PART
I
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 (including DG Marine, as defined);
“DG Marine” means DG Marine Transportation, LLC and its subsidiaries; “Denbury”
means Denbury Resources Inc. and its subsidiaries; “CO
2
” means
carbon dioxide; and “NaHS”, which is commonly pronounced as “nash”, means sodium
hydrosulfide.
DG Marine
is a joint venture in which we own an effective 49% economic
interest. Our joint venture partner holds a 51% economic interest and
controls decision-making over most key operational matters. For
financial reporting purposes, we consolidate DG Marine as discussed in Note 3 to
the Consolidated Financial Statements. References in this annual
report to DG Marine include 100% of the operations and activities of DG Marine
unless the context indicates differently.
Except
to the extent otherwise provided, the information contained in this form is as
of December 31, 2008.
General
We are a
growth-oriented 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 and Florida. We were formed
in 1996 as a master limited partnership, or MLP. We have a diverse
portfolio of customers, operations and assets, including refinery-related
plants, pipelines, storage tanks and terminals, barges, and trucks and truck
terminals. We provide services to refinery owners; oil, natural gas
and CO
2
producers;
industrial and commercial enterprises that use CO
2
and other
industrial gases; and individuals and companies that use our trucking
services. 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 manage
our businesses through four divisions which constitute our reportable
segments:
Pipeline Transportation
—We
transport crude oil, CO
2
and, to a
lesser extent, natural gas for others for a fee in the Gulf Coast region of the
U.S. through approximately 590 miles of pipeline. We own and operate
three crude oil common carrier pipelines, two CO
2
pipelines
and three small natural gas pipelines. Our 235-mile Mississippi
System provides shippers of crude oil in Mississippi indirect access to
refineries, pipelines, storage, terminaling and other crude oil infrastructure
located in the Midwest. Our 100-mile Jay System originates in southern Alabama
and the panhandle of Florida and can deliver crude oil to a terminal near
Mobile, Alabama. Our 90-mile Texas System transports crude oil from
West Columbia to Webster, Webster to Texas City and Webster to
Houston. Our crude oil pipeline systems include a total of
approximately 0.7 million barrels of leased and owned tankage. In
addition, we lease the NEJD Pipeline System, described below, to
Denbury.
The Free
State Pipeline is an 86-mile, 20” CO
2
pipeline
that extends from Denbury’s CO
2
source
fields at the Jackson Dome, near Jackson, Mississippi, to Denbury’s oil fields
in east Mississippi. In 2008, we entered into a twenty-year
transportation services agreement to deliver CO
2
on the
Free State pipeline for Denbury’s use in its tertiary recovery
operations. We also own a small CO
2
pipeline
in Mississippi to transport CO
2
to a
Denbury oil field.
In 2008,
we entered into a twenty-year financing lease transaction with Denbury valued at
$175 million related to Denbury’s North East Jackson Dome (NEJD) Pipeline
System. The NEJD Pipeline System is a 183-mile, 20” pipeline
extending from the Jackson Dome, near Jackson, Mississippi, to near
Donaldsonville, Louisiana, and is currently being leased and used by Denbury for
its Phase I area of tertiary operations in southwest Mississippi. We
recorded this lease arrangement in our consolidated financial statements as a
direct financing lease.
Refinery Services
—We provide
services to eight refining operations located predominantly in Texas, Louisiana
and Arkansas. These refineries generally are owned and operated by large
companies, including ConocoPhillips, CITGO and Ergon. Our refinery services
primarily involve processing high sulfur (or “sour”) natural gas streams, which
are separated from hydrocarbon streams, to remove the sulfur. Our refinery
services contracts, which usually have an initial term of two to ten years, have
an average remaining term of five years.
Supply and Logistics
—We
provide terminaling, blending, storing, marketing, gathering and transporting
(by trucks and barges), and other supply and logistics services to third
parties, as well as to support our other businesses. Our terminaling,
blending, marketing and gathering activities are focused on crude oil and
petroleum products, primarily fuel oil. We own or lease over 280
trucks, 550 trailers and 1.1 million barrels of liquid storage capacity at
eight different locations. Through our investment in DG Marine, we own and
operate barges used primarily for the inland marine transportation of fuel oil
and similar petroleum products. We also conduct certain crude oil
aggregating operations, including purchasing, gathering and transporting (by
trucks and pipelines operated by us and trucks, pipelines and barges operated by
others), and reselling that crude oil to help ensure (among other things) a base
supply source for our crude oil pipeline systems. Usually, our supply
and logistics segment experiences limited commodity price risk because it
involves back-to-back purchases and sales, matching our sale and purchase
volumes on a monthly basis.
Industrial
Gases
.
|
·
|
CO
2
— We supply CO
2
to industrial customers under seven long-term contracts, with an average
remaining contract life of 7 years. We acquired those
contracts, as well as the CO
2
necessary to satisfy substantially all of our expected obligations under
those contracts, in three separate transactions with affiliates of our
general partner. Our compensation for supplying CO
2
to our industrial customers is the effective difference between the price
at which we sell our CO
2
under each contract and the price at which we acquired our CO
2
pursuant to our volumetric production payments (also known as VPPs), minus
transportation costs.
|
|
·
|
Syngas
—Through our 50%
interest in a joint venture, we receive a proportionate share of fees
under a processing agreement covering a facility that manufactures
high-pressure steam and syngas (a combination of carbon monoxide and
hydrogen). Under that processing agreement, Praxair provides
the raw materials to be processed and receives the syngas and steam
produced by the facility. Praxair has the exclusive right to
use that facility through at least 2016, and Praxair has the option to
extend that contract term for two additional five year
periods. Praxair also is our partner in the joint venture and
owns the remaining 50% interest.
|
|
·
|
Sandhill Group LLC –
Through our 50% interest in a joint venture, we process raw CO
2
for
sale to other customers for uses ranging from completing oil and natural
gas producing wells to food processing. The Sandhill facility acquires
CO
2
from
us under one of the long-term supply contracts described
above.
|
We
conduct our operations through subsidiaries and joint ventures. As is
common with publicly-traded partnerships, or MLPs, our general partner is
responsible for operating our business, including providing all necessary
personnel and other resources.
