
—
(142,383)
—
—
1,135
212,768
465
10,817
11,282
$
$
11,436
—
(163,673)
6,424
1,508
(172,297)
777,600
(728,300)
—
(3,018)
184,969
—
(112,844)
—
—
638
119,045
5,055
5,762
10,817
$
2,859
—
(332,462)
1,146
119
(340,738)
691,829
(698,729)
250,000
(14,586)
116,347
2,528
(58,983)
(11,369)
(26,288)
1,140
251,889
1,614
4,148
5,762
The accompanying notes are an integral part of these consolidated financial statements.
F-6
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization
We are a limited partnership focused on the midstream segment of the oil and gas industry in the Gulf Coast region of
the United States, primarily Texas, Louisiana, Arkansas, Mississippi, Alabama, Florida and in the Gulf of Mexico. We have a
diverse portfolio of assets, including pipelines, refinery-related plants, storage tanks and terminals, railcars, rail loading and
unloading facilities, barges 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. We manage our businesses through the following three divisions that constitute our reportable segments:
•
•
•
Pipeline transportation of interstate, intrastate and offshore crude oil, and, to a lesser extent, carbon dioxide (or
“CO2”);
Refinery services involving 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"); and
Supply and logistics services, which include terminaling, blending, storing, marketing, and transporting crude
oil and petroleum products and, on a smaller scale, CO2.
On December 28, 2010, we permanently eliminated our incentive distribution rights (“IDRs”) and converted our 2%
general partner interest into a non-economic interest, which we refer to as our IDR Restructuring. We issued Class A Units,
Class B Units and Waiver Units to the former stakeholders of our general partner in exchange for the elimination of our IDRs.
See Note 11 for additional discussion of our capital structure.
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, 2012 and 2011 and our results of operations, comprehensive income (loss), changes in partners’ capital and cash
flows for the years ended December 31, 2012, 2011 and 2010. All intercompany balances and transactions have been
eliminated. The accompanying Consolidated Financial Statements include Genesis Energy, L.P. and its operating subsidiaries,
Genesis Crude Oil, L.P. and Genesis NEJD Holdings, LLC, and their subsidiaries, and Genesis Energy, LLC. The inclusion of
Genesis Energy, LLC in our Consolidated Financial Statements was effective December 28, 2010 due to our IDR Restructuring
(see Notes 1 and 11).
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 Cameron Highway Oil Pipeline Company (or “CHOPS”), Southeast
Keathley Canyon Pipeline Company, LLC (or “SEKCO”), Poseidon Oil Pipeline Company, L.L.C. (or "Poseidon") and
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.
CHOPS
In November 2010, we acquired a 50% equity interest in CHOPS, a joint venture that owns and operates a crude oil
pipeline system in the Gulf of Mexico. Enterprise Products Partners, L.P. indirectly owns the remaining 50% interest in, and
operates, the joint venture.
SEKCO
In December 2011, we entered into a joint venture forming SEKCO with Enterprise Products Partners, L.P. to
construct a deepwater pipeline serving the Lucius development area in southern Keathley Canyon of the Gulf of Mexico. We
own 50% of SEKCO, and Enterprise Products owns the remaining 50% interest. Enterprise Products serves as construction
manager and will be the operator of the new pipeline. The 149-mile, 18-inch diameter pipeline, will connect the Lucius-truss
spar floating production platform to an existing junction platform at South Marsh Island that is part of the Poseidon pipeline
system. The new pipeline is expected to begin service by mid-2014.
Poseidon
In January 2012, we acquired a 28% equity interest in Poseidon, a joint venture that owns and operates a crude oil
pipeline system in the Gulf of Mexico. Affiliates of Enterprise Products and Shell each own a 36% interest in Poseidon. An
affiliate of Enterprise Products serves as the operator.
F-7
Odyssey
In January 2012, we acquired a 29% equity interest in Odyssey, a joint venture that owns and operates a crude oil
pipeline system in the Gulf of Mexico. An affiliate of Shell owns the remaining 71% interest in Odyssey, and an affiliate of
Shell serves as the operator.
Noncontrolling Interests
During the year ended December 31, 2010, we held less than 100% interests in two consolidated subsidiaries, DG
Marine and Genesis Crude Oil, L.P. During 2010, we acquired the interests in those subsidiaries that we did not already own. In
July 2010, we acquired the 51% interest in DG Marine from TD Marine LLC (“TD Marine”), a related party. In connection
with our IDR Restructuring in December 2010, when we acquired our general partner, we also acquired the 0.01% general
partner’s interest in Genesis Crude Oil, L.P. We reclassified the acquired noncontrolling interests in Genesis Crude Oil, L.P. and
DG Marine to Genesis Energy, L.P. partners’ capital during 2010.
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 the expected life of the rights, expected forfeiture rates of the rights,
volatility of our unit price 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 market. Cost is determined principally under the average cost
method within specific inventory pools.
Fixed Assets
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 15 years for pipelines and related assets, 20
to 25 years for marine vessels, 10 to 20 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 are classified in fixed assets, as they are necessary to ensure efficient and uninterrupted
operations of the gathering businesses. These crude oil 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.
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 future asset retirement obligations relate to future
costs associated with the removal of our oil and CO2 pipelines, barge decommissioning, removal of equipment and facilities
F-8
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
When a direct financing lease is consummated, 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 pipeline transportation services 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.
CO2 Assets
Our CO2 assets include three volumetric production payments, which are amortized on a units-of-production method.
These assets are included in Other Assets in our Consolidated Balance Sheets. See Note 9.
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, 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. The favorable lease and other intangible assets 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 are
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. Fully-amortized debt issuance costs and the related
accumulated amortization are written-off in conjunction with the refinancing or termination of the applicable debt arrangement.
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
2011, we adopted new accounting guidance, which provides the option to make a qualitative evaluation about the likelihood of
goodwill impairment. After performing a qualitative assessment of relevant events and circumstances, 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. 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 stock appreciation rights plan and 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
values of our equity-based awards are re-measured at the end of each reporting period and are recorded as liabilities. The
liability and related compensation cost for our stock appreciation rights are calculated using a Black-Scholes option pricing
model that takes into consideration the expected future value of the rights at their expected exercise dates and management’s
assumptions about expectation of forfeitures prior to vesting. The fair value of our phantom units is equal to the market price of
F-9
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 15 for more information on these plans.
Revenue Recognition
Product Sales—Revenues from the sale of crude oil, petroleum products and CO2 by our supply and logistics segment,
and caustic soda and NaHS by our refinery services segment are recognized when title to the inventory is transferred to the
customer, collectibility 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.
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.
In order to compensate us for bearing the risk of volumetric losses in volumes that occur to crude oil in our pipelines
due to temperature, crude quality and the inherent difficulties of measurement of liquids in a pipeline, our tariffs 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.
Income from direct financing leases is being recognized ratably over the term of the leases and is included in pipeline
revenues.
Cost of Sales and Operating Expenses
Supply and logistics costs and expenses include the cost to acquire the product and the associated costs to transport it
to our terminal facilities 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 and barges, including personnel costs, fuel and maintenance of our equipment.
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 supply and logistics revenues.
The most significant operating costs in our refinery services segment consist of the costs to operate NaHS plants
located at various refineries, caustic soda used in the process of processing the refiner’s sour gas stream, and costs to transport
the NaHS and caustic soda.
Pipeline operating costs consist primarily of power costs to operate pumping equipment, personnel costs to operate the
pipelines, insurance costs and costs associated with maintaining the integrity of our pipelines.
Excise and Sales Taxes
We collect and remit excise and sales taxes to state and federal governmental authorities on its sales of fuels. These
taxes are presented on a net basis, with any differences due to rebates allowed by those governmental entities reflected as a
reduction of product cost in the Consolidated Statements of Operations.
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.
F-10
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. See Note 17.
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.
Net Income Per Common Unit
Basic and diluted net income per common unit is determined by dividing net income attributable to limited partners by
the weighted average number of outstanding common units during the period. Prior to our IDR Restructuring, income available
to common unit holders was allocated 98% to our limited partners and 2% to the general partner, including general partner
allocations for incentive distributions and certain equity-based compensation costs, which our general partner agreed to pay.
Recent and Proposed Accounting Pronouncements
Recently Issued
In July 2012, the FASB issued guidance intended to simplify the impairment test for indefinite-lived intangible assets
other than goodwill by giving entities the option to first assess qualitative factors to determine whether it is more likely than not
that an indefinite-lived intangible asset is impaired. The results of the qualitative assessment would be used as a basis in
determining whether it is necessary to perform the two-step quantitative impairment testing. An entity can choose to perform
the qualitative assessment on none, some or all of its indefinite-lived intangible assets, or may bypass the qualitative
assessment and proceed directly to the quantitative impairment test. This guidance will be effective for annual and interim
impairment tests performed for fiscal years beginning after September 15, 2012, with early adoption permitted in certain
circumstances. We will adopt this guidance on January 1, 2013. Our adoption is not expected to have a material impact on our
financial position, results of operations or cash flows.
Recently Adopted
In December 2011, the Financial Accounting Standards Board (“FASB”) issued guidance requiring new disclosures
for financial instruments and derivative instruments that are eligible for offset in the statement of financial position or subject to
a master netting arrangement. The new guidance is effective for us beginning January 1, 2013 and is not expected to have a
significant impact on our financial position, results of operations or cash flows.
In June 2011, the FASB issued guidance that modified how comprehensive income is presented in an entity’s financial
statements. The guidance issued requires an entity to present the total comprehensive income, the components of net income,
and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two
separate but consecutive statements and eliminates the option to present the components of other comprehensive income as part
of the statement of equity. We adopted the revised financial statement presentation for comprehensive income beginning
January 1, 2012 and it did not have a significant impact on our financial position, results of operations or cash flows. The
guidance pertaining to reclassifying items out of accumulated other comprehensive income has been deferred and will be
effective for us beginning January 1, 2013. The adoption of this guidance is not expected to have a significant impact on our
financial position, results of operations or cash flows.
3. Acquisitions
Interests in Gulf of Mexico Crude Oil Pipeline Systems
On January 3, 2012, we acquired from Marathon Oil Company interests in several Gulf of Mexico crude oil pipeline
systems. The acquired pipeline interests include a 28% interest in Poseidon Oil Pipeline Company, L.L.C. (or “Poseidon”), a
100% interest in Marathon Offshore Pipeline, LLC (subsequently re-named GEL Offshore Pipeline, LLC, or “GOPL”) and a
29% interest in Odyssey Pipeline L.L.C. (or “Odyssey”). GOPL owns a 23% interest in the Eugene Island crude oil pipeline
system and a 100% interest in two smaller offshore pipelines. The purchase price, net of post-closing adjustments, was $205.6
million. We funded the purchase price with cash available under our credit facility. We account for our interests in Poseidon and
F-11
Odyssey under the equity method of accounting. We have recorded the assets acquired and liabilities assumed of GOPL in the
Consolidated Financial Statements at their estimated fair values. Such fair values were developed by management.
The allocation of the purchase price is summarized as follows:
Property and equipment
Equity investees
Asset retirement obligation assumed
Total allocation
$
$
28,456
182,993
(5,873)
205,576
Our Consolidated Financial Statements include the results of the acquired pipeline interests since the effective closing
date of the acquisition in January 2012. The following table presents selected financial information included in our Consolidated
Financial Statements for the year ended December 31, 2012:
Revenues
Equity in earnings of equity investees
Net income
Year Ended December 31,
2012
$
$
$
5,508
13,118
15,112
The table below presents selected unaudited pro forma financial information for the year ended December 31, 2011
incorporating the historical results of the acquired pipeline interests. The unaudited pro forma financial information below has
been prepared as if the acquisition had been completed at the beginning of the prior year and is based upon assumptions deemed
appropriate by us and may not be indicative of actual results.
Pro forma earnings data:
Revenues
Equity in earnings of equity investees
Net income
Basic and diluted earnings per unit:
As reported net income per unit
Pro forma net income per unit
As reported units outstanding
Pro forma units outstanding
Year Ended December 31,
2011
$
$
$
$
$
3,096,693
14,770
58,349
0.75
0.86
67,938
67,938
FMT Black Oil Barge Transportation Business
In August 2011, we completed the acquisition of the black oil barge transportation business of Florida Marine
Transporters, Inc. and its affiliates (“FMT”). The purchase price was $143.5 million (including $2.5 million for fuel inventory
and other costs). The acquired business was comprised of 30 barges (seven of which were initially sub-leased under terms
similar to those of an existing FMT lease, which we subsequently purchased in February 2012 for $30.9 million) and 14 push/
tow boats which transport heavy refined products, primarily serving refineries and storage terminals along the Gulf Coast,
Intracoastal Canal and western river systems of the United States, including the Red, Ouachita and Mississippi Rivers. The
August 2011 acquisition and related transaction costs were funded with a portion of the net proceeds from the July 2011 public
offering of our common units, whereby we raised approximately $185 million in net proceeds of equity capital. The February
2012 vessels purchase was funded with cash available under our credit facility. See Note 11 for additional information regarding
the common unit offering.
F-12
The financial results of the acquired business are included in the supply and logistics segment from the date of
acquisition.
Wyoming Refinery and Pipeline Assets
In November 2011, we acquired a 90% interest in a 3,500 barrel per day refinery located in Converse County,
Wyoming, including 300 miles of abandoned 3” to 6” pipeline. Those assets are located near the emerging Powder River Basin
portion of the Niobrara Shale. The purchase price was $20 million, which included $1.3 million for product inventories. We
funded the acquisition with cash available under our credit facility.
The financial results of the refinery assets are included in the supply and logistics segment and the pipeline assets have
been included in the pipeline transportation segment from the date of acquisition.
CHOPS Investment
In November 2010, we acquired a 50% equity interest in CHOPS, a joint venture that owns and operates a crude oil
pipeline system in the Gulf of Mexico. The purchase price was approximately $330 million plus approximately $2.5 million of
purchase price adjustments.
The funding for this acquisition consisted of $330 million in cash from the issuance of 5,175,000 common units at
$23.58 per common unit and the issuance of $250 million of senior unsecured notes. Total net proceeds from the common units
offering, after deducting underwriting discounts and commissions and estimated offering expenses and including our general
partner’s proportionate capital contribution to maintain its 2% general partner interest, were approximately $119 million.
CHOPS is a 380-mile 24- and 30-inch diameter pipeline constructed in 2004, with capacity to deliver up to 500,000
barrels per day of crude oil from developments in the Gulf of Mexico to major refining markets along the Texas Gulf Coast
located in Port Arthur and Texas City. Enterprise Products Partners, L.P. indirectly owns the remaining 50% interest in, and
operates, the joint venture.
The following table presents selected unaudited pro forma financial information incorporating the historical 50%
equity interest in CHOPS. The effective closing date of our purchase of a 50% equity interest in CHOPS was November 23,
2010. As a result, our Consolidated Statements of Operations for the year ended December 31, 2010 includes our 50% equity
investment in CHOPS for the last five weeks of 2010. The unaudited pro forma financial information has been prepared as if the
acquisition had been completed on the first day of 2010 rather than the actual closing date. The unaudited pro forma financial
information has been prepared based upon assumptions deemed appropriate by us and may not be indicative of actual results.
Pro forma earnings data:
Equity in earnings of equity investees
Net loss attributable to Genesis Energy, L.P.
Basic and diluted earnings per unit:
As reported net income per unit
Pro forma net income per unit
As reported units outstanding
Pro forma units outstanding
Year Ended December 31,
2010
$
$
$
$
15,322
(55,001)
0.49
0.30
40,560
44,969
Acquisition of Remaining “Noncontrolling” Interest in DG Marine
In July 2010, we acquired from TD Marine, a related party, their 51% interest in DG Marine for $25.5 million in cash,
resulting in DG Marine becoming wholly-owned by us. We funded the acquisition with proceeds from our credit agreement,
including (i) paying off DG Marine’s stand-alone credit facility, which had an outstanding principal balance of $44.4 million,
and (ii) settling DG Marine’s interest rate swaps, which resulted in $1.3 million being reclassified from Accumulated Other
Comprehensive Loss (“AOCL”) to interest expense in the third quarter of 2010.
Prior to the acquisition, DG Marine was consolidated as a variable interest entity as certain of our voting rights were not
proportional to our 49% economic interest. As a result of the acquisition, we reclassified the acquired noncontrolling interest in
DG Marine of $21.3 million to Genesis Energy, L.P. partners’ capital. Additionally, we reduced our partners’ capital by $26.3
million for the costs related to the transaction ($25.5 million paid to TD Marine and $0.8 million in direct transaction costs
associated with the acquisition). The net effect of Genesis Energy, L.P. partners’ capital in our Consolidated Balance Sheet for
December 31, 2010 was a decrease of $5 million.
F-13
4. Receivables
Accounts receivable – trade, net consisted of the following:
Accounts receivable - trade
Allowance for doubtful accounts
Accounts receivable - trade, net
December 31,
2012
2011
$
$
273,297
(2,372)
270,925
$
$
239,033
(1,044)
237,989
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
Other
Total inventories
2012
December 31,
2011
2010
$
$
1,044
2,096
(768)
2,372
$
$
1,307
373
(636)
1,044
$
$
1,372
491
(556)
1,307
December 31,
2012
2011
$
58,943
$
15,885
5,636
6,573
13
70,769
11,701
11,312
7,337
5
$
87,050
$
101,124
At December 31, 2012 and 2011, market values of our inventory exceeded recorded costs.
F-14
6. Fixed Assets and Asset Retirement Obligations
Fixed Assets
Fixed assets consisted of the following:
Pipelines and related assets
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
December 31,
2012
2011
$
226,831
$
167,865
87,502
21,170
298,054
15,606
4,964
52,541
16,557
46,233
21,732
262,216
13,140
3,778
14,236
11,938
723,225
(157,944)
565,281
$
541,138
(124,213)
416,925
$
Depreciation expense was $37.4 million, $27.5 million and $22.5 million for the years ended December 31, 2012,
2011, and 2010, respectively.
Asset Retirement Obligations
A reconciliation of our liability for asset retirement obligations is as follows:
December 31, 2010
Liabilities incurred and assumed in the current period
Accretion expense
December 31, 2011
Liabilities incurred and assumed in the current period
Accretion expense
December 31, 2012
7. Net Investment in Direct Financing Leases
$
5,179
349
372
5,900
5,995
800
$
12,695
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.
The following table lists the components of the net investment in direct financing leases:
Total minimum lease payments to be received
Estimated residual values of leased property (unguaranteed)
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
F-15
December 31,
2012
2011
$
320,148
$
341,917
292
1,804
(159,750)
162,494
(5,109)
157,385
$
1,287
1,992
(176,726)
168,470
(6,010)
162,460
$
At December 31, 2012, minimum lease payments to be received for each of the five succeeding fiscal years are $21.3
million for 2013, $21.2 million for 2014 and $20.7 million per year for 2015, 2016 and 2017.
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 the underlying
book value of the capital accounts we acquire. Such excess cost amounts are included within the carrying values of our equity
investees. At December 31, 2012 and 2011, the unamortized excess cost amounts totaled $234 million and $97.8 million,
respectively. We amortize the excess cost as a reduction in equity earnings in a manner similar to depreciation.
The following table presents information included in our Consolidated Financial Statements related to our equity
investees.
Genesis’ share of operating earnings
Amortization of excess purchase price
Net equity in earnings
Distributions received
Year Ended December 31,
2012
2011
2010
$
$
$
24,532
(10,187)
14,345
38,809
$
$
$
7,910
(4,563)
3,347
20,028
$
$
$
3,224
(869)
2,355
6,482
The following tables present the combined balance sheet information for the last two years and income statement data
for the last three years for our equity investees (on a 100% basis):
BALANCE SHEET DATA:
Assets
Current Assets
Fixed Assets, net
Other Assets
Total Assets
Liabilities and equity
Current Liabilities
Other Liabilities
Equity
Total Liabilities and Equity
INCOME STATEMENT DATA:
Revenues
Operating Income
Net Income
December 31,
2012
2011
$
$
$
$
74,906
$
832,525
10,202
917,633
112,321
134,731
670,581
$
$
917,633
$
12,732
441,894
18,000
472,626
5,891
8,536
458,199
472,626
Year Ended December 31,
2012
2011
2010
$
$
$
162,267
80,841
77,975
$
$
$
56,353
16,363
16,322
$
$
$
20,013
5,881
5,843
The 2010 income statement data above includes CHOPS since the date of acquisition. We have included in this filing
on Form 10-K (i) unaudited financial statements for CHOPS as of December 31, 2012 and 2011 and for the years ended
December 31, 2012 and 2011 and (ii) audited financial statements as of December 31, 2010 and the period from November 23,
2010 to December 31, 2010.
F-16
9. Intangible Assets, Goodwill and Other Assets
Intangible Assets
The following table reflects the components of intangible assets being amortized at December 31, 2012 and 2011:
December 31, 2012
December 31, 2011
Weighted
Amortization
Period in Years
Gross
Carrying
Amount
Accumulated
Amortization
Carrying
Value
Gross
Carrying
Amount
Accumulated
Amortization
Carrying
Value
5
6
2
5
15
4
5
$
94,654
$
69,167
$
25,487
$
94,654
$
62,111
$
32,543
38,678
36,469
22,892
36,469
15,786
—
38,678
36,469
19,476
34,105
169,801
128,528
41,273
169,801
115,692
19,202
2,364
54,109
35,430
26,403
9,027
35,430
23,584
11,846
13,260
18,888
67,578
18,932
2,565
18,888
47,856
4,862
10,695
—
19,722
14,070
13,260
18,888
67,578
17,292
2,092
17,048
42,724
2,899
11,168
1,840
24,854
14,393
$ 256,311
$ 181,246
$
75,065
$ 254,671
$ 161,315
$
93,356
Refinery Services:
Customer relationships
Licensing agreements
Supplier relationships
Segment total
Supply & Logistics:
Customer relationships
Intangibles associated with
lease
Trade names
Segment total
Other
Total
The licensing agreements referred to in the table above relate to the agreements we have with refiners to provide
services. The supply and logistics lease relates to a terminal facility in Shreveport, Louisiana.
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 supply and logistics lease and other intangible assets are being
amortized on a straight-line basis. Amortization expense on intangible assets was $19.9 million, $30.9 million and $26.8
million for the years ended December 31, 2012, 2011 and 2010, respectively.
The following table reflects our estimated amortization expense for each of the five subsequent fiscal years:
Refinery Services:
Customer relationships
Licensing agreements
Supply and Logistics:
Customer relationships
Intangibles associated with lease
Other
Total
2013
2014
2015
2016
2017
$
7,116
$
5,597
$
4,405
$
3,471
$
3,163
2,165
474
1,704
2,928
1,660
474
1,685
2,711
1,275
474
1,671
2,510
981
474
1,638
$
14,622
$
12,344
$
10,536
$
9,074
$
2,737
2,324
757
474
1,619
7,911
In the first quarter of 2011, we adjusted the useful lives of our supply and logistics trade names. As a result of this
change in the amortization period of our assets, operating income and net income attributable to us for 2011 decreased $7.7
million, or $0.11 per common unit. At December 31, 2012, our supply and logistics trade names were fully amortized.
F-17
Goodwill
The carrying amount of goodwill by business segment at both December 31, 2012 and 2011 was $301.9 million in
refinery services and $23.1 million in supply and logistics. 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
Other deferred costs and deposits
Other assets, net of amortization
December 31,
2012
2011
$
$
8,320
25,298
33,618
$
$
12,158
17,848
30,006
The CO2 assets are being amortized on a units-of-production method. We recorded amortization of $3.8 million in
2012, $3.7 million in 2011 and $4.3 million in 2010.
10. Debt
At December 31, 2012 and 2011, our obligations under debt arrangements consisted of the following:
Senior secured credit facility
7.875% senior unsecured notes (including unamortized premium of $895 and $0 in 2012 and
2011, respectively)
Total long-term debt
Senior Secured Credit Facility
December 31,
2012
2011
500,000
$
409,300
350,895
850,895
$
250,000
659,300
$
$
In July 2012, we amended and restated our senior secured credit facility with a syndicate of banks to, among other
things, increase the committed amount from $775 million to $1 billion and the accordion feature from $225 million to $300
million, giving us the ability to expand the size of the facility up to an aggregate $1.3 billion for acquisitions or internal growth
projects, subject to lender consent. The inventory financing sublimit tranche was increased from $125 million to $150 million,
and the term of our credit facility was extended to July 25, 2017.
The key terms for rates under our 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 1.75% to 2.75% on Eurodollar borrowings and from 0.75% to 1.75% on alternate base rate borrowings,
depending on our leverage ratio. Our leverage ratio is recalculated quarterly and in connection with each material
acquisition. At December 31, 2012, the applicable margins on our borrowings were 1.0% for alternate base rate
borrowings and 2.0% for Eurodollar rate borrowings.
• Letter of credit fees range from 1.75% to 2.75% based on our leverage ratio as computed under the credit facility.
The rate can fluctuate quarterly. At December 31, 2012, our letter of credit rate was 2.0%.
• We pay a commitment fee on the unused portion of the $1 billion maximum facility amount. The commitment fee on
the unused committed amount will range from 0.375% to 0.50% per annum depending on our leverage ratio (0.375%
at December 31, 2012).
F-18
Our credit facility is secured by liens on a substantial portion of our assets, and by guarantees by all of our restricted
subsidiaries (as defined in the credit facility).
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 5.00 to 1.00 (5.50 to 1.00 in an acquisition period). Our senior secured leverage ratio excludes outstanding debt under
senior unsecured notes and cannot exceed 3.75 to 1.00 (4.25 to 1.00 in an acquisition period). 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 2.75 to 1.00 (3.00 to 1.00 during an acquisition period).
At December 31, 2012, we had $500 million borrowed under our credit facility, with $63.9 million of the borrowed
amount designated as a loan under the inventory sublimit. The credit agreement allows up to $100 million of the capacity to be
used for letters of credit, of which $16.7 million was outstanding at December 31, 2012. 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 July 25, 2017. The total amount available for borrowings under our credit facility at December 31, 2012 was $483.3 million.
7.875% Senior Unsecured Notes Due 2018
In November 2010, we issued $250 million in aggregate principal amount of 7.875% senior unsecured notes due
December 15, 2018. The notes were sold at face value. Interest payments are due on June 15 and December 15 of each year,
beginning June 15, 2011. We used the net proceeds from this offering to finance in part the purchase price and related
transaction costs for the acquisition of a 50% equity interest in CHOPS.
In February 2012, we issued an additional $100 million of aggregate principal amount of senior unsecured notes
under our existing 7.875% senior unsecured notes due 2018 indenture. The notes were issued at 101% of face value at an
effective interest rate of 7.682%. The notes have the same terms and conditions as the notes previously issued under the
indenture. The issuance increased the total aggregate principal amount under the indenture to $350 million. The net proceeds
were used to repay borrowings under our credit facility.
The notes were co-issued by Genesis Energy Finance Corporation (which has no independent assets or operations) and
are fully and unconditionally guaranteed, jointly and severally, by certain of our wholly-owned subsidiaries. We have the right
to redeem the notes at any time after December 15, 2013 at a premium to the face amount of the notes that varies based on the
time remaining to maturity of the notes. Prior to December 15, 2013, we may also redeem up to 35% of the principal amount
for 107.875% of the face amount with the proceeds from an equity offering of our common units.
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, 2012, we were in compliance with the financial covenants contained in our credit facility and
indenture.
11. Partners’ Capital and Distributions
At December 31, 2012, our outstanding equity consisted of 81,162,755 Class A Units, 39,997 Class B Units and
3,476,466 Waiver 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. The Waiver Units are non-voting securities entitled to a minimal preferential quarterly
distribution. At issuance our waiver units were comprised of four classes (designated Class 1, Class 2, Class 3 and Class 4) of
F-19
1,738,000 units each. The waiver units in each class are convertible into Class A common units in the calendar quarter at a 1:1
conversion rate during which each of our common units receives a specified minimum quarterly distribution and our
distribution coverage ratio (after giving effect to the then convertible waiver units) would be at least 1.1 times. The minimum
distribution per common unit required for conversion is $0.43 (Class 1), $0.46 (Class 2), $0.49 (Class 3) and $0.52 (Class 4).
On February 14, 2012, our Class 1 waiver units became convertible because we paid a distribution of $0.44 per
common unit and satisfied the conversion coverage ratio requirement. All Class 1 waiver units were converted into common
units by March 31, 2012.
On August 14, 2012, our Class 2 waiver units became convertible because we paid a distribution of $0.46 per common
unit and satisfied the conversion coverage ratio requirement. All Class 2 waiver units were converted into common units by
September 30, 2012.