Our
General Partner and Our Relationship with Denbury Resources Inc.
Denbury
Resources Inc. (NYSE:DNR) indirectly owns more than a majority interest of the
equity interest in, and controls, our general partner, which owns all of our
general partner interest, all of our incentive distribution rights,
and 7.2% of our outstanding common units. Another Denbury
subsidiary owns an additional 3% of our outstanding common
units. Denbury, a large independent energy company with an equity
market capitalization of approximately $3.2 billion as of February 27, 2009,
operates primarily in Mississippi, Louisiana and Texas, emphasizing the tertiary
recovery of oil using CO
2
flooding. Denbury is the largest producer (based on average barrels
produced per day) of oil in Mississippi, and it is one of only a handful of
producers in the U.S. that possesses CO
2
tertiary
recovery expertise along with large deposits of CO
2
reserves,
approximately 5.6 trillion cubic feet of estimated proved CO
2
reserves
as of December 31, 2008. Other than the CO
2
reserves
owned by Denbury, we are not aware of any significant natural sources of CO
2
from East
Texas to Florida. Denbury is conducting its CO
2
tertiary
recovery operations in the Eastern Gulf Coast of the U.S., an area with many
mature oil reservoirs that potentially contain substantial volumes of
recoverable oil. We believe Denbury’s equity ownership interests in us provide
Denbury with economic and strategic incentives to occasionally utilize certain
services we provide, whether through transportation agreements or other
transactions.
Although
Denbury is one of our customers from time to time, Denbury is not obligated to
enter into any additional transactions with (or to offer any opportunities to)
us or to promote our interest, and none of Denbury or any of its affiliates
(including our general partner) has any obligation or commitment to contribute
or sell any assets to us or enter into any type of transaction with us, and each
of them, other than our general partner, has the right to act in a manner that
could be beneficial to its interests and detrimental to
ours. Further, Denbury may, at any time, and without notice, alter
its business strategy, including determining that it no longer desires to use us
as a provider of any services. Additionally, if Denbury were to make
one or more offers to us, we cannot say that we would elect to pursue or
consummate any such opportunity. In addition, though our
relationship with Denbury is a strength, it also is a source of potential
conflicts.
Our
Objectives and Strategies
Our
primary business objectives are to generate stable cash flows to 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 strategies:
|
·
|
Maintaining a balanced and
diversified portfolio of midstream energy and industrial gases assets,
operations and customers.
We
intend to maintain a balanced and diversified portfolio of midstream
energy and industrial gases assets, operations and
customers. We believe our cash flows are likely to continue to
be relatively stable due to the diversity of our customer base, the nature
and increasing array of services we provide to both producers
and refiners, and the geographic location of our
operations.
|
|
·
|
Maintaining, on average, a
conservative capital structure that will allow us to execute our growth
strategy while, over the longer term, enhancing our credit
ratings.
We intend to maintain, on average, a
conservative capital structure that will allow us to execute our growth
strategy while, over the longer term, enhancing our credit
ratings. We intend to maintain a balanced approach to our
existing capital availability by focusing on opportunities that provide
stable cash flows and strategic opportunities utilizing our existing
assets. We had approximately $176.5 million available to borrow
under our senior secured credit facility as of December 31,
2008.
|
|
·
|
Increasing the utilization
rates for, and enhancing the profitability of, our existing
assets.
We intend to increase the utilization rates and,
thereby, enhance the profitability of our existing assets. We
own some pipelines and terminals that have available capacity and others
for which we can increase the capacity at a relatively nominal
cost. We also intend to enhance profitability of our existing
assets through further integration of our
operations.
|
|
·
|
Increasing stable cash flows
generated through fee-based services, longer-term contractual arrangements
and managing commodity price risks.
We
intend to generate more stable cash flows, when practical, by (i)
emphasizing fee-based compensation under longer term contracts, and (ii)
using contractual arrangements, including back-to-back contracts and
derivatives. We charge fee-based arrangements for substantially
all of our services. We are able to enter into longer term
contracts with most of our customers in our refinery services and
industrial gases divisions. Our marketing activities do not
include speculative transactions.
|
|
·
|
Expanding our asset base
through strategic and accretive acquisitions
and strategic construction and
development projects
.
We intend to
expand our asset base through strategic and accretive acquisitions and
strategic construction and development projects in new and existing
markets. Such acquisitions or projects could be structured as,
among other things, purchases, leases, tolling or similar agreements or
joint ventures.
|
|
·
|
Creating strategic
arrangements and sharing capital costs and risks through joint ventures
and strategic alliances.
We intend to continue to create
strategic arrangements with customers and other industry participants, and
to share capital costs and risks, through the formation of joint ventures
and strategic alliances.
|
|
·
|
Optimizing our CO2 and other
industrial gases expertise and infrastructure.
We intend
to continue to pursue opportunities to create growth from our experience
with CO2 and other industrial
gases.
|
|
·
|
Attracting new refinery
customers and expanding the services we provide those
customers.