At December 31, 2012, our waiver units outstanding were comprised of the Class 3 and Class 4 waiver units.
IDR Restructuring
Prior to our IDR Restructuring our partners’ capital consisted of common units (Class A Units), representing a 98%
aggregate ownership interest in the Partnership and its subsidiaries (after giving effect to the general partner interest), a 2%
general partner interest, and incentive distribution rights (IDRs). Our general partner owned all of our general partner interest,
all of our IDRs, and all of the 0.01% general partner interest in Genesis Crude Oil, L.P. (which was reflected as a
noncontrolling interest in the Consolidated Statements of Partners’ Capital at December 31, 2009.) IDRs provided our general
partner incremental incentive cash distributions when the quarterly cash distribution amount per common unit exceeded certain
target thresholds.
In December 2010, the IDRs held by our general partner were eliminated and the 2% general partner interest in us that
our general partner held was converted into a non-economic general partner interest. In exchange, we issued to the former
owners of our general partner approximately 27,000,000 units, consisting of: (i) approximately 19,960,000 Class A Units,
(ii) approximately 40,000 Class B Units and (iii) approximately 7,000,000 Waiver Units.
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 consists generally of all of our cash receipts less cash
disbursements adjusted for net changes to reserves. We paid distributions in 2013, 2012 and 2011 as follows:
Distribution For
2010
4th Quarter
2011
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
2012
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
Date Paid
Per Unit Amount
Total Amount
February 14, 2011 $
0.4000
May 13, 2011 $
August 12, 2011 $
November 14, 2011 $
February 14, 2012
$
May 15, 2012
August 14, 2012
November 14, 2012
February 14, 2013
$
$
$
$
0.4075
0.4150
0.4275
0.4400
0.4500
0.4600
0.4725
0.4850
$
$
$
$
$
$
$
$
$
25,846
26,343
29,878
30,777
31,677
35,768
36,563
38,375
39,390
F-20
Net Income per Common Unit
The following table sets forth the computation of basic and diluted net income per common unit.
Numerators for basic and diluted net income per common unit:
Net income (loss) attributable to Genesis Energy, L.P.
$
96,319
$
51,249
$
(48,459)
Year Ended December 31,
2012
2011
2010
Less: General partner's incentive distribution paid or to be paid for the
period
Add: Expense allocable to our general partner
Subtotal
Less: General partner 2% ownership
Income available for common unitholders
Denominator for basic and diluted per common unit
Basic and diluted net income per common unit
Equity Issuances and Contributions
—
—
96,319
—
96,319
78,363
1.23
$
$
—
—
51,249
—
51,249
67,938
0.75
$
$
(8,128)
76,923
20,336
(407)
19,929
40,560
0.49
$
$
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.
In March 2012, we issued 5,750,000 Class A common units in a public offering at a price of $30.80 per unit. We
received proceeds, net of underwriting discounts and offering costs, of $169.4 million from the offering. The net proceeds were
used for general corporate purposes, including the repayment of borrowings under our credit facility.
In July 2011, we issued 7,350,000 common units in a public offering. We received proceeds, net of underwriting
discounts and offering costs, of $185 million from the offering. The proceeds were used to fund our acquisition of the black oil
barge transportation business of FMT (see Note 3) and other corporate purposes, including the repayment of borrowings
outstanding under our credit facility.
In November 2010, we issued 5,175,000 common units in a public offering in connection with the acquisition of a
50% equity interest in CHOPS. Our general partner also contributed capital of $2.5 million in November 2010 to maintain its
2% capital account. The new common units issued in 2012, 2011 and 2010 to the public for cash were as follows:
Period
March 2012
Purchaser of
Common Units
Public
Public
July 2011
November 2010 Public
Units
Gross
Unit Price
Issuance Value
GP
Contributions
Costs
Net Proceeds
5,750
7,350
5,175
$
$
$
30.80
26.30
23.58
$
$
$
177,100
193,305
122,027
$
$
$
— $
— $
$
2,490
(7,679) $
(8,336) $
(5,680) $
169,421
184,969
118,837
During 2010, we recorded a non-cash contribution of $76.9 million from our general partner related to incentive
compensation arrangements with our senior executives. As the purpose of these arrangements was to incentivize these
individuals to grow the partnership, the expense was recognized as compensation by us and a capital contribution by our
general partner. This amount relates to arrangements representing an equity interest in our general partner for which our general
partner did not seek reimbursement under our partnership agreement.
12. Business Segment Information
Our operations consist of three operating segments:
•
Pipeline Transportation – interstate, intrastate and offshore crude oil, and to a lesser extent, CO2;
• Refinery Services – processing high sulfur (or “sour”) gas streams as part of refining operations to remove the sulfur
and selling the related by-product, NaHS and;
•
Supply and Logistics – terminaling, blending, storing, marketing, and transporting crude oil and petroleum products
(primarily fuel oil, asphalt, and other heavy refined products) and, on a smaller scale, CO2.
F-21
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 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.
Year Ended December 31, 2012
Segment margin (a)
Capital expenditures (b)
Revenues:
External customers
Intersegment (c)
Total revenues of reportable segments
Year Ended December 31, 2011
Segment margin (a)
Capital expenditures (b)
Revenues:
External customers
Intersegment (c)
Total revenues of reportable segments
Year Ended December 31, 2010
Segment margin (a)
Capital expenditures (b)
Revenues:
External customers
Intersegment (c)
Total revenues of reportable segments
Pipeline
Transportation
Refinery
Services
Supply &
Logistics
Total
$
$
$
$
$
$
$
$
$
$
$
$
96,539
328,710
61,706
14,584
76,290
67,908
14,501
50,391
11,799
62,190
48,305
333,557
45,367
10,285
55,652
$
$
$
$
$
$
$
$
$
$
$
$
72,883
2,692
205,110
(9,093)
196,017
74,618
1,846
210,394
(8,683)
201,711
62,923
1,433
158,456
(7,396)
151,060
$
$
$
$
$
$
$
$
$
$
$
$
92,911
94,896
3,803,241
(5,491)
3,797,750
59,975
170,647
2,828,884
(3,116)
2,825,768
38,336
1,740
1,897,501
(2,889)
1,894,612
$
$
$
$
$
$
$
$
$
$
$
$
262,333
426,298
4,070,057
—
4,070,057
202,501
186,994
3,089,669
—
3,089,669
149,564
336,730
2,101,324
—
2,101,324
Total assets by reportable segment were as follows:
Pipeline transportation
Refinery services
Supply and logistics
Other assets
Total consolidated assets
December 31,
2012
890,652
$
December 31,
2011
594,728
$
December 31,
2010
606,980
$
414,170
750,347
54,495
426,993
658,393
50,730
422,351
432,808
44,596
$ 2,109,664
$ 1,730,844
$ 1,506,735
F-22
(a) A reconciliation of Segment Margin to income (loss) before income taxes for each year presented is as follows:
Segment margin
Corporate general and administrative expenses
Depreciation, amortization and impairment
Interest expense
Distributable cash from equity investees in excess of equity in earnings
Non-cash items not included in segment margin
Cash payments from direct financing leases in excess of earnings
Income (loss) before income taxes
Year Ended December 31,
2012
2011
2010
$ 262,333
(38,372)
(61,166)
(40,921)
(24,464)
(5,280)
(5,016)
87,114
$
$
$
202,501
(31,685)
(62,190)
(35,767)
(16,681)
(1,531)
(4,615)
50,032
$ 149,564
(110,058)
(53,569)
(22,924)
(2,284)
(4,479)
(4,203)
$ (47,953)
(b) Capital expenditures include maintenance and growth capital expenditures, such as fixed asset additions (including
enhancements to existing facilities and construction of internal growth projects) as well as acquisitions of businesses
and interests in equity investees. Capital spending in our pipeline transportation segment included $63.7 million
during the year ended December 31, 2012 representing capital contributions to our SEKCO equity investee to fund our
share of the construction costs for its pipeline. During the same period, capital spending in our pipeline transportation
segment also included $205.6 million for the acquisition of interests in several Gulf of Mexico pipelines. During 2012,
capital spending in our supply and logistics segment also included $30.9 million for the purchase of barge assets.
(c) Intersegment sales were conducted under terms that we believe were no more or less favorable than then-existing
market conditions.
F-23
13. Transactions with Related Parties
Sales, purchases and other transactions with affiliated companies, in the opinion of management, are conducted under
terms no more or less favorable than then-existing market conditions. The transactions with related parties were as follows:
Revenues:
Petroleum products sales to an affiliate of the Quintana Group (2)
Sales of CO2 to Sandhill Group, LLC (3)
Petroleum products sales to Davison family businesses (2)
Pipeline transportation and supply and logistics services provided to
Denbury
Expenses:
Marine operating fuel and expenses provided by an affiliate of the
Quintana Group (2)
Amounts paid to our CEO in connection with the use of his aircraft
Operations, general and administrative services provided by our general
partner (4)
Supply and logistics products and services provided by Denbury
Year Ended December 31,
2012
2011
2010 (1)
$
21,143
$
20,888
$
2,905
1,344
—
6,260
600
—
—
2,481
1,207
—
3,568
316
—
—
3,740
2,706
1,081
3,059
2,443
—
47,035
373
(1)
(2)
(3)
(4)
Affiliates of Denbury Resources, Inc. sold its interests in our general partner in February 2010. Transactions
with Denbury are included in the table as a related party through that date.
The Quintana Group, a private equity fund based in Houston, Texas owned 12% of our Class A common units
and 74% of our Class B common units until October 5, 2012 when the Quintana Group monetized all of its
remaining investment in us. Substantially in connection with that transaction, certain members of the Davison
family, collectively, increased their investment in us to 17.2% of our Class A common units and 76.9% of our
Class B common units. At December 31, 2012, certain members of the Davison family, collectively, owned
17% of our Class A common units and 76.9% of our Class B common units. Solely for financial statement
purposes, we will continue to treat the Davison family and their affiliates as related parties.
We own a 50% interest in Sandhill Group, LLC.
Our general partner became a wholly-owned subsidiary in December 2010.
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, we believe
that the terms of this arrangement are no worse than what we could have obtained in an arms-length transaction.
In July 2010, we acquired from TD Marine its 51% interest in DG Marine. TD Marine is owned by members of the
Davison family.
Amounts due to and from Related Parties
At December 31, 2012, and 2011 Sandhill owed us $0.3 million and $0.2 million, respectively, for purchases of CO2.
At December 31, 2011, an affiliate of the Quintana Group owed us $1.9 million. We owed the affiliate $0.1 million
December 31, 2011.
Financing
We guarantee 50% of Sandhill’s outstanding credit facility loan. At December 31, 2012 and 2011, the total amount of
Sandhill’s obligation to the bank was $1.2 million and $1.7 million, respectively; therefore, our guarantee was for $0.6 million
and $0.9 million for the respective periods.
As discussed in Note 11, our general partner made capital contributions in order to maintain its capital account totaling
$2.5 million in 2010. In 2010, we recorded a capital contribution from our general partner of $76.9 million related to
compensation recognized for our executive management team (see Note 15).
F-24
14. 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
Other current assets
Increase (decrease) in:
Accounts payable
Accrued liabilities
Net changes in components of operating assets and liabilities
Year Ended December 31,
2012
2011
2010
$
$
(34,299) $
14,074
(9,593)
(66,208) $
(46,151)
(3,598)
53,146
(10,263)
13,065
$
33,049
15,977
(66,931) $
(41,648)
(16,870)
(4,036)
47,401
9,666
(5,487)
Payments of interest and commitment fees, net of amounts capitalized, were $41.5 million, $32.9 million and $25.1
million during the years ended December 31, 2012, 2011 and 2010, respectively. We capitalized interest of $3.9 million during
2012 and $0.1 million for both 2011 and 2010.
During the years ended December 31, 2012 and 2011, we received tax refunds, net of amounts paid, of $0.3 million
and $0.1 million, respectively. Cash paid for income taxes, net of amounts refunded, was $2.4 million during 2010.
At December 31, 2012, 2011 and 2010, we had incurred liabilities for fixed and intangible asset additions totaling
$14.1 million, $2 million and $2.6 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” on the Consolidated Statements of
Cash Flows.
15. Equity-Based Compensation Plans and Employee Benefit 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 2012 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 2012, we granted 176,995 phantom units with tandem DERs at a weighted average grant fair value of $31.14
per unit. During 2011, we granted 151,916 phantom units with tandem DERs at a weighted average grant date fair value of
$27.82 per unit. The phantom units granted during 2012 and 2011 were both service-based and performance-based awards. The
service-based awards vest on the third anniversary of the date of grant. Between 50% and 150% of the number of performance-
based phantom units awarded in 2011 and 2012 will vest on the third anniversary of the date of grant, if certain quarterly cash
distribution per common unit targets are achieved in the fourth quarter of 2013 and 2014, 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 2010, we granted 62,927 phantom units that were service-based awards at a weighted average grant date fair
F-25
value of $20.64 per unit. These phantom units will vest on the third anniversary of the date of grant. A summary of our phantom
unit activity for our service-based and performance-based awards is set forth below:
Service-Based Awards
Performance-Based Awards
Number of
Phantom
Units
Average
Grant
Date Fair
Value
Total
Value
Number of
Phantom
Units
Average
Grant
Date Fair
Value
Unvested at December 31, 2011
Granted
Forfeited
Settled
109,762
48,785
$
$
(1,787) $
(30,548) $
23.36
$
30.52
29.04
24.94
Unvested at December 31, 2012
126,212
$
25.66
$
2,564
1,489
(52)
(762)
3,239
102,970
$
28.19
$
128,210
$
(2,679) $
— $
31.38
29.04
—
228,501
$
29.97
$
Total
Value
2,902
4,023
(78)
—
6,847
At December 31, 2012, we estimated the unrecognized compensation cost of our phantom awards to be approximately
$7.5 million to be recognized over a weighted average period of approximately two years. We recorded $6.7 million and $1.9
million of compensation expense for the years ended December 31, 2012 and 2011, respectively. Our liability for these awards
totaled $7.2 million and $2 million at December 31, 2012 and 2011, respectively.
2007 Long Term Incentive Plan
As a result of the sale of our general partner in February 2010, all outstanding phantom units issued pursuant to our
2007 Long Term Incentive Plan vested. As a result of this acceleration of the vesting period, we recorded non-cash
compensation expense of $0.5 million in the first quarter of 2010. In total, 123,857 phantom units vested. This expense is
primarily included in general and administrative expenses. At December 31, 2012 and 2011, there were no awards outstanding
under this plan.