We expect to attract new refinery customers
as more sour crude is imported (or produced) and refined in the U.S., and
we plan to expand the services we provide to our refinery customers by
offering a broader array of services, leveraging our strong relationships
with refinery owners and producers, and deploying our proprietary
knowledge.
|
|
·
|
Leveraging our oil handling
capabilities with Denbury’s tertiary recovery
projects
. Because we have facilities in close proximity
to certain properties on which Denbury is conducting tertiary recovery
operations, we believe we are likely to have the opportunity to provide
some oil transportation, gathering, blending and marketing services to it
and other producers as production from those properties
increases.
|
Our
Key Strengths
We
believe we are well positioned to execute our strategies and ultimately achieve
our objectives due primarily to the following competitive
strengths:
Ø
|
Diversified and Balanced
Portfolio of Customers, Operations and Assets.
We have a
diversified and well-balanced portfolio of customers, operations and
assets throughout the Gulf Coast region of the United
States. Through our diverse assets, we provide stand-alone and
integrated gathering, transporting, processing, blending, storing and
marketing services, among others, to four distinct customer groups:
refinery owners; CO
2
producers; industrial and commercial enterprises that use CO
2
and
other industrial gases; and individuals and companies that use our
transportation services. Our operations and assets are characterized
by:
|
|
·
|
Strategic
Locations.
Our oil pipelines and related assets are
predominantly located near areas that are experiencing increasing oil
production, (in large part because of Denbury’s tertiary recovery
operations) or near inland refining operations that we believe are
contemplating expansion of capacity or ability to handle sour gas
streams.
|
|
·
|
Cost-Effective Expansion and
Enhancement Opportunities.
We own pipelines, terminals
and other assets that have available capacity or that have opportunities
for expansion of capacity without incurring material
expenditures.
|
|
·
|
Cash Flow
Stability.
Our cash flow is relatively stable due to a
number of factors, including our long-term, fee-based contracts with our
refinery services and industrial gases customers; our diversified base of
customers, assets and services; and our relatively low exposure to
volatile fluctuations in commodity
prices.
|
Ø
|
Financial Liquidity and
Flexibility.
We have the
financial liquidity and flexibility to pursue additional growth projects.
As of December 31, 2008, we had $320 million of loans and
$3.5 million in letters of credit outstanding under our
$500 million credit facility, resulting in $176.5 million of
remaining credit, all of which was available under our borrowing
base. Our borrowing base fluctuates each quarter based on our earnings
before interest, taxes, depreciation and amortization, or EBITDA. Our
borrowing base may be increased to the extent of EBITDA attributable to
acquisitions, with approval of the lenders. In addition we had
$19.0 million of cash on hand at December 31,
2008.
|
Ø
|
Experienced, Knowledgeable and
Motivated Senior Management Team with Proven Track Record.
Our
senior management team has an average of more than 25 years of
experience in the midstream sector. They have worked together and
separately in leadership roles at a number of large, successful public
companies, including other publicly-traded partnerships. To help ensure
that our senior management team is incentivized to create value for our
equity holders by maintaining and increasing (over time) the distribution
rate we pay on our common units, our general partner has provided the
members of our senior management team with long-term, incentive equity
compensation that generally increases in value as our incentive
distribution rights increase in value. To take advantage of
this opportunity, our senior executive team must grow the distributions we
pay our common unitholders.
|
Ø
|
Supply and Logistics
Division
Support
s Full Suite of
Services.
In addition to its established customers, our
supply and logistics division can, from time to time, attract customers to
our other divisions and/or create synergies that may not be available to
our competitors. Several examples
include:
|
|
·
|
our
refinery services division can effectively compete with refineries, on a
stand alone basis, to remove sulfur partially due to the synergies created
from our ability to economically source, transport and store large
supplies of caustic soda (the main component in the NaHS sulfur removal
process), as well as our ability to store, transport and market
NaHS;
|
|
·
|
our
pipeline transportation division receives throughput related to the
gathering and marketing services that our supply and logistics division
provides to producers;
|
|
·
|
our
supply and logistics division gives us the opportunity to bundle services
in certain circumstances; for example, in the future, we hope to gather
disparate qualities of oil and use our terminal and storage assets to
customize blends for some of our customers needing fuel supplies;
and
|
|
·
|
our
supply and logistics division gives us the opportunity to blend, store and
distribute products made by our refinery
customers.
|
Ø
|
Unique Platform, Limited
Competition and Anticipated Growing Demand in Our Refinery Services
Operations.
We provide services to eight refining
operations located predominantly in Texas, Louisiana and Arkansas. Our
refinery services primarily involve processing sour natural gas streams,
which are separated from hydrocarbon streams, to remove the
sulfur. Refineries contract with us for a number of reasons,
including the following:
|
|
·
|
sulfur
handling and removal is typically not a core business of our refinery
customers;
|
|
·
|
over
a long period of time, we have developed and maintained strong
relationships with our refinery services customers, which relationships
are based on our reputation for high standards of performance, reliability
and safety;
|
|
·
|
the
proprietary sulfur removal process we use -- the NaHS sulfur removal
process -- is, generally, more reliable and less capital and labor
intensive than the conventional “Claus” process employed at most
refineries, and it generates a marketable by-product,
NaHS;
|
|
·
|
we
have the scale of operations and supply and logistics capabilities to make
the NaHS sulfur removal process extremely reliable as a means to remove
sulfur efficiently while working in concert with the refineries to ensure
uninterrupted refinery operations;
|
|
·
|
other
than the refinery owners (who remove their own sulfur), we have few
competitors for our refinery services business;
and
|
|
·
|
we
believe that the demand for sulfur removal at U.S. refineries will
increase in the years ahead as the quality of the oil supply used by
refineries in the U.S. continues to drop (or become more
“sour”). As that occurs, we believe more refineries will seek
economic and proven sulfur removal processes from reputable service
providers that have the scale and logistical capabilities to efficiently
perform such services. In addition, we have an increasing array
of services we can offer to our refinery
customers.