Stock Appreciation Rights Plan
Our Stock Appreciation Rights Plan is administered by the G&C Committee, who determines, in its full discretion,
who shall receive awards under the Plan, the number of rights to award, the grant date of the units and the formula for
allocating rights to the participants and the strike price of the rights awarded. Each right is equivalent to one common unit.
The rights have a term of 10 years from the date of grant. If the right has not been exercised at the end of the ten year
term and the participant has not terminated employment with us, the right will be deemed exercised as of the date of the right’s
expiration and a cash payment will be made as described below.
Upon vesting, the participant may exercise rights and receive a cash payment calculated as the difference between the
average of the closing market price of our common units for the ten days preceding the date of exercise over the strike price of
the right being exercised. If the G&C Committee determines, in its full discretion, that it would cause significant financial harm
to the Partnership to make cash payments to participants who have exercised rights under the Stock Appreciation Rights Plan,
then the G&C Committee may authorize deferral of the cash payments until a later date.
Termination for any reason other than death, disability or normal retirement (as these terms are defined in the Stock
Appreciation Rights Plan) will result in the forfeiture of any non-vested rights. Upon death, disability or normal retirement, all
rights will become fully vested. If a participant is terminated for any reason within one year after the effective date of a change
in control (as defined in the plan) all rights will become fully vested.
The compensation cost associated with our Stock Appreciation Rights plan, which upon exercise will result in the
payment of cash to the employee, is re-measured each reporting period based on the fair value of the rights. Under accounting
guidance, the liability is calculated using a fair value method that takes into consideration the expected future value of the
rights at their expected exercise dates.
The liability amount accrued on the balance sheet is adjusted to the fair value of the outstanding awards at each
balance sheet date with the adjustment reflected in the Consolidated Statement of Operations. The fair value is adjusted for
expected forfeitures of rights (due to terminations before vesting, or expirations after vesting).
The estimates that we make each period to determine the fair value of these rights include the following assumptions:
F-26
Expected life of rights (in years)
Risk-free interest rate
Expected unit price volatility
Expected future distribution yield
Assumptions Used for Fair Value of Rights
December 31, 2012
Less than 1
0.00% - 0.07%
39.3%
5.00%
December 31, 2011
-
3.41
0.00
0.00% - 0.58%
40.6%
6.00%
December 31, 2010
-
0.00
4.41
0.12% - 1.73%
41.9%
6.00%
The following table reflects rights activity under our Stock Appreciation Rights Plan as of January 1, 2012, and
changes during the year ended December 31, 2012:
Outstanding at December 31, 2011
Exercised during 2012
Forfeited or expired during 2012
Outstanding at December 31, 2012
Exercisable at December 31, 2012
Stock
Appreciation
Rights
Weighted
Average
Strike Price
662,484
$
(264,060) $
(13,618) $
$
384,806
351,051
$
17.97
18.85
18.91
17.25
17.66
Weighted
Average
Contractual
Remaining
Term (Yrs)
Aggregate
Intrinsic
Value
4.83
4.71
$
$
7,099
6,332
The total intrinsic value of rights exercised during 2012, 2011 and 2010 was $3.3 million, $2.4 million and $1.3
million, respectively, which was paid in cash to the participants.
At December 31, 2012, there was less than $0.1 million of total unrecognized compensation cost related to rights that
we expect will vest under the Stock Appreciation Rights Plan. This amount was calculated as the fair value at December 31,
2012 multiplied by those rights for which compensation cost has not been recognized, adjusted for estimated forfeitures. This
unrecognized cost will be recalculated at each balance sheet date until the rights are exercised, forfeited or expire. For the
awards outstanding at December 31, 2012, the remaining cost will be recognized in the first quarter of 2013.
We recorded compensation expense related to our stock appreciation rights of $4.5 million, $0.6 million and $5.2
million in 2012, 2011 and 2010, respectively.
Equity-Based Compensation Plan Expense
Equity-based compensation expense during the three years ended December 31, 2012 was as follows:
Consolidated Statement of Operations
Supply and logistics operating costs
Refinery services operating costs
Pipeline operating costs
General and administrative expenses
Total
Series B Units
Expense Related to Equity-Based
Compensation Plans
2012
2011
2010
$ 3,038
$
1,427
247
6,467
181
226
135
$ 2,611
833
575
2,013
2,098
$ 11,179
$ 2,555
$ 6,117
Pursuant to restricted unit agreements entered into with Genesis Energy, LLC, our general partner, on February 5,
2010, certain members of our management team received an aggregate of 767 Series B units in our general partner. These
awards provided for the conversion of the Series B units into Series A units in our general partner on the seventh anniversary of
the issuance date of the awards or at the time of certain events including a change in control of our general partner. As a result
of our IDR Restructuring on December 28, 2010, the Series B units converted into Series A units. The Series A units were then
exchanged for a total of 2,364,279 Class A Units and 827,484 Waiver Units. See Note 11 for a discussion of our IDR
Restructuring and our equity securities.
F-27
Although the Series B Units represented an equity interest in our general partner and our general partner did not seek
reimbursement under our partnership agreement for the value of these compensation arrangements, we recorded non-cash
expense for the estimated fair value of the awards. For the year ended December 31, 2010, we recorded non-cash expense of
$79.1 million related to these Series B awards with an offsetting entry to the capital account of our general partner. As the
awards are fully-vested, no further compensation expense for these awards remains to be recorded.
Class B Membership Interests
As part of finalizing the compensation arrangements for our senior executives on December 31, 2008, our general
partner awarded them an equity interest in our general partner as long-term incentive compensation. The Class B membership
interests awarded to our senior executives were accounted for as liability awards under the guidance for equity-based
compensation.
All of the Class B membership interests in our general partner held by our management team at December 31, 2009
were either (i) converted into Series A units in our general partner or (ii) redeemed by our general partner on February 5,
2010. In total, the value of the Series A units issued and cash payments made by our general partner to settle its obligations
under the Class B membership interests and related deferred compensation totaled $14.9 million. This value, when combined
with amounts previously paid to our management team during 2009 related to the Class B membership interests, resulted in
total compensation expense of $15.4 million. Upon settlement by our general partner of these arrangements with our
management team, we recorded a reduction in expense of $2.1 million in the first quarter of 2010.
Bonus Program
Bonuses under our bonus plan are paid at the discretion of the G&C Committee to our employees and executive
officers. In 2012, the G&C Committee based bonus amounts primarily on the amount of cash we generated for distributions to
our unitholders, measured on a calendar-year basis. Two metrics were used to determine the general bonus pool – the level of
Available Cash before Reserves (before subtracting bonus expense and related employer tax burdens) that we generated and our
company-wide safety record improvement which included a targeted reduction in our company-wide incident injury rate. The
level of Available Cash before Reserves generated for the year as a percentage of a target set by the G&C Committee is
weighted 90% and the achieved level of the targeted improvement in our safety record is weighted 10%. The sum of the
weighted percentage achievement of these targets is multiplied by the eligible compensation and the target percentages
established by the G&C Committee for the various levels of our employees to determine the maximum general bonus pool. At
December 31, 2012, we accrued $7.9 million for estimated bonuses to be paid in March 2013. For 2011 and 2010, we paid
bonuses totaling $6.6 million and $5.2 million, respectively, to our executive officers and employees.
Employee Benefit Plans
In order to encourage long-term savings and to provide additional funds for retirement to its employees, we sponsor a
tax qualified profit-sharing and retirement savings plan. Under this plan, our matching contribution is calculated as an equal
match of the first 6% of each employee’s annual pretax contribution. Our profit-sharing plan targets a 3% contribution of each
eligible employee’s total compensation (subject to IRS limitations). The expenses included in the Consolidated Statements of
Operations for costs relating to this plan were $3.4 million, $2.6 million and $2.7 million for the years ended December 31,
2012, 2011 and 2010, respectively.
We also provided certain health care and survivor benefits for our active employees. Our health care benefit programs
are self-insured, with a catastrophic insurance policy to limit our costs. We plan to continue self-insuring these plans in the
future. The expenses included in the Consolidated Statements of Operations for these benefits were $8.8 million, $8.1 million
and $6.5 million in 2012, 2011 and 2010, respectively.
16. Major Customers and Credit Risk
Due to the nature of our supply and logistics operations, a disproportionate percentage of our trade receivables
constitute obligations of 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 integrated and large independent energy
companies with stable payment experience. The credit risk related to contracts which are traded on the NYMEX is limited due
to daily margin requirements and other NYMEX requirements.
F-28
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 2012, 2011 and 2010 our largest customer was Shell Oil Company, which accounted for 14%, 16% and 13% of
total revenues respectively. The revenues from Shell Oil Company in all three years relate primarily to our supply and logistics
operations.
17. 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.
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, 2012, we had the following outstanding derivative commodity futures and options contracts that
were entered into to economically hedge inventory or fixed price purchase commitments. We had no outstanding derivative
contracts that were designated as hedges under accounting rules.
Not qualifying or not designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 bbls)
Weighted average contract price per bbl
Crude oil LLS/WTI swap:
Contract volumes (1,000 bbls)
Weighted average contract price per bbl
Heating oil futures:
Contract volumes (1,000 bbls)
Weighted average contract price per gal
# 6 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
F-29
Sell (Short)
Contracts
Buy (Long)
Contracts
316
88.35
$
100
17.25
$
62
3.02
$
765
92.37
$
325
1.61
$
$
$
$
$
$
199
89.66
—
—
—
—
160
93.06
85
0.55
Interest Rate Derivatives
During 2010, our DG Marine subsidiary utilized swap contracts with financial institutions to hedge interest payments
for its outstanding debt. DG Marine expected these interest rate swap contracts to be highly effective in limiting its exposure to
fluctuations in market interest rates; therefore, we designated these swap contracts as cash flow hedges under accounting
guidance. The effective portion of the derivative represented the change in fair value of the hedge that offset the change in cash
flows of the hedged item. The effective portion of the gain or loss in the fair value of these swap contracts was reported as a
component of Accumulated Other Comprehensive Loss (AOCL) and was reclassified into future earnings contemporaneously,
as interest expense associated with the underlying debt was recorded. In the third quarter of 2010, we settled the DG Marine
interest rate swaps in connection with our acquisition of the 51% interest of DG Marine that we did not own (see Note 3).
Financial Statement Impacts
The following table summarizes the accounting treatment and classification of our derivative instruments on our
Consolidated Financial Statements.
Derivative Instrument
Designated as hedges under accounting guidance:
Hedged Risk
Impact of Unrealized Gains and Losses
Consolidated
Balance Sheets
Consolidated
Statements of Operations
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
Excess, if any, over effective portion of
hedge is recorded in Supply and
logistics costs - product costs Effective
portion is offset in cost of sales against
change in value of inventory being
hedged
Interest rate swaps
(cash flow hedge)
(through July 2010)
Changes in interest
Not applicable
rates
Expect hedge to fully offset hedged risk;
no ineffectiveness recorded. Effective
portion is recorded to AOCL and
ultimately reclassified to Interest
expense
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
Entire amount of change in fair value of
derivative is recorded in Supply and
logistics costs - product costs
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-30
The following tables reflect the estimated fair value gain (loss) position of our derivatives at December 31, 2012 and
2011:
Fair Value of Derivative Assets and Liabilities
Asset Derivatives:
Commodity derivatives—futures and call options:
Undesignated hedges
Total asset derivatives
Liability Derivatives:
Commodity derivatives—futures and call options:
Undesignated hedges
Total liability derivatives
Consolidated
Balance Sheets
Location
Current Assets -
Other
Current Assets -
Other
Fair Value
December 31, 2012
December 31, 2011
758
758
(1)
(3,357)
(3,357)
$
$
306
306
(2,820) (1)
(2,820)
$
$
(1) These derivative liabilities have been funded with margin deposits recorded in our Consolidated Balance Sheets under
Current Assets - Other.
Effect on Operating Results
Amount of Loss Recognized in Income
Supply & Logistics Product Costs
Interest Expense Reclassified from
AOCL
Other Comprehensive Loss
Effective Portion
Year Ended
December 31,
Year Ended
December 31,
Year Ended
December 31,
2012
2011
2010
2012
2011
2010
2012
2011
2010
$
— $
(173)
(1)
$
307
(1)
$
— $
— $
— $
— $
— $
—
(2,388)
(17,419)
(2,388)
(17,592)
—
—
(4)
303
—
303
—
—
—
—
—
—
—
—
(2,112)
—
—
—
—
—
—
$
— $
— $ (2,112) $
— $
— $
—
—
(424)
(424)
Total derivatives
$ (2,388) $ (17,592)
$
(1) Represents the amount of loss recognized in income for derivatives related to the fair value hedge of inventory. The
amount excludes the gain on the hedged inventory under the fair value hedge of $0.8 million and $1 million for the
years ended 2011 and 2010, respectively.
We have no derivative contracts with credit contingent features.
18. 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
F-31
Commodity derivatives—
futures and call options:
Contracts designated as
hedges under accounting
guidance
Contracts not considered
hedges under accounting
guidance
Total commodity derivatives
Interest rate swaps designated
as cash flow hedges under
accounting guidance
(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, 2012 and 2011.
Recurring Fair Value Measures
Commodity derivatives:
Assets
Liabilities
December 31, 2012
December 31, 2011
Level 1
Level 2
Level 3
Level 1
Level 2
Level 3
$
$
758
$
(3,357) $
— $
— $
— $
— $
306
$
(2,820) $
— $
— $
—
—
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.
During 2010, we settled our interest rate swaps, which were classified as Level 3 fair value measurements. The
following table provides a reconciliation of changes in fair value of our interest rate swaps during 2010.
See Note 17 for additional information on our derivative instruments.
Balance at beginning of period
Realized and unrealized gains (losses)
Reclassified into interest expense for settled contracts
Included in other comprehensive income (loss)
Balance at end of period
Nonfinancial Assets and Liabilities
Year Ended
December 31,
2010
(1,688)
2,112
(424)
—
$
$
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, 2012 our
senior unsecured notes had a carrying value of $350.9 million and a fair value of $373.2 million, compared to $250 million and
$253.1 million, respectively at December 31, 2011. The fair value of the senior unsecured notes is determined based on trade
information in the financial markets of our public debt and is considered a Level 2 fair value measurement.