|
Ø
|
Relationship with
Denbury
. We believe Denbury has an economic and
strategic incentive to execute some business transactions with us. We also
believe that we can leverage our operations (and our relationship with
Denbury) into oil transportation and storage opportunities with third
parties, such as other producers and refinery operators, in the areas into
which Denbury expands its
operations.
|
2008
Developments
Investment
in DG Marine Transportation, LLC
On July
18, 2008, we acquired an interest in DG Marine which acquired the inland marine
transportation business of Grifco Transportation, Ltd. (“Grifco”) and two of
Grifco’s affiliates. DG Marine is a joint venture with TD Marine,
LLC, an entity formed by members of the Davison family, who are owners of
approximately 30% of our common units. (See discussion below on the
acquisition of the Davison family businesses in 2007.). TD Marine owns
(indirectly) a 51% economic interest in DG Marine, and we own (directly and
indirectly) a 49% economic interest. This acquisition gives us the
capability to provide transportation services of petroleum products by barge and
complements our other supply and logistics operations.
Denbury
Drop-Down Transactions
We
completed two “drop-down” transactions with Denbury in 2008 involving two of
their existing CO
2
pipelines
- the NEJD and Free State CO
2
pipelines. We paid for these pipeline assets with $225 million in cash and
1,199,041 common units valued at $25 million based on the average closing price
of our units for the five trading days surrounding the closing date of the
transaction. Under the twenty-year agreements with Denbury related to the NEJD
and Free State pipelines, we expect to receive approximately $30 million per
annum, in the aggregate. Future payments for the NEJD pipeline are
fixed at $20.7 million per year during the term of the financing lease, and the
payments related to the Free State pipeline are dependent on the volumes of
CO
2
transported therein, with a minimum monthly payment of $0.1
million.
Fourteen
Consecutive Distribution Rate Increases
We have
increased our quarterly distribution rate for fourteen consecutive
quarters. On February 13, 2009, we paid a cash distribution of $0.33
per unit to unitholders of record as of February 3, 2009, an increase per unit
of $0.0075 (or 2.3%) from the distribution in the prior quarter, and an increase
of 15.8% from the distribution in February 2008. As in the past,
future increases (if any) in our quarterly distribution rate will be dependent
on our ability to execute critical components of our business
strategy.
Florida
Oil Pipeline System Expansion
In the
second quarter of 2009, we expect to complete construction of an extension of
our existing Florida oil pipeline system that would extend to producers
operating in southern Alabama. That new lateral extension consists of
approximately 33 miles of 8” pipeline originating in the Little Cedar Creek
Field in Conecuh County, Alabama to a connection to our Florida Pipeline System
in Escambia County, Alabama. That project also includes gathering connections to
approximately 35 wells and oil storage capacity of 20,000 barrels in
the field. Our capital costs in 2008 related to this project totaled
$7.4 million, and we expect to expend $4.1 million to complete the project
in 2009.
Description
of Segments and Related Assets
We
conduct our business through four primary segments: Pipeline Transportation,
Refinery Services, Industrial Gases 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.
Pipeline
Transportation
Crude
Oil Pipelines
Overview.
Our core
pipeline transportation business is the transportation of crude oil for others
for a fee. Through the 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 the Federal Energy Regulatory
Commission, or FERC, or the Railroad Commission of
Texas. 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 was injected into the pipeline and the delivery
point. We also can 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 crude oil pipeline operations are generated by the difference
between the revenues from regulated published tariffs, pipeline loss allowance
revenues and the fixed and variable costs of operating and maintaining our
pipelines.
We own
and operate three common carrier crude oil pipeline systems. Our
235-mile Mississippi System provides shippers of crude oil in Mississippi
indirect access to refineries, pipelines, storage, terminaling and other crude
oil infrastructure located in the Midwest. Our 100-mile Jay System
originates in southern Alabama and the panhandle of Florida and extends to a
point near Mobile, Alabama. Our 90-mile Texas System extends from
West Columbia to Webster, Webster to Texas City and Webster to
Houston.
Mississippi
System
. Our Mississippi System extends from Soso, Mississippi
to Liberty, Mississippi and includes tankage at various locations with an
aggregate owned storage capacity of 247,500 barrels. This System is
adjacent to several oil fields operated by Denbury, which is the sole shipper
(other than us) on our Mississippi System. As a result of its
emphasis on the tertiary recovery of crude oil using CO
2
flooding,
Denbury has become the largest producer (based on average barrels produced per
day) of crude oil in the State of Mississippi, and it owns more developed
CO
2
reserves than anyone in the Gulf Coast region of the U.S. As Denbury
continues to implement its tertiary recovery strategy, its anticipated increased
production could create increased demand for our crude oil transportation
services because of the close proximity of those pipelines to Denbury’s
projects.
We
provide transportation services on our Mississippi pipeline to Denbury under an
“incentive” tariff. Under our incentive tariff, the average rate per
barrel that we charge during any month decreases as our aggregate throughput for
that month increases above specified thresholds.
Jay System
. Our
Jay System begins near oil fields in southern Alabama and the panhandle of
Florida and extends to a point near Mobile, Alabama. Our Jay System
includes tankage with 230,000 barrels of storage capacity, primarily at Jay
station. Recent changes in ownership of the more mature producing
fields in the area surrounding our Jay System have led to interest in further
development activities regarding those fields which we believe may lead to
increases in production. As a result of new production in the area
surrounding our Jay System, volumes have stabilized on that system.
We expect
to complete construction of an extension of our existing Florida oil pipeline
system in the second quarter of 2009 that would extend to producers operating in
southern Alabama. The new lateral will consist of approximately 33 miles of 8”
pipeline originating in the Little Cedar Creek Field in Conecuh County, Alabama
to a connection to our Florida Pipeline System in Escambia County, Alabama. The
project will also include gathering connections to approximately 35 wells and
additional oil storage capacity of 20,000 barrels in the field.
Texas System
. The
active segments of the Texas System extend from West Columbia to Webster,
Webster to Texas City and Webster to Houston. Those segments include
approximately 90 miles of pipeline. 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. We entered into a joint tariff with TEPPCO Crude Pipeline,
L.P. (TEPPCO) to receive oil from its system at West Columbia and a joint tariff
with TEPPCO and ExxonMobil Pipeline Company to receive oil from their systems at
Webster. We also continue to receive barrels from a connection with
Seminole Pipeline Company at Webster. We own tankage with
approximately 55,000 barrels of storage capacity associated with the Texas
System. We lease an additional approximately 165,000 barrels of
storage capacity for our Texas System in Webster. We have a tank
rental reimbursement agreement with the primary shipper on our Texas System to
reimburse us for the lease of this storage capacity at Webster.
CO
2
Pipelines
We also
transport CO
2
for a
fee. The Free State Pipeline is an 86-mile, 20” pipeline that extends
from Denbury’s CO
2
source
fields at Jackson Dome, near Jackson, Mississippi, to Denbury’s oil fields in
east Mississippi. In addition, the NEJD Pipeline System, a 183-mile,
20” CO
2
pipeline
that we lease to Denbury extends from the Jackson Dome, near Jackson,
Mississippi, to near Donaldsonville, Louisiana, currently being used by Denbury
for its tertiary operations in southwest Mississippi.
Denbury
has exclusive use of the NEJD Pipeline 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. We are responsible for
owning, operating and maintaining and making improvements to the Free State
Pipeline, however Denbury has rights to exclusive use and is required to use the
Free State Pipeline to supply CO
2
to its
current and certain of its other tertiary operations in East
Mississippi.
Customers
Denbury
is the sole shipper (other than us) on our Mississippi System and the Free State
Pipeline. Denbury also has exclusive right to use the Free State
Pipeline and the NEJD Pipeline. The customers on our Jay and Texas
Systems are primarily large, energy companies. 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 pipelines, will be built
in the same geographic areas in the near future.
Refinery
Services
We
acquired our refinery services segment in the Davison transaction in July
2007. That segment provides services to eight refining operations
primarily located in Texas, Louisiana and Arkansas. In our
processing, we apply proprietary technology that uses large quantities of
caustic soda (the primary input used by our process). Our refinery services
business generates revenue by providing a service for which it receives NaHS as
consideration and by selling the NaHS, the by-product of our process, to
approximately 100 customers. As such, we believe we are one of the
largest marketers of NaHS in North America.
NaHS is
used in the specialty chemicals business, in pulp and paper business, in
connection with mining operations and also has environmental
applications. NaHS is used in various industries for applications
including, but not limited to, agricultural, dyes, and other chemical
processing; waste treatment programs requiring stabilization and reduction of
heavy and toxic metals through precipitation; and sulfidizing oxide ores (most
commonly to separate copper from molybdenum). NaHS is also used in the Kraft
pulping process to prepare synthetic cooking liquor (white liquor); as a make-up
chemical to replace lost sulfur values; as a scrubbing media for residual
chlorine dioxide generated and consumed in mill bleach plants; and for removing
hair from hides at the beginning of the tannery process.
Our
refinery service contracts typically have an initial term from two to ten
years. Because of our reputation, experience and logistical
capability to transport, store and deliver both NaHS and caustic soda, we
believe such contracts will likely be renewed upon the expiration of their
primary terms. We also believe that the demand for sulfur removal at
U.S. refineries will increase in the years ahead as the quality of the oil
supply used by refineries in the U.S. continues to drop (or become more
“sour”). As that occurs, we believe more refineries will seek
economic and proven sulfur removal processes from reputable service providers
that have the scale and logistical capabilities to efficiently perform such
services. Because of our existing scale, we believe we will be
able to attract some of these refineries as new customers for our sulfur
handling/removal services.
The
largest cost component of providing our sulfur removal service is acquiring and
delivering caustic soda to our operations. Caustic soda, or NaOH, is the
scrubbing agent introduced in the sour gas stream to remove the sulfur and
generate the by-product, NaHS. Therefore the contribution to segment margin
includes the revenues generated from the sales of NaHS less our total cost of
providing the services, including the costs of acquiring and delivering caustic
soda to our service locations. Because the activities of these
service arrangements can fluctuate, we do, from time to time engage in other
activities such as selling caustic soda, buying NaHS from other producers for
re-sale to our customers and buying and selling sulfur, the financial results of
which are also reported in our refinery services segment.
Our
sulfur removal facilities consist of NaHS units that are located at sites leased
at five refineries, primarily in the southeastern United
States. While some of our customers have elected to own the sulfur
removal facilities located at their refineries, we operate those
facilities.
Customers
Refinery
Services: At December 31, 2008, we provided services to eight
refining operations.
NaHS
Marketing: We sell our NaHS to customers in a variety of industries,
with the largest customers involved in copper mining and the production of
paper. We sell to customers in the copper mining industry in the
western United States as well as customers who export the NaHS to South America
for mining in Peru and Chile. Many of the paper mills that purchase
NaHS from us are located in the southeastern United States. No
customer of the refinery services segment is responsible for more than ten
percent of our consolidated revenues. Approximately 13% of the
revenues of the refinery services segment in 2008 resulted from sales to
Kennecott Utah Copper, a subsidiary of Rio Tinto plc. While the
market price of copper and other ores has declined in 2008 creating a reduction
in mining operations and economic circumstances have reduced demand of paper
products from the paper mills who acquire NaHS, the provisions in our service
contracts with refiners allow us to adjust our service levels to maintain a
balance between NaHS supply and demand.