F-32
19. 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, 2012, were as
follows (in thousands):
2013
2014
2015
2016
2017
2018 and thereafter
Office
Space
Transportation
Equipment
Terminals and
Tanks
Total
$
1,006
$
12,273
$
6,006
$
1,219
1,207
1,173
1,029
5,169
13,965
12,166
8,488
6,236
13,431
6,129
2,571
2,374
2,374
24,545
19,285
21,313
15,944
12,035
9,639
43,145
Total minimum lease obligations
$
10,803
$
66,559
$
43,999
$
121,361
Total operating lease expense was as follows (in thousands):
Year Ended December 31, 2012
Year Ended December 31, 2011
Year Ended December 31, 2010
$
$
$
21,624
18,331
15,692
In connection with our 50% interest in SEKCO, we have committed to share in the required funding with Enterprise
Products Partners, L.P. to construct a deepwater pipeline serving the Lucius development area in southern Keathley Canyon of
the Gulf of Mexico.
We are subject to various environmental laws and regulations. Policies and procedures are in place to monitor
compliance and to detect and address any releases of crude oil from our pipelines or other facilities; however no assurance can
be made that such environmental releases may not substantially affect our business.
Other Matters
Our facilities and operations may experience damage as a result of an accident or natural disaster. These hazards can
cause personal injury or loss of life, severe damage to and destruction of property and equipment, pollution or environmental
damage and suspension of operations. We maintain insurance that we consider adequate to cover our operations and properties,
in amounts we consider reasonable. Our insurance does not cover every potential risk associated with operating our facilities,
including the potential loss of significant revenues. The occurrence of a significant event that is not fully-insured could
materially and adversely affect our results of operations. We believe we are adequately insured for public liability and property
damage to others and that our coverage is similar to other companies with operations similar to ours. No assurance can be made
that we will be able to maintain adequate insurance in the future at premium rates that we consider reasonable.
We are subject to lawsuits in the normal course of business and examination by tax and other regulatory authorities.
We do not expect such matters presently pending to have a material effect on our financial position, results of operations or
cash flows.
20. 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.
F-33
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.
Our income tax (benefit) expense is as follows:
Current:
Federal
State
Total current income tax (benefit) expense
Deferred:
Federal
State
Total deferred income tax (benefit) expense
Total income tax (benefit) expense
Year Ended December 31,
2012
2011
2010
$
$
$
$
$
(8,463) $
275
(8,188) $
(1,035) $
18
(1,017) $
(9,205) $
2,147
676
2,823
$
$
(3,714) $
(326)
(4,040) $
(1,217) $
1,664
1,494
3,158
(573)
3
(570)
2,588
Deferred income taxes relate to temporary differences based on tax laws and statutory rates in effect at the balance
sheet date. Deferred tax assets and liabilities consist of the following:
December 31,
2012
2011
Deferred tax assets:
Current:
Other current assets
Other
Total current deferred tax asset
Net operating loss carryforwards
Total long-term deferred tax asset
Valuation allowances
Total deferred tax assets
Deferred tax liabilities:
Current:
Other
Long-term:
Fixed assets
Intangible assets
Total long-term liability
Total deferred tax liabilities
Total net deferred tax liability
$
348
$
8
356
5,206
5,206
(543)
5,019
$
351
8
359
2,363
2,363
(428)
2,294
(658) $
(211)
(4,914)
(8,896)
(13,810)
(14,468) $
(9,449) $
(5,744)
(6,805)
(12,549)
(12,760)
(10,466)
$
$
$
$
We record a valuation allowance when it is more likely than not that some portion or all of the deferred tax assets will
not be realized. The ultimate realization of the deferred tax assets depends on the ability to generate sufficient taxable income
of the appropriate character in the future and in the appropriate taxing jurisdictions.
F-34
Our income tax (benefit) expense varies from the amount that would result from applying the federal statutory income
tax rate to income (loss) before income taxes as follows:
Income (loss) before income taxes
Partnership (income) loss not subject to tax
Loss subject to income taxes
Tax benefit at federal statutory rate
State income taxes, net of federal benefit
Effects of unrecognized tax positions, federal and state
Return to provision, federal and state
Other
Income tax (benefit) expense
Year Ended December 31,
2012
2011
2010
$
$
$
$
$
87,114
(89,797)
(2,683) $
(939) $
460
(8,205)
(166)
(355)
(9,205) $
$
50,032
(60,304)
(10,272) $
(3,595) $
123
1,964
72
219
(1,217) $
(47,953)
47,357
(596)
(209)
583
1,909
257
48
2,588
Effective tax rate on income (loss) before income taxes
(1)
(1)
(1)
(1) Income tax expense is related to taxable income generated by our corporate subsidiaries and Texas Margin Tax. Due to
the income tax benefit in 2012 and 2011 and the loss before income taxes in 2010, the effective tax rate as a
percentage of our total income (loss) before income taxes is not meaningful.
A reconciliation of the beginning and ending amount of our unrecognized tax positions was as follows:
Balance at January 1, 2010
Additions based on tax positions related to current year
Balance as of December 31, 2010
Additions based on tax positions related to current year
Balance as of December 31, 2011
Reversal of uncertain tax positions due to tax audit settlements
Balance as of December 31, 2012
$
$
4,332
1,909
6,241
1,964
8,205
(8,205)
—
In 2012, we reversed $8.2 million of uncertain tax positions and recognized an income tax benefit in the Consolidated
Statements of Operations as a result of tax audit settlements and the expiration of statutes of limitations. These uncertain tax
positions were included in Other Long-Term Liabilities in our Consolidated Balance Sheet at December 31, 2011.
21. Subsequent Events (Unaudited)
Senior Unsecured Notes Issuance
On February 8, 2013, we issued an additional $350 million in aggregate principal amount of 5.75% senior unsecured
notes. The notes mature on February 15, 2021. The net proceeds were used to repay borrowings under our credit agreement and
general partnership purposes.
F-35
22. Quarterly Financial Data (Unaudited)
The table below summarizes our unaudited quarterly financial data for 2012 and 2011.
First
Second
Third
Fourth
2012 Quarters
Total
Year
Revenues
$
960,717
$ 1,013,431
$ 1,041,837
$ 1,054,072
$ 4,070,057
Operating income
$
Net income attributable to Genesis Energy, L.P. $
Net income per common unit—basic and
diluted
Cash distributions per common unit (1)
Revenues
$
$
$
Operating income
$
Net income attributable to Genesis Energy, L.P. $
Net income per common unit—basic and
26,730
19,604
0.27
0.4400
First
689,798
12,832
7,030
diluted
Cash distributions per common unit (1)
$
$
0.11
0.4000
$
$
$
$
$
$
$
$
$
27,669
18,584
0.23
0.4500
$
$
$
$
29,118
31,194
0.39
0.4600
2011 Quarters
Second
Third
762,790
25,931
17,358
0.27
0.4075
$
$
$
$
$
830,200
28,632
19,088
0.27
0.4150
$
$
$
$
$
$
$
$
$
30,173
26,937
0.34
0.4725
$
$
$
$
Fourth
113,690
96,319
1.23
1.8225
Total
Year
806,881
$ 3,089,669
15,057
7,773
0.10
0.4275
$
$
$
$
82,452
51,249
0.75
1.6500
(1) Represents cash distributions declared and paid in the applicable period.
Immaterial Restatement
Annual amounts for revenues and cost of sales for 2012 include corrections to previously reported quarterly amounts
for each of the first three quarters of 2012. These corrections were made to present certain sales transactions on a gross basis
that previously had been recorded on a net basis. Amounts as reported and as adjusted are reflected in the table below. The
corrections had no effect on previously reported operating income, net income or Segment Margin. There was no impact on
2011 results.
AS REPORTED:
REVENUES:
Supply and logistics
Total revenues
COSTS AND EXPENSES:
Supply and logistics product costs
Total costs and expenses
OPERATING INCOME
AS ADJUSTED:
REVENUES:
Supply and logistics
Total revenues
COSTS AND EXPENSES:
Supply and logistics product costs
Total costs and expenses
OPERATING INCOME
2012 Quarters
First
Second
Third
$
$
$
$
$
$
$
$
$
$
865,489
932,943
808,095
906,213
26,730
$
$
$
$
$
857,127
922,668
792,413
894,999
27,669
$
$
$
$
$
875,193
942,334
811,896
913,216
29,118
2012 Quarters
First
Second
Third
893,263
$
947,890
$
974,696
960,717
$ 1,013,431
$ 1,041,837
835,869
933,987
26,730
$
$
$
883,176
$
911,399
985,762
$ 1,012,719
27,669
$
29,118
F-36
23. Condensed Consolidating Financial Information
Our $350 million 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
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.
As a result of our IDR Restructuring in December 2010 (see Note 11), each subsidiary guarantor and the subsidiary co-
issuer are 100% owned, directly or indirectly, by Genesis Energy, L.P.
The following is condensed consolidating financial information for Genesis Energy, L.P. and subsidiary guarantors:
Condensed Consolidating Balance Sheet
December 31, 2012
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
$
10
$
— $
11,214
$
58
$
— $
11,282
Other current assets
Total current assets
Fixed Assets, at cost
Less: Accumulated depreciation
Net fixed assets
Goodwill
Other assets, net
Equity investees and other investments
Investments in subsidiaries
Total assets
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Senior secured credit facilities
Senior unsecured notes
Deferred tax liabilities
Other liabilities
Total liabilities
Partners’ capital
$
$
745,589
745,599
—
—
—
—
17,737
—
1,006,415
—
—
—
—
—
—
—
—
—
367,837
379,051
617,519
(144,882)
472,637
325,046
254,423
549,235
102,707
41,533
41,591
105,706
(13,062)
92,644
—
(762,207)
(762,207)
—
—
—
—
157,604
(163,696)
—
—
—
(1,109,122)
392,752
404,034
723,225
(157,944)
565,281
325,046
266,068
549,235
—
1,769,751
$
— $
2,083,099
$
291,839
$
(2,035,025) $
2,109,664
2,361
$
— $
1,048,937
$
23,567
$
(762,214) $
312,651
500,000
350,895
—
—
853,256
916,495
—
—
—
—
—
—
—
—
13,810
13,044
1,075,791
1,007,308
—
—
—
166,282
189,849
101,990
—
—
—
(163,513)
500,000
350,895
13,810
15,813
(925,727)
1,193,169
(1,109,298)
916,495
Total liabilities and partners’ capital
$
1,769,751
$
— $
2,083,099
$
291,839
$
(2,035,025) $
2,109,664
F-37
Condensed Consolidating Balance Sheet
December 31, 2011
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
$
3
$
— $
9,182
$
1,632
$
— $
10,817
Other current assets
Total current assets
Fixed Assets, at cost
Less: Accumulated depreciation
Net fixed assets
Goodwill
Other assets, net
Equity investees and other investments
Investments in subsidiaries
Total assets
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Senior secured credit facilities
Senior unsecured notes
Deferred tax liabilities
Other liabilities
Total liabilities
Partners capital
$
$
597,966
597,969
—
—
—
—
14,773
—
841,725
—
—
—
—
—
—
—
—
—
341,131
350,313
444,262
(114,655)
329,607
325,046
276,450
326,947
96,303
31,897
33,529
96,876
(9,558)
87,318
—
(605,707)
(605,707)
—
—
—
—
162,373
(167,774)
—
—
—
(938,028)
365,287
376,104
541,138
(124,213)
416,925
325,046
285,822
326,947
—
1,454,467
$
— $
1,704,666
$
283,220
$
(1,711,509) $
1,730,844
2,529
$
— $
835,013
$
17,562
$
(605,676) $
249,428
409,300
250,000
—
—
661,829
792,638
—
—
—
—
—
—
—
—
12,549
14,673
862,235
842,431
—
—
—
169,842
187,404
95,816
—
—
—
(167,586)
(773,262)
(938,247)
409,300
250,000
12,549
16,929
938,206
792,638
Total liabilities and partners’ capital
$
1,454,467
$
— $
1,704,666
$
283,220
$
(1,711,509) $
1,730,844
F-38
Condensed Consolidating Statement of Operations
Year Ended December 31, 2012
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
$
— $
— $ 3,772,400
$
135,013
$
(109,663) $ 3,797,750
—
—
—
—
—
—
—
—
—
—
—
137,151
(40,832)
96,319
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
192,083
50,106
19,999
26,184
(16,065)
—
196,017
76,290
4,014,589
181,196
(125,728)
4,070,057
3,696,792
120,095
21,000
42,297
57,402
3,937,586
77,003
14,345
20,547
16,502
128,397
8,903
120,280
19,489
894
122
3,764
144,549
36,647
—
—
(109,661)
3,707,411
(16,107)
123,477
—
—
—
21,894
42,419
61,166
(125,768)
3,956,367
40
—
(157,698)
113,690
14,345
—
(16,591)
—
(40,921)
20,056
(157,658)
302
—
87,114
9,205
$
96,319
$
— $
137,300
$
20,358
$
(157,658) $
96,319
REVENUES:
Supply and logistics
Refinery services
Pipeline transportation services
Total revenues
COSTS AND EXPENSES:
Supply and logistics costs
Refinery services operating costs
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
Income before income taxes
Income tax benefit
NET INCOME
F-39
Condensed Consolidating Statement of Operations
Year Ended December 31, 2011
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
$
— $
— $ 2,824,524
$
14,883
$
(13,639) $ 2,825,768
—
—
—
—
—
—
—
—
—
—
—
86,958
(35,709)
51,249
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
197,928
36,281
3,058,733
2,766,084
122,724
16,174
34,473
59,439
2,998,894
59,839
3,347
5,333
16,933
85,452
1,555
20,548
25,909
61,340
14,363
20,968
790
—
2,751
38,872
22,468
—
—
(16,765)
—
201,711
62,190
(30,404)
3,089,669
(13,639)
2,766,808
(16,910)
126,782
—
—
—
16,964
34,473
62,190
(30,549)
3,007,217
145
—
(92,291)
82,452
3,347
—
(16,991)
5,477
(338)
—
(35,767)
(92,146)
—
50,032
1,217
$
51,249
$
— $
87,007
$
5,139
$
(92,146) $
51,249
REVENUES:
Supply and logistics
Refinery services
Pipeline transportation services
Total revenues
COSTS AND EXPENSES:
Supply and logistics costs
Refinery services operating costs
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
Income before income taxes
Income tax benefit (expense)
NET INCOME
F-40
Condensed Consolidating Statement of Operations
Year Ended December 31, 2010
REVENUES:
Supply and logistics
Refinery services
Pipeline transportation services
Total revenues
COSTS AND EXPENSES:
Supply and logistics costs
Refinery services operating costs
Pipeline transportation operating costs
General and administrative
Depreciation and amortization
Total costs and expenses
OPERATING (LOSS) INCOME
Equity in earnings of equity investees
Equity in (losses) earnings of subsidiaries
Interest (expense) income, net
(Loss) income before income taxes
Income tax expense
NET (LOSS) INCOME
Net loss attributable to noncontrolling
interests
NET (LOSS) INCOME ATTRIBUTABLE
TO GENESIS ENERGY, L.P.
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
$
— $
— $ 1,894,612
$
— $
— $ 1,894,612
—
—
—
—
—
—
—
—
—
—
—
(34,988)
(13,471)
(48,459)
—
(48,459)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
146,570
29,497
2,070,679
1,858,862
85,250
14,301
113,406
50,973
2,122,792
(52,113)
2,355
7,401
7,884
(34,473)
(2,175)
(36,648)
2,083
14,544
26,155
40,699
—
12,672
476
—
2,596
15,744
24,955
—
—
(17,337)
7,618
(413)
7,205
—
(10,054)
—
151,060
55,652
(10,054)
2,101,324
—
1,858,862
(9,828)
—
—
—
88,094
14,777
113,406
53,569
(9,828)
2,128,708
(226)
—
27,587
—
27,361
—
27,361
(27,384)
2,355
—
(22,924)
(47,953)
(2,588)
(50,541)
(1)
2,082
$
(48,459) $
— $
(34,565) $
7,205
$
27,360
$
(48,459)
F-41
Condensed Consolidating Statement of Comprehensive Income
Year Ended December 31, 2012
Net income
$
96,319
$
— $
137,300
$
20,358
$
(157,658) $
96,319
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
Change in fair value of derivatives:
Current period reclassification in earnings -
interest rate swaps
Changes in derivative financial instruments -
interest rate swaps
Comprehensive income
Comprehensive loss attributable to noncontrolling
interests
Comprehensive income attributable to Genesis
Energy, L.P.
—
—
96,319
—
—
—
—
—
—
—
—
—
—
—
—
—
137,300
20,358
(157,658)
96,319
—
—
—
—
$
96,319
$
— $
137,300
$
20,358
$
(157,658) $
96,319
Condensed Consolidating Statement of Comprehensive Income
Year Ended December 31, 2011
Net income
$
51,249
$
— $
87,007
$
5,139
$
(92,146) $
51,249
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
Change in fair value of derivatives:
Current period reclassification in earnings -
interest rate swaps
Changes in derivative financial instruments -
interest rate swaps
Comprehensive income
Comprehensive loss attributable to noncontrolling
interests
Comprehensive income attributable to Genesis
Energy, L.P.
—
—
51,249
—
—
—
—
—
—
—
—
—
—
—
—
—
87,007
5,139
(92,146)
51,249
—
—
—
—
$
51,249
$
— $
87,007
$
5,139
$
(92,146) $
51,249
F-42
Condensed Consolidating Statement of Comprehensive Income
Year Ended December 31, 2010
Net income
$
(48,459) $
— $
(36,648) $
7,205
$
27,361
$
(50,541)
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
Change in fair value of derivatives:
Current period reclassification in earnings -
interest rate swaps
Changes in derivative financial instruments -
interest rate swaps
Other comprehensive loss from consolidated
subsidiaries
Comprehensive income
Comprehensive loss attributable to noncontrolling
interests
Comprehensive income attributable to Genesis
Energy, L.P.
—
—
829
(47,630)
—
—
—
—
—
—
2,112
(424)
—
(34,960)
1,223
—
—
—
7,205
—
—
—
(829)
26,532
2,112
(424)
—
(48,853)
—
1,223
$
(47,630) $
— $
(33,737) $
7,205
$
26,532
$
(47,630)
F-43
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2012
Net cash (used in) provided by operating activities
$
(70,083) $
— $
362,855
$
25,186
$
(128,654) $
189,304
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
Repayments on loan to non-guarantor
subsidiary
Proceeds from asset sales
Other, net
Net cash used in investing activities
CASH FLOWS FROM FINANCING
ACTIVITIES:
—
27,878
(169,421)
—
—
—
—
(141,543)
Borrowings on senior secured credit facility
Repayments on senior secured credit facility
1,674,400
(1,583,700)
Proceeds from issuance of senior unsecured
notes, including premium
Debt issuance costs
Issuance of common units for cash, net
Distributions to partners/owners
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
101,000
(7,105)
169,421
(142,383)
—
211,633
7
3
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(137,362)
(9,094)
—
(146,456)
14,909
(63,749)
(205,576)
4,078
773
(1,557)
(388,484)
—
—
—
—
169,421
(142,383)
623
27,661
2,032
9,182
(9,045)
137,465
—
—
—
—
—
49
—
—
—
—
—
(14,183)
(3,532)
(17,715)
(1,574)
1,632
(27,878)
169,421
14,909
(63,749)
—
(205,576)
(4,078)
—
—
—
—
—
—
(169,421)
4,044
(8,811)
—
—
—
773
(1,508)
(401,607)
1,674,400
(1,583,700)
101,000
(7,105)
169,421
1,135
212,768
465
10,817
11,282
156,566
(142,383)
Cash and cash equivalents at end of period
$
10
$
— $
11,214
$
58
$
— $
F-44
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2011
Net cash (used in) provided by operating activities
$
(41,392) $
— $
99,360
$
17,696
$
(17,357) $
58,307
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
Repayments on loan to non-guarantor
subsidiary
Proceeds from assets 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
Debt issuance costs
Issuance of ownership interests to partners for
cash
Distributions to partners/owners
Other, net
Net cash provided by financing activities
Net increase in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
$
—
107,956
(184,969)
—
—
—
—
(77,013)
777,600
(728,300)
(3,018)
184,969
(112,844)
—
118,407
2
1
3
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(27,417)
(575)
—
(27,992)
11,436
(19,999)
(142,886)
3,685
6,424
770
—
—
(107,956)
204,968
11,436
—
(20,787)
—
(163,673)
—
—
738
(3,685)
—
—
—
6,424
1,508
(167,987)
(20,624)
93,327
(172,297)
—
—
—
184,969
(112,844)
602
72,727
4,100
5,082
—
—
—
19,999
(12,500)
(3,618)
3,881
953
679
—
—
—
(204,968)
125,344
3,654
777,600
(728,300)
(3,018)
184,969
(112,844)
638
(75,970)
119,045
—
—
5,055
5,762
$
— $
9,182
$
1,632
$
— $
10,817
F-45
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2010
Net cash (used in) provided by operating activities
$
(569,824) $
— $
680,974
$
3,746
$
(24,433) $
90,463
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
Repayments on loan to non-guarantor
subsidiary
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
Transfer of senior secured credit facility to
Parent
Proceeds from issuance of senior unsecured
notes
Debt issuance costs
Issuance of ownership interests to partners for
cash
Acquisition of noncontrolling interest in DG
Marine
Distributions to partners/owners
Other, net
Net cash provided by (used in) financing activities
Net (decrease) increase in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
$
—
45,889
(118,875)
—
—
—
—
(72,986)
449,729
(455,629)
364,772
250,000
(14,586)
118,875
—
(70,352)
—
642,809
(1)
2
1
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(12,372)
(28)
—
(12,400)
2,859
—
(332,462)
3,331
1,146
119
—
—
—
—
—
—
(45,889)
118,875
2,859
—
—
(332,462)
(3,331)
—
—
—
1,146
119
(337,379)
(28)
69,655
(340,738)
242,100
(243,100)
(364,772)
—
118,888
(26,288)
(70,359)
1,134
(342,397)
1,198
3,884
—
—
—
—
—
—
(3,301)
(3,301)
417
262
679
—
—
—
691,829
(698,729)
—
250,000
(14,586)
(118,888)
118,875
—
70,359
3,307
(45,222)
—
—
$
— $
(26,288)
(70,352)
1,140
251,889
1,614
4,148
5,762
$
— $
5,082
$
F-46
Financial Statements of Significant Equity Investee - Cameron Highway Oil Pipeline Company
Cameron Highway Oil Pipeline Company
Balance Sheets
December 31, 2012 and 2011
(in thousands of dollars)
Assets
Current Assets
Cash and cash equivalents
Accounts receivable – trade
Accounts receivable – related parties
Prepaid and other current assets
Total current assets
Property, plant and equipment, net
Total assets
Liabilities and Partners' Equity
Current Liabilities
Accounts payable – trade
Accounts payable – related parties
Accrued product payables
Accrued ad valorem taxes
Other current liabilities
Total current liabilities
Other liabilities
Commitments and contingencies (see Note 6)
Partners' equity
Total liabilities and partners’ equity
2012
2011
(Unaudited)
$
918
4,735
189
272
6,114
421,928
$ 428,042
$
884
455
170
520
82
2,111
1,627
$
$
$
1,220
3,818
6
295
5,339
438,421
443,760
882
541
462
535
133
2,553
1,616
424,304
$ 428,042
439,591
443,760
$
The accompanying notes are an integral part of these unaudited financial statements.
F-47
Cameron Highway Oil Pipeline Company
Statements of Operations
For Years Ended December 31, 2012 and 2011
(in thousands of dollars)
Revenues
Crude oil handling revenues
Costs and expenses
Depreciation and accretion
Other operating costs and expenses
General and administrative
Total costs and expenses
Net income
2012
2011
(Unaudited)
$
34,605
$
42,454
16,596
10,428
104
27,128
7,477
$
16,742
11,933
90
28,765
13,689
$
The accompanying notes are an integral part of these unaudited financial statements.
F-48
Cameron Highway Oil Pipeline Company
Statements of Cash Flows
For Years Ended December 31, 2012 and 2011
(in thousands of dollars)
Cash flow from operating activities
Net income
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and accretion
Non-cash asset impairment charge
Loss (gain) on sale of asset
Effect of changes in operating accounts:
Accounts receivable
Prepaid and other current assets
Accounts payable
Accrued product payables
Accrued ad valorem taxes
Other current liabilities
Net cash provided by operating activities
Cash flow from investing activities
Capital expenditures
Proceeds on sale of assets
Cash used in investing activities
Cash flow from financing activities
Contributions from partners
Distributions to partners
Cash used in financing activities
Net change in cash and cash equivalents
Cash and cash equivalents, January 1
Cash and cash equivalents, December 31
2012
2011
(Unaudited)
$
7,477
$
13,689
16,596
16,742
—
(5)
591
26
(1,100)
23
(84)
(292)
(15)
(51)
22,549
(92)
5
(87)
20
(22,784)
(22,764)
(302)
1,220
4,482
623
(2,118)
462
(34)
45
34,508
(593)
58
(535)
—
(35,340)
(35,340)
(1,367)
2,587
$
918
$
1,220
The accompanying notes are an integral part of these unaudited financial statements.
F-49
Cameron Highway Oil Pipeline Company
Statements of Partners' Equity
For Years Ended December 31, 2012 and 2011
(in thousands of dollars)
Cameron
Highway
Pipeline I,
L.P.
(50%)
Cameron
Highway
Pipeline II,
L.P.
(25%)
Cameron
Highway
Pipeline III
L.P.
(25%)
(Unaudited)
Total
Capital account balances at January 1, 2011
$
230,620
$
115,311
$
115,311
$
461,242
Net income
Distributions to partners
Capital accounts balances at December 31, 2011
Net income
Contributions from partners
Distributions to partners
Capital accounts balances at December 31, 2012
$
6,845
(17,670)
219,795
3,739
10
(11,392)
212,152
$
3,422
(8,835)
109,898
1,869
5
(5,696)
106,076
$
3,422
(8,835)
109,898
1,869
5
(5,696)
106,076
$
13,689
(35,340)
439,591
7,477
20
(22,784)
424,304
The accompanying notes are an integral part of these unaudited financial statements.
F-50
Cameron Highway Oil Pipeline Company
Notes to Unaudited Financial Statements
1. Company Organization and Description of Business
Company Organization
Cameron Highway Oil Pipeline Company (“Cameron Highway”) is a Delaware general partnership formed in June 2003 to
construct, install, own and operate a 374-mile crude oil pipeline system (the “Pipeline”) located in deepwater areas of the central
Gulf of Mexico offshore Texas and Louisiana. Unless the context requires otherwise, references to “we,” “us”, “our” or the
“Company,” within these notes are intended to mean the Cameron Highway joint venture.
We are owned (i) 50% by Cameron Highway Pipeline I, L.P. (“CHOPS I”), a subsidiary of Enterprise GTM Holdings L.P.
(“Enterprise”), (ii) 25% by Cameron Highway Pipeline II, L.P. (“CHOPS II”), a subsidiary of Genesis Energy LP (“Genesis”),
and (iii) 25% by Cameron Highway Pipeline III, L.P. (“CHOPS III”), another subsidiary of Genesis. CHOPS I, CHOPS II and
CHOPS III are referred to individually as a “Partner”, or collectively as the “Partners.”
Description of Business
The Pipeline has a current throughput capacity of 270 thousand barrels per day and is designed to gather production from deepwater
areas of the Gulf of Mexico, primarily the South Green Canyon and Walker Ridge areas, for delivery to refineries and terminals
in southeast Texas. The Pipeline is supported by life of lease dedications by BP Exploration & Production Inc. (“BP”), BHP
Billiton Ltd. (“BHP”), PXP Offshore LLC and Chevron USA Inc. with respect to their production from the Holstein, Mad Dog
and Atlantis fields and by Anadarko US Offshore Corporation with respect to its production from the Constitution and Ticonderoga
fields. Additionally, we have contracted with Petrobras America Inc. to transport crude oil production from the Cottonwood field.
Manta Ray Gathering Company L.L.C., a subsidiary of Enterprise, manages and operates the Pipeline.
2. Significant Accounting Policies
Our unaudited 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 unaudited
footnote disclosures are stated in thousands of dollars.
Business Segment
We operate in a single business segment, Offshore Crude Oil Pipeline Services, which consists of the transportation of crude oil
for producers. The following table summarizes our financial information with respect to this business segment:
Segment revenues
Segment operating income
Segment net income
Segment assets
F-51
For the Year Ended
December 31,
2012
2011
$
34,605 $
7,477
7,477
42,454
13,689
13,689
At December 31,
2012
2011
$
428,042 $
443,760
Cash and Cash Equivalents
Cash and cash equivalents represent unrestricted cash on hand and highly liquid investments with original maturities of less than
three months from the date of purchase.