Competition
for Refinery Services Business
We
believe that the U.S. refinery industry’s demand for sulfur extraction services
will increase because we believe sour oil will constitute an ever-increasing
portion of the total worldwide supply of crude oil. In addition, we
have an increasing array of services we can offer to our refinery customers and
we believe our proprietary knowledge, scale, logistics capabilities and safety
and service record will encourage such customers to continue to outsource their
existing refinery services needs to us. While other options exist for
the removal of sulfur from sour oil, we believe our existing customers are
unlikely to change to another method due to the costs involved. Other
than the refinery owners (who may process sulfur themselves), we have few
competitors for our refinery services business.
Industrial
Gases
Overview
Our
industrial gases segment is a natural outgrowth from our pipeline transportation
business. Because of Denbury’s tertiary recovery operations utilizing
CO
2
flooding around our Mississippi System, we became familiar with CO
2
-related
activities and, ultimately, began our CO
2
business
in 2003. Our relationships with industrial customers who use CO
2
have
continued to expand, which has introduced us to potential opportunities
associated with other industrial gases. We (i) supply CO
2
to
industrial customers, (ii) process raw CO
2
and sell
that processed CO
2
, and (iii)
manufacture and sell syngas, a combination of carbon monoxide and
hydrogen.
CO
2
–
Industrial Customers
We supply
CO
2
to
industrial customers under seven long-term CO
2
sales
contracts. We acquired those contracts, as well as the CO
2
necessary
to satisfy substantially all of our expected obligations under those contracts,
in three separate transactions with Denbury. We purchased those
contracts, along with three VPPs representing 280.0 Bcf of CO
2
(in the
aggregate), from Denbury. We sell our CO
2
to
customers who treat the CO
2
and sell
it to end users for use for beverage carbonation and food chilling and
freezing. Our compensation for supplying CO
2
to our
industrial customers is the effective difference between the price at which we
sell our CO
2
under each
contract and the price at which we acquired our CO
2
pursuant
to our VPPs, minus transportation costs. We expect some seasonality
in our sales of CO
2
. The
dominant months for beverage carbonation and freezing food are from April to
October, when warm weather increases demand for beverages and the approaching
holidays increase demand for frozen foods. At December 31, 2008, we have 153.8
Bcf of CO
2
remaining
under the VPPs.
Currently,
all of our CO
2
supply is from our interests – our VPPs - in fields producing naturally
occurring CO
2
. The
agreements we executed with Denbury when we acquired the VPPs provide that we
may acquire additional CO
2
from
Denbury under terms similar to the original agreements should additional volumes
be needed to meet our obligations under the existing customer
contracts. Based on the current volumes being sold to our customers,
we believe that we will need to acquire additional volumes from Denbury in
2015. When our VPPs expire, we will have to obtain our CO
2
supply
from Denbury, from other sources, or discontinue the CO
2
supply
business. Denbury will have no obligation to provide us with CO
2
once our
VPPs expire, and Denbury has the right to compete with us in the CO
2
supply
business. See “Risks Related to Our Partnership Structure” for a
discussion of the potential conflicts of interest between Denbury and
us.
One of
the parties that we supply with CO
2
under a
long-term sales contract is Sandhill Group, LLC. On April 1, 2006, we
acquired a 50% interest in Sandhill Group, LLC as discussed below.
CO
2
-
Processing
We own a
50% partnership interest in Sandhill. Reliant Processing Ltd. owns
the remaining 50% of Sandhill. Sandhill is a limited liability
company that owns a CO
2
processing
facility located in Brandon, Mississippi. Sandhill is engaged in the production
and distribution of liquid carbon dioxide for use in the food, chemicals and oil
industries. The facility acquires CO
2
from us
under a long-term supply contract. This contract expires in 2023, and
provides for a maximum daily contract quantity of 16,000 Mcf per day with a
take-or-pay minimum quantity of 2,500,000 Mcf per year.
Syngas
We own a
50% partnership interest in T&P Syngas. T&P Syngas is a
partnership which owns a facility located in Texas City, Texas that manufactures
syngas and high-pressure steam. Under a long-term processing
agreement, the joint venture receives fees from its sole customer,
Praxair Hydrogen Supply, Inc. during periods when processing occurs, and Praxair
has the exclusive right to use the facility through at least 2016, which Praxair
has the option to extend for two additional five year terms. Praxair
owns the remaining 50% interest in that joint venture.
Customers
Five of
our seven contracts for supplying CO
2
are with
large international companies. One of the remaining contracts is with
Sandhill Group, LLC, of which we own 50%. The remaining contract is
with a smaller company with a history in the CO
2
business. Revenues from this segment did not account for more than
ten percent of our consolidated revenues.
The sole
customer of T&P Syngas is Praxair, a worldwide provider of industrial
gases.
Sandhill
sells to approximately 20 customers, with sales to three of those customers
representing approximately 67% of Sandhill’s total revenues of approximately $11
million in 2008. In 2008, Sandhill sold approximately $2.4 million of
CO
2
to
affiliates of Reliant Processing, Ltd., our partner in Sandhill, as discussed
above. Sandhill has long-term relationships with those customers and
has not experienced collection problems with them.
Competition
Currently,
all of our CO
2
supply is from our interest – our VPPs – in fields producing naturally occurring
sources. In the future we may have to obtain our CO
2
supply
from manufactured processes. Naturally-occurring CO
2
, like that
from the Jackson Dome area, occurs infrequently, and only in limited areas east
of the Mississippi River, including the fields controlled by
Denbury. Our industrial CO
2
customers
have facilities that are connected to the NEJD CO
2
pipeline,
which makes delivery easy and efficient. Once our existing VPPs
expire, we will have to obtain CO
2
from
Denbury or other suppliers should we choose to remain in the CO
2
supply
business, and the competition and pricing issues we will face at that time are
uncertain.