Contingencies
Certain conditions may exist as of the date our financial statements are issued, which may result in a loss to us but which will only
be resolved when one or more future events occur or fail to occur. Management has regular quarterly litigation reviews, including
updates from legal counsel, to assess the need for accounting recognition or disclosure of these contingencies, and such assessment
inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings that are pending against
us or unasserted claims that may result in such proceedings, our management and legal counsel evaluate the perceived merits of
any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought
therein.
We accrue an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be
reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than
any other amount, then the minimum of the range is accrued. We do not record a contingent liability when the likelihood of loss
is probable but the amount cannot be reasonably estimated or when it is believed to be only reasonably possible or remote.
For contingencies where an unfavorable outcome is reasonably possible and the impact would be material, we disclose the nature
of the contingency and, if feasible, an estimate of the possible loss or range of loss.
Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees
would be disclosed.
We had no matters requiring loss contingency accruals or disclosure at December 31, 2012 or 2011.
Crude Oil Imbalances
In the course of providing crude oil handling services, the volume of crude oil that we receive differs from the volume of crude
oil that we commit to redeliver. This volumetric difference is referred to as a crude oil imbalance, which is settled in-kind the
following month with crude oil volumes instead of cash. For financial accounting and reporting purposes, we value our crude
oil imbalances using contractual settlement prices.
Crude oil imbalance receivables and payables are netted on the Balance Sheets as a component of accounts receivable or payable,
respectively, on our balance sheet. At December 31, 2012 and 2011, our imbalance receivables were $0.1 million and $0.6 million,
respectively, and our imbalance payables were $0.3 million and $ 8 thousand, respectively.
Environmental Costs
Our operations are subject to extensive federal environmental regulations. Environmental costs for remediation are accrued based
on estimates of known remediation requirements. Such accruals are based on management's best estimate of the ultimate cost to
remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially
depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory
approvals. Expenditures to mitigate or prevent future environmental contamination are capitalized. Ongoing environmental
compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of future
expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the
expenditures are fixed or reliably determinable. There were no environmental remediation liabilities incurred as of December
31, 2012 or 2011.
Estimates
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; and (iv) revenue and
expense accruals.
F-52
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.
Impairment Testing for Long-Lived Assets
Long-lived assets such as property, plant and equipment 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.
We recorded $0.6 million of non-cash asset impairment charges in 2011 related to construction in progress balances that were
written off.
Income Taxes
We are organized as a pass-through entity for federal income tax purposes and our Partners are individually responsible for their
allocable share of our taxable income for federal income tax purposes. As a result, our financial statements do not provide for
such taxes.
Property, Plant and Equipment
Property, plant and equipment is recorded at cost. Expenditures for additions, improvements and other enhancements to property,
plant and equipment are capitalized, and minor replacements, maintenance, and repairs that do not extend asset life or add value
are charged to expense as incurred. When property, plant and equipment 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 periods it
benefits. Our property, plant and equipment is 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.
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 (though 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 property, plant and equipment and related AROs.
Recently Issued Accounting Standards
The Financial Accounting Standards Board has recently issued various new accounting standards that may impact our future
financial statements. We have evaluated these new standards and have determined that the adoption of these rules will not have
a material impact on us.
F-53
Revenue Recognition
In general, we recognize revenue when all of the following criteria are met: (i) persuasive evidence of an exchange arrangement
exists; (ii) delivery has occurred or services have been rendered; (iii) the buyer's price is fixed or determinable; and (iv) collectibility
is reasonably assured.
Crude oil handling revenues are generated from purchase and sale arrangements whereby we purchase crude oil from shippers at
various receipt points along the Pipeline for an index-based price (less a price differential per unit of volume (typically in barrels)
representing the handling fee) and sell crude oil back to the same shippers at various redelivery points at the same index-based
price. Since these are purchase and sales transactions with the same counterparty that are entered into in contemplation of one
another, the purchase and sales amounts are netted against one another and the residual handling fees (i.e., the net revenue amounts)
are recognized as crude oil handling revenues. The intent of such buy-sell arrangements is to earn a fee for handling crude oil and
not to engage in crude oil marketing activities.
We net the corresponding receivables and payables from such transactions on our Balance Sheets for consistency of presentation.
3. Property, Plant and Equipment
The historical cost of our property, plant and equipment and related accumulated depreciation balances were as follows at the
dates indicated:
Pipeline and equipment
Platforms and facilities (1)
Crude oil line fill (2)
Construction in progress
Subtotal
Less: Accumulated depreciation
Property, plant and equipment, net
Estimated
Useful Life
To 2035
To 2035
N/A
N/A
At December 31,
2011
2012
329,368
329,404 $
169,973
165,365
34,053
34,053
18,215
22,073
551,609
550,895
(113,188)
(128,967)
438,421
421,928 $
$
$
(1) Includes offshore platforms and related facilities that are an integral part of the Pipeline.
(2) Line fill is carried at historical cost and is not depreciated, but is subject to impairment
considerations.
Depreciation expense was $16.5 million and $16.6 million for the years ended December 31, 2012 and 2011, respectively.
In 2011, we recorded a non-cash asset impairment charge of $0.6 million attributable to an unfinished lateral pipeline. This
impairment charge is a component of other operating costs and expenses on our Statements of Operation for the year ended
December 31, 2011.
Asset Retirement Obligations
Our AROs result from pipeline right-of-way agreements and regulatory requirements of the Bureau of Safety and Environmental
Enforcement. The following table presents information regarding our asset retirement liabilities for the periods noted.
Balance of ARO at beginning of year
Accretion expense
Revisions in expected cash flows
Balance of ARO at end of year
F-54
For the Year Ended
December 31,
2012
2011
$
$
1,616 $
118
(107)
1,627 $
1,475
120
21
1,616
Property, plant and equipment at December 31, 2012 and 2011 includes $1.1 million and $1.2 million of asset retirement costs,
respectively, that were capitalized as an increase in the associated long-lived asset. The following table presents our forecast of
accretion expense for the periods presented:
2013
2014
2015
2016
2017
$
115 $
123 $
131 $
141 $
151
4. Partners' Equity
Income or loss amounts are allocated to Partners based on their respective partnership interests. Distributions to Partners are also
made in accordance with each Partner's respective partnership interests. We make cash distributions to Partners on a quarterly
basis to the extent that our cash balance exceeds our normal working capital and any outstanding invoices.
5. Related Party Transactions
Manta Ray Operation and Management Agreement
Manta Ray manages and operates the Pipeline under the terms of an Operation and Management Agreement (the “Agreement”).
Pursuant to the Agreement, we pay Manta Ray $350 thousand per month
(adjusted annually for changes in an average weekly earnings index as defined in the Agreement) for routine operating services.
We also reimburse Manta Ray for all non-routine operations-related services.
The Agreement may be terminated or canceled by us if Manta Ray (i) defaults in the performance of any of its obligations; (ii)
dissolves, liquidates or terminates its separate corporate existence; (iii) makes a general assignment for the benefit of creditors or
admits in writing its inability to pay its debts; or (iv) if Manta Ray is in default under the performance standards set forth in the
Agreement. The Agreement may be terminated or canceled by Manta Ray without cause at any time with at least 180 days notice
if (i) we are in default in the performance of any payment obligations; (ii) we dissolve, liquidate or terminate our separate corporate
existence; (iii) we make a general assignment for the benefit of creditors or admit in writing our inability to pay our debts generally
as they become due; or (iv) we sell or lease our Pipeline to a third party.
As presented on our statements of operations, other operating costs and expenses include $5.8 million and $5.5 million for payments
we made to Manta Ray under the Agreement for the years ended December 31, 2012 and 2011, respectively.
Offshore Platform Lease
We lease offshore platform space from an affiliate of Enterprise and a third party. Total rent paid to the affiliate of Enterprise was
$0.7 million for each of the years ended December 31, 2012 and 2011. See Note 6 for additional information regarding this
operating lease.
6. Commitments and Contingencies
Regulatory and Legal
As part of our normal business activities, we are subject to various laws and regulations, including those related to environmental
matters. In the opinion of management, compliance with existing laws and regulations will not materially affect our financial
position, results of operations or cash flows. Also, in the normal course of business, we may be a party to lawsuits and similar
proceedings before various courts and governmental agencies involving, for example, contractual disputes, environmental issues
and other matters. We are not aware of any such matters at December 31, 2012. As new information becomes available or relevant
developments occur, we will establish accruals and/or make disclosures as appropriate.
Operating Leases
Lease and rent expense included in operating income was $1.7 million and $1.8 million for the years ended December 31, 2012
and 2011, respectively.
We rent offshore platform space from an affiliate of Enterprise and a third party. Total rent paid for this platform space was $1.4
million and $1.3 million for the years ended December 31, 2012 and 2011, respectively. The agreement has an indefinite term
F-55
and will continue until the platform is abandoned. However, we can terminate the agreement at any time if we cease operations
on the platform. As a result, there are no future minimum payment obligations attributable to this agreement.
We also have right-of-way leases held in connection with our Pipeline. In general, our payments for right-of-way easements are
determined by the underlying contracts, which typically include a stated fixed fee. Certain of our right-of-way leases contain rent
escalation clauses whereby the rent is adjusted periodically for inflation. Lease expense is charged to operating costs and expenses
on a straight-line basis over the period of expected economic benefit.
The following table presents our minimum payment obligations under operating leases for right-of-way:
$
22 $
22 $
22 $
22 $
Other Commitments
2013
2014
2015
2016
2017
Thereafter
194
22 $
At December 31, 2012, we do not have any material contractual payment obligations resulting from commodity purchase contracts
or third-party service arrangements. In addition, we had no outstanding capital expenditure commitments at December 31, 2012.
7. Significant Risks
Production and Credit Risk due to Customer Concentration
Offshore crude oil pipeline systems such as ours are affected by oil exploration and production activities. Crude oil reserves are
depleting assets. Our 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 any production to a competing pipeline. We actively seek to offset the loss of volumes
due to depletion by adding connections to new customers and fields.
BP accounted for 40% and 42% of our revenues for the years ended December 31, 2012 and 2011, respectively. BHP accounted
for 42% and 41% of our revenues for the years ended December 31, 2012 and 2011, respectively. The loss of these producers or
a significant reduction in the crude oil volumes they have dedicated to us would have a material adverse effect on our financial
position, results of operations and cash flows.
In April 2010, the Deepwater Horizon drilling rig caught fire and sank in the Gulf of Mexico, resulting in an oil spill that significantly
impacted ecological resources in the Gulf of Mexico. As a result, in May 2010, a federal offshore drilling moratorium went into
effect which halted drilling of uncompleted and new oil and gas wells (in water deeper than 500 feet) in the Gulf of Mexico with
certain limited exceptions and halted consideration of drilling permits for deepwater wells. The moratorium was lifted in October
2010. Due to the inherent technological and operational challenges of deepwater drilling activities, similar tragic events could
occur in the future resulting in new regulations or other actions that curtail exploration and production activities in the Gulf of
Mexico. Such developments could have a material adverse effect on our financial position, results of operations or cash flows.
Insurance Risks
Our assets are located offshore Texas and Louisiana in the Gulf of Mexico, which is prone to tropical weather events such as
hurricanes. Our Partners are required to maintain certain levels of insurance with respect to our assets. If our assets were significantly
damaged in a storm, it could have a material impact on our financial position and results of operations.
8. Subsequent Events
In preparing these unaudited financial statements, the Company has evaluated subsequent events for potential recognition or
disclosure through February 15, 2013, the issuance date of these financial statements.
F-56
Financial Statements of Significant Equity Investee – Cameron Highway Oil Pipeline Company
INDEPENDENT AUDITORS’ REPORT
To the Management Committee of
Cameron Highway Oil Pipeline Company
Houston, Texas
We have audited the accompanying balance sheet of Cameron Highway Oil Pipeline Company (the “Company”) as of
December 31, 2010, and the related statements of operations, partners’ equity, and cash flows for the period from November 23,
2010 through December 31, 2010. These financial statements are the responsibility of the Company’s management. Our
responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with generally accepted auditing standards as established by the Auditing Standards
Board (United States) and 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. The Company is not required to have, nor were we engaged to perform, an audit
of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a
basis for designing 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 over financial reporting. Accordingly, we express no opinion. An audit
also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of the Company at
December 31, 2010, and the results of its operations and its cash flows for the period from November 23, 2010 through
December 31, 2010 in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
March 4, 2011
F-57
CAMERON HIGHWAY OIL PIPELINE COMPANY
BALANCE SHEET
December 31, 2010
(Dollars in thousands)
ASSETS
CURRENT ASSETS
Cash and cash equivalents
Accounts receivable – trade
Accounts receivable – affiliates
Prepaid and other current assets
Total current assets
PROPERTY, PLANT AND EQUIPMENT, NET
Total assets
LIABILITIES AND PARTNERS’ EQUITY
CURRENT LIABILITIES
Accounts payable – trade
Accounts payable – affiliates
Other current liabilities
Total current liabilities
OTHER LIABILITIES
COMMITMENTS AND CONTINGENCIES
PARTNERS’ EQUITY
Total liabilities and partners’ equity
See Notes to Financial Statements
$
$
$
$
2,587
8,172
218
918
11,895
455,424
467,319
2,420
1,525
657
4,602
1,475
—
461,242
467,319
F-58
CAMERON HIGHWAY OIL PIPELINE COMPANY
STATEMENT OF OPERATIONS
Period from November 23, 2010 through December 31, 2010
(Dollars in thousands)
REVENUES
Crude oil handling revenues
Total revenues
COSTS AND EXPENSES
Depreciation and accretion
Other operating costs and expenses (see Note 5)
General and administrative costs
Total costs and expenses
NET INCOME
See Notes to Financial Statements
$
$
5,636
5,636
1,797
1,159
16
2,972
2,664
F-59
CAMERON HIGHWAY OIL PIPELINE COMPANY
STATEMENT OF CASH FLOWS
Period from November 23, 2010 through December 31, 2010
(Dollars in thousands)
OPERATING ACTIVITIES
Net income
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and accretion
Effect of changes in operating accounts
Accounts receivable
Prepaid and other current assets
Accounts payable
Other current liabilities
Net cash provided by operating activities
INVESTING ACTIVITIES
Capital expenditures
Cash used in investing activities
FINANCING ACTIVITIES
Distributions to partners
Cash used in financing activities
NET CHANGE IN CASH AND CASH EQUIVALENTS
CASH AND CASH EQUIVALENTS, NOVEMBER 23
CASH AND CASH EQUIVALENTS, DECEMBER 31
See Notes to Financial Statements
$
2,664
1,797
129
100
388
(27)
5,051
(104)
(104)
(7,800)
(7,800)
(2,853)
5,440
2,587
$
F-60
CAMERON HIGHWAY OIL PIPELINE COMPANY
STATEMENT OF PARTNERS’ EQUITY
Period from November 23, 2010 through December 31, 2010
(Dollars in thousands)
BALANCE AT NOVEMBER 23, 2010
Net income
Distributions to partners
BALANCE AT DECEMBER 31, 2010
Cameron
Highway
Pipeline I, L.P.