With
regard to our CO
2
supply
business, our contracts have long terms and generally include take-or-pay
provisions requiring annual minimum volumes that each customer must pay for even
if the CO
2
is not
taken.
Due to
the long-term contract and location of our syngas facility, as well as the costs
involved in establishing facilities, we believe it is unlikely that competing
facilities will be established for our syngas processing services.
Sandhill
has competition from the other industrial customers to whom we supply CO
2
. As
discussed above, the limited amounts of naturally-occurring CO
2
east of
the Mississippi River makes it difficult for competitors of Sandhill to
significantly increase their production or sales and, thereby, increase their
market share.
Supply and
Logistics
Our
supply and logistics segment has the capabilities and assets to provide a wide
array of services to oil producers and refiners in the Gulf Coast
region. These services include gathering of crude oil at the
wellhead, marketing of crude oil to refiners and other supply companies,
transporting crude oil by truck to pipeline injection points or directly to the
refiners, and acquiring the resulting petroleum products from the refiners for
transportation by truck and barge primarily to third parties in fuels markets
and some end-users. Our profit for those services is derived
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 gathering and marketing operations are concentrated in Texas, Louisiana,
Alabama, Florida and Mississippi. Those operations help to ensure
(among other things) a base supply source for our oil pipeline
systems. In addition, our oil gathering and marketing
activities provide us with an extensive expertise, knowledge base and skill set
that facilitates our ability to capitalize on regional opportunities which arise
from time to time in our market areas. Usually, this segment experiences limited
commodity price risk because we generally make back-to-back purchases and sales,
matching our sale and purchase volumes on a monthly basis. The
most substantial component of our aggregating costs relates to operating our
fleet of leased trucks.
When the
crude oil markets are in contango (oil prices for future deliveries are higher
than for current deliveries), we may purchase and store crude oil as inventory
for delivery in future months. When we purchase this inventory, we
simultaneously enter into a contract to sell the inventory in the future period,
either with a counterparty or in the crude oil futures market. We generally will
account for this inventory and the related derivative hedge as a fair value
hedge in accordance with Statement of Financial Accounting Standards No.
133. See Note 17 of the Notes to the Consolidated Financial
Statements.
With the
Davison acquisition in 2007, we added trucks, trailers and existing leased and
owned storage, and we expanded our activities to include transporting, storing
and blending intermediate and finished refined products. In our
petroleum products marketing operations, we primarily supply fuel oil, asphalt,
diesel and gasoline to wholesale markets and some end-users such as paper mills
and utilities. We also provide services to refineries by purchasing
their products that do not meet the specifications they desire, transporting
them to one of our terminals and blending them to a quality that meets the
requirements of our customers. We cannot predict when the
opportunities to provide this service will arise. However, when such
opportunities arise, their contribution to margin as a percentage of the
revenues tends to be higher than the same percentage attributable to our
recurring operations.
Our
supply and logistics operations utilize a variety of assets. Those
assets include leased and owned tankage at terminals in our area of
concentration with total storage capacity of 1.1 million barrels, over 280
trucks and over 550 trailers, as well as barges owned and operated by DG
Marine. DG Marine owns nine pushboats and sixteen double hulled,
hot-oil asphalt-capable barges with capacities ranging from 30,000 to 38,000
barrels each. DG Marine also will take delivery of four additional
barges and acquire one additional pushboat in the first half of
2009. Several of our terminals are located on waterways in the
southeastern United States that are accessible by barge.
We
believe we are well positioned to provide a full suite of logistical services to
both independent and integrated refinery operators, ranging from upstream (the
procurement and staging of refinery inputs) to downstream (the transportation,
staging and marketing) of refined products.
Customers
and Competition
In our
supply and logistics segment, we sell crude oil and petroleum products and
provide transportation services to hundreds of customers. During
2008, more than ten percent of our consolidated revenues were generated from
Shell Oil Company. We do not believe that the loss of any one
customer for crude oil or petroleum products would have a material adverse
effect on us as these products are readily marketable commodities.
Our
largest competitors in the purchase of leasehold crude oil production are Plains
Marketing, L.P., Shell (US) Trading Company, and TEPPCO Partners,
L.P. Additionally we compete with many regional and local gatherers
who may have significant market share in the areas in which they
operate. In our petroleum products marketing operations and our
trucking and barge operations, we compete primarily with regional suppliers.
Competitive factors in our supply and logistics business include price, personal
relationships, 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.
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 companies that purchase NaHS. 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 independent
energy companies with stable payment experience. The credit risk
related to contracts which 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 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. We use similar procedures to manage our exposure to our
customers in the pipeline transportation and industrial gases
segments.
Some of
our customers experienced cash flow difficulties in the latter half of 2008 as a
result of the tightening of the credit markets. These customers
generally purchase petroleum products and NaHS from us. We have
strengthened our credit monitoring procedures to perform more frequent review of
our customer base. As a result of cash flow difficulties of some of
our customers, we have experienced a delay in collections from these customers
and have established an allowance for possible uncollectible receivables at
December 31, 2008 in the amount of $1.1 million.
Employees
To carry
out our business activities, our general partner employed, at February 27, 2009,
approximately 610 employees. Additionally, DG Marine employed 133
employees. None of those employees are represented by labor unions,
and we believe that relationships with those employees are
good.
Organizational
Structure
Genesis
Energy, LLC, a Delaware limited liability company, serves as our sole general
partner and as our general partner of all of our subsidiaries. Our
general partner is owned and controlled by Denbury Gathering & Marketing,
Inc., a subsidiary of Denbury, and certain members of our Senior Management own
an interest as described below. Below is a chart depicting our
ownership structure.