(Enterprise)
50%
Cameron
Highway
Pipeline II, L.P.
(Genesis)
25%
Cameron
Highway
Pipeline III, L.P.
(Genesis)
25%
Total
$
$
233,188
$
116,595
$
116,595
$
466,378
1,332
(3,900)
230,620
$
666
(1,950)
115,311
$
666
(1,950)
115,311
$
2,664
(7,800)
461,242
See Notes to Financial Statements
F-61
CAMERON HIGHWAY OIL PIPELINE COMPANY
NOTES TO FINANCIAL STATEMENTS
1. Partnership Organization
Cameron Highway Oil Pipeline Company (“Cameron Highway”) is a Delaware general partnership formed in June
2003 to construct, install, own and operate a 374-mile crude oil pipeline (the “Pipeline”) located in deepwater areas of the
central Gulf of Mexico offshore Texas and Louisiana. Unless the context requires otherwise, references to “we,” “us”, “our” or
the “Company,” within these notes are intended to mean the Cameron Highway joint venture.
At December 31, 2010, we were owned (i) 50% by Cameron Highway Pipeline I, L.P. (“CHOPS I”), a subsidiary of
Enterprise GTM Holdings L.P. (“Enterprise”), (ii) 25% by Cameron Highway Pipeline II, L.P. (“CHOPS II”), a subsidiary of
Genesis Energy, L.P. (“Genesis”), and (iii) 25% by Cameron Highway Pipeline III, L.P. (“CHOPS III”), another subsidiary of
Genesis. CHOPS I, CHOPS II and CHOPS III are collectively referred to as the “Partners.” Genesis acquired its indirect 50%
equity interest in Cameron Highway from Valero Energy Corporation on November 23, 2010.
2. Summary of Significant Accounting Policies
Our financial statements are prepared on the accrual basis of accounting in conformity 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.
Business Segment
We operate in a single business segment, Offshore Pipeline & Services, which consists of a 374-mile pipeline used in
the transportation of crude oil.
Cash and Cash Equivalents
Cash and cash equivalents represent unrestricted cash on hand and highly liquid investments with original maturities
of less than three months from the date of purchase. Our Statements of Cash Flows are prepared using the indirect method.
Contingencies
Certain conditions may exist as of the date our financial statements are issued, which may result in a loss to us but
which will only be resolved when one or more future events occur or fail to occur. Our management and its legal counsel assess
such contingent liabilities, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies
related to legal proceedings that are pending against us or unasserted claims that may result in proceedings, our management
and legal counsel evaluate the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of
the amount of relief sought or expected to be sought therein.
If the assessment of a contingency indicates that it is probable that a material loss has been incurred and the amount of
liability can be estimated, then the estimated liability would be accrued in our financial statements. If the assessment indicates
that a potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated,
then the nature of the contingent liability, together with an estimate of the range of possible loss (if determinable and material),
is disclosed.
Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the
guarantees would be disclosed.
Crude Oil Imbalances
Crude oil imbalances arise in the course of providing crude oil handling services, where we receive volumes of crude
oil that differ from the volumes committed to be redelivered. These differences result in imbalances that are settled in-kind (i.e.,
with crude oil volumes instead of cash) the following month. We value our crude oil imbalances using contractual settlement
prices. Imbalance receivables and payables are classified on our balance sheet within accounts receivable and payable,
respectively. At December 31, 2010, our imbalance receivables were $0.3 million, and our imbalance payables were $0.5
million.
Environmental Costs
Our operations include activities subject to federal and state environmental regulations. Environmental costs for
remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s best
F-62
estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those
estimates may change substantially depending on information about the nature and extent of contamination, appropriate
remediation technologies and regulatory approvals. Expenditures to mitigate or prevent future environmental contamination are
capitalized. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental
remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value,
unless the amount and timing of the expenditures are fixed or reliably determinable. There were no environmental remediation
liabilities incurred as of December 31, 2010.
Estimates
Preparing our financial statements in conformity with GAAP requires management to make estimates and assumptions
that affect amounts presented in the financial statements (i.e. assets, liabilities, revenue and expenses) and disclosures about
contingent assets and liabilities. Our actual results could differ from these estimates. On an ongoing basis, management reviews
its estimates based on currently available information. Any future changes in facts and circumstances may require updated
estimates, which, in turn, could have a significant impact on our financial statements.
Financial Instruments
Cash and cash equivalents, accounts receivable and accounts payable are carried at amounts which reasonably
approximate their fair values due to their short-term nature.
Impairment Testing For Long-Lived Assets
Long-lived assets such as property, plant and equipment are reviewed for impairment whenever 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 the carrying value
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 for any of the periods presented.
Income Taxes
We are organized as a pass-through entity for federal income tax purposes and our Partners are individually
responsible for their allocable share of our taxable income for federal income tax purposes. As a result, our financial statements
do not provide for such taxes.
Partnership Equity
We allocate income or loss and pay cash distributions to Partners in accordance with their respective partnership
interests.
Property, Plant and Equipment
Property, plant and equipment is recorded at cost. Expenditures for additions, improvements and other enhancements
to property, plant and equipment are capitalized. Minor replacements, maintenance, and repairs that do not extend asset life or
add value are charged to expense as incurred. When property, plant and equipment assets are retired or otherwise disposed of,
the related cost and accumulated depreciation are removed from the accounts and any resulting gain or loss is included in
results of operations for the respective period. See Note 3 for additional information regarding our property, plant and
equipment.
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.
Over time, the liability is accreted to its present value (through accretion expense) and the capitalized cost is depreciated over
the remaining useful life of the related long-lived 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 AROs.
F-63
Recently Issued Accounting Standards
The accounting standard setting organizations, including the U.S. Securities and Exchange Commission, have recently
issued various new accounting standards. We have evaluated these new standards and have determined that the adoption of
these rules will not have a material impact on us.
Revenue Recognition
Crude oil handling revenues are generated from purchase and sale arrangements whereby we purchase crude oil from
shippers at various receipt points along the Pipeline for an index-based price (less a price differential) and sell the crude oil
back to the same shippers at various redelivery points at the same index-based price. Since these are purchase and sales
transactions with the same counterparty and are entered into in contemplation of one another, we recognize net revenue from
such arrangements based upon the price differential per unit of volume (typically in barrels) multiplied by the volume
delivered. We net the corresponding receivables and payables from such transactions on our balance sheet for consistency of
presentation.
Subsequent Events
We have evaluated subsequent events through March 4, 2011, which is the date our Audited Financial Statements and
Notes were available to be issued, and have determined that there were no material subsequent events.
3. Property, Plant and Equipment
Our property, plant and equipment values and accumulated depreciation balances were as follows at the dates
indicated:
Pipeline (1)
Platforms and facilities (2)
Crude oil line fill (3)
Construction in progress
Total
Less accumulated depreciation
Property, plant and equipment, net
Estimated
Useful
Life
30 years
30 years
n/a
n/a
December 31, 2010
$
$
329,093
169,789
34,053
19,056
551,991
96,567
455,424
(1) Includes the Pipeline and related assets.
(2) Platforms and facilities include offshore platforms and related facilities that are an integral part of the Pipeline.
(3) Crude oil line fill is carried at original cost and is not depreciated, but it is subject to impairment considerations.
The Pipeline has a throughput capacity of 500,000 barrels per day and is designed to gather production from
deepwater areas of the Gulf of Mexico, primarily the South Green Canyon and Walker Ridge areas, for delivery to refineries
and terminals in southeast Texas. The Pipeline is supported by life of lease dedications by BP, BHP Billiton Ltd. and Chevron
in connection with their production from the Holstein, Mad Dog and Atlantis fields and by Anadarko in connection with its
production from the Constitution and Ticonderoga fields. Additionally, we have contracted with Petrobras to transport crude oil
production from the Cottonwood field.
Our AROs primarily result from right-of-way agreements associated with our pipeline operations and regulatory
requirements triggered by the abandonment or retirement of certain offshore facilities. None of our assets are legally restricted
for purposes of settling AROs.
Property, plant and equipment at December 31, 2010 includes $1.2 million of estimated ARO costs capitalized as an
increase in the associated long-lived asset. Based on information currently available, we estimate that accretion expense will
approximate $0.1 million annually for 2011 through 2014 and $0.2 million for 2015.
4. Related Party Transactions
We have an Operation and Management Agreement (the “Agreement”) with Manta Ray Offshore Gathering Co LLC
(“Manta Ray”) for the operation and management of the Pipeline. Manta Ray is a subsidiary of Enterprise. Pursuant to the
F-64
agreement, we pay Manta Ray $350,000 per month (adjusted annually for changes in an average weekly earnings index as
defined in the Agreement) for routine operating services. During 2010, such amount was approximately $462,000 per month.
We reimburse Manta Ray for all non-routine operations-related services.
The Agreement may be terminated or canceled by us if Manta Ray (i) defaults in the performance of any of its
obligations; (ii) dissolves, liquidates or terminates its separate corporate existence; (iii) makes a general assignment for the
benefit of creditors or admits in writing its inability to pay its debts; or (iv) if Manta Ray is in default under the performance
standards set forth in the Agreement. The Agreement may be terminated or canceled by Manta Ray without cause at any time
with at least 180 days notice if (i) we are in default in the performance of any payment obligations; (ii) we dissolve, liquidate or
terminate our separate corporate existence; (iii) we make a general assignment for the benefit of creditors or admit in writing
our inability to pay our debts generally as they become due; or (iv) we sell or lease our Pipeline to a third party. Other operating
costs and expenses for the period from November 23, 2010 through December 31, 2010 include payments to Manta Ray
totaling $0.6 million for operation and management services rendered to us.
We rent offshore platform space from an affiliate of Enterprise and a third party. Total rent paid to the affiliate of
Enterprise was $69 thousand for the period from November 23, 2010 through December 31, 2010. See Note 5 for additional
information regarding this operating lease.
5. Commitments and Contingencies
Operating Leases
Lease and rent expense included in operating income was $224 thousand for the period from November 23, 2010 to
December 31, 2010.
We rent offshore platform space from an affiliate of Enterprise and a third party. Total rent paid for this platform space
was $138 thousand for the period from November 23, 2010 through December 31, 2010. The agreement has an indefinite term
and will continue until the platform is abandoned. However, we can terminate the agreement at any time if we cease operations
on the platform. As a result, there are no future minimum payment obligations attributable to this agreement.
We lease right-of-way held in connection with our Pipeline. In general, our payments for right-of-way easements are
determined by the underlying contracts, which typically include a stated fixed fee. Certain of our right-of-way leases contain
rent escalation clauses whereby the rent is adjusted periodically for inflation. Lease expense is charged to operating costs and
expenses on a straight line basis over the period of expected economic benefit. The following table presents our minimum
payment obligations under operating leases for right-of-way:
2011
2012
2013
2014
2015
Thereafter
Total
Other Matters
$
$
21
21
22
22
22
233
341
We are subject to potential loss contingencies arising from the course of our regular business operations. These may
result from federal, state and local environmental, health and safety laws and regulations and third-party litigations. There are
no matters currently which, in the opinion of our management, will have a material adverse effect on the financial position or
results of our operations.
6. Significant Risks
Nature of Operations
Offshore crude oil pipeline systems such as ours are affected by oil exploration and production activities. Crude oil
reserves are depleting assets that will produce over a finite period. Our Pipeline must access additional reserves to offset either
(i) the natural decline in production from existing connected wells or (ii) the loss of any production to a competitor. We actively
seek to offset the loss of volumes due to depletion by adding connections to new customers and fields.
F-65
In April 2010, the Deepwater Horizon drilling rig caught fire and sank in the Gulf of Mexico, resulting in an oil spill
that has significantly impacted ecological resources in the Gulf of Mexico. As a result, in May 2010, a federal offshore drilling
moratorium went into effect which halted drilling of uncompleted and new oil and gas wells (in water deeper than 500 feet) in
the Gulf of Mexico with certain limited exceptions and halted consideration of drilling permits for deepwater wells. The
moratorium was lifted in October 2010; however, it is uncertain at this time how and to what extent oil and natural gas supplies
from the Gulf of Mexico and other offshore drilling areas will be affected. A continued decline in oil and natural gas production
volumes and or a failure to achieve anticipated future production due to limitations caused by the federal moratorium could
have a material adverse effect on our financial position, results of operations or cash flows.
Weather-Related Risks
Our assets are located offshore Texas and Louisiana in the Gulf of Mexico, which is prone to tropical weather events
such as hurricanes. Our Partners are required to maintain certain levels of insurance with respect to our assets. If our assets
were materially damaged in a storm, it could have a material impact on our financial position and results of operations.
F-66
Officers*
Directors*
Grant E. Sims
Chief Executive Officer
Steven R. Nathanson
James E. Davison (1)
Private investor; former chairman of Davison
Transport, Inc.
James E. Davison, Jr. (1)
President and Chief Operating Officer
Private investor; executive of Davison family
Robert V. Deere
Chief Financial Officer
Paul A. Davis
Senior Vice President
Stephen M. Smith
Vice President
Karen N. Pape
businesses
Donald L. Evans (1)
President of Don Evans Group, Ltd.; non-executive
chairman of Energy Future Holdings, Corp.;
former Secretary of U.S. Dept of Commerce
Sharilyn S. Gasaway(1) (2)
Private investor; former Executive Vice President
and Chief Financial Officer of Alltel Corporation
Senior Vice President and Controller
Kenneth M. Jastrow, II (1) (2) (3)
Non-executive Chairman of Forestar Group, Inc.;
former Chairman and Chief Executive Officer of
Temple-Inland, Inc.
Corbin J. Robertson III (1) (2)
Private investor; Managing Partner of LKCM
Headwater Investments GP, LLC and LKCM
Headwater Investments I, L.P.
Grant E. Sims (1)
Chairman of the Board and Chief Executive Officer,
Genesis Energy, LLC
(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
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