(1)
The
incentive compensation arrangement between our general partner and our Senior
Executives (see Item 11. Executive Compensation.), provides them long-term
incentive equity compensation that generally increases in value as the incentive
distribution rights held by our general partner increase in value. The maximum
amount of this interest is 20% (17.2% currently awarded) and will fluctuate in
value with increases or decreases in our distributions to our partners and our
success in generating available cash.
Regulation
Pipeline
Tariff Regulation
The
interstate common carrier pipeline operations of the Jay and Mississippi Systems
are subject to rate regulation by FERC under the Interstate Commerce Act, or
ICA. FERC regulations require that oil pipeline rates be posted
publicly and that the rates be “just and reasonable” and not unduly
discriminatory.
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 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—a cost-of-service methodology, competitive market showings
(“Market-Based Rates”), or agreements between shippers and the oil pipeline
company that the rate is acceptable (“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
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 be non-discriminatory and 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 TEPPCO 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
natural gas gathering pipelines and CO
2
pipeline
are subject to regulation by the state agencies in the states in which they are
located.
Barge
Regulations
DG
Marine’s inland marine transportation operations are subject to regulation by
the United States Coast Guard (USCG), federal and state laws. The
Jones Act is a federal cabotage law that restricts domestic marine
transportation in the U.S. to vessels built and registered in the U.S., manned
by U.S. citizens and owned and operated by U.S. citizens. The crews
employed on the pushboats are required to be licensed by the
USCG. Federal regulations require that all tank barges engaged in the
transportation of oil and petroleum in the U.S. be double hulled by
2015. All of DG Marine’s barges are double-hulled.
Environmental
Regulations
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, 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, the imposition of remedial obligations, and the imposition
of injunctive obligations. 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.
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, including current owners and operators
of a contaminated facility, owners and operators of the facility at the time of
contamination, and those parties arranging for waste disposal at a contaminated
facility. Such “responsible persons” may be subject to joint and
several liability for the costs of cleaning up the hazardous substances that
have been released into the environment and for damages to natural
resources. 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. In cases of environmental
contamination, it is also not uncommon for neighboring landowners and other
third parties to file claims for personal injury and property damage allegedly
caused by the hazardous substances released into the
environment.
We
currently own or lease, and have in the past owned or leased, properties that
have been in use for many years in connection with the gathering and
transportation of hydrocarbons including crude oil and other activities that
could cause an environmental impact. We also generate, handle and
dispose of regulated materials in the course of our operations, including some
characterized as “hazardous substances” under CERCLA and “hazardous wastes”
under RCRA. We may therefore be subject to liability and regulation
under CERCLA, RCRA and analogous state laws for hydrocarbons or other substances
that may have been disposed of or released on or under our current or former
properties or at other locations where wastes have been taken for
disposal. Under these laws and regulations, we could be required to
undertake investigations into suspected contamination, remove previously
disposed wastes, remediate environmental contamination, restore affected
properties, or undertake measures to prevent future contamination.
The
Federal Water Pollution Control Act, as amended, also known as the “Clean Water
Act” and the Oil Pollution Act, or OPA, and analogous state laws and regulations
promulgated thereunder impose restrictions and controls regarding the discharge
of pollutants, including crude oil, into federal and state
waters. The Clean Water Act and OPA provide administrative, civil and
criminal penalties for any unauthorized discharges of pollutants, including oil,
and impose liabilities for the costs of remediation of
spills. Federal and state permits for water discharges also may be
required. OPA also requires operators of offshore facilities and
certain onshore facilities near or crossing waterways to provide financial
assurance generally ranging from $10 million in state waters to $35 million in
federal waters to cover potential environmental cleanup and restoration
costs. This amount can be increased to a maximum of $150 million
under certain limited circumstances where the Minerals Management Service
believes such a level is justified based on the worst case spill risks posed by
the operations. We have developed an Integrated Contingency Plan to
satisfy components of OPA as well as the federal Department of Transportation,
the federal Occupational and Safety Health Act, or OSHA, and state laws and
regulations. We believe this plan meets regulatory requirements as to
notification, procedures, response actions, response resources and spill impact
considerations in the event of an oil spill.
The 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.
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.
DG Marine
is subject to many of the same regulations as our other operations, including
the Clean Water Act, OPA and the Clean Air Act. OPA and CLERCA
require DG Marine to obtain a Certificate of Financial Responsibility for each
barge and most of its pushboats to evidence financial ability to satisfy
statutory liabilities for oil and hazardous substance water
pollution.
Recent
scientific studies have suggested that emissions of certain gases, including
CO
2
,
methane and certain other gases may be contributing to the warming of the
Earth’s atmosphere. In response to such studies, it is anticipated
that the U.S. Congress will continue to actively consider legislation to
restrict or further regulate the emission of greenhouse gases, primarily through
the development of emission inventories and/or regional greenhouse gases cap and
trade programs. Also, on April 2, 2007, the U.S. Supreme Court in
Massachusetts, et al. v.
EPA
held that CO
2
may be
regulated as an “air pollutant” under the federal Clean Air Act and the EPA must
consider whether it is required to regulate greenhouse gases from mobile sources
such as cars and trucks. The Court’s holding in
Massachusetts
that greenhouse
gases fall under the Clean Air Act also may result in future regulation of
greenhouse gas emissions from stationary sources. In July 2008, the
EPA released an Advance Notice of Proposed Rulemaking regarding possible future
regulation of greenhouse gas emissions under the Clean Air Act, in response to
the Supreme Court’s decision in
Massachusetts
. In
the notice, the EPA evaluated the potential regulation of greenhouse gases under
the Clean Air Act and other potential methods of regulating greenhouse
gases. Although the notice did not propose any specific, new
regulatory requirements for greenhouse gases, it indicates that federal
regulation of greenhouse gas emissions could occur in the near
future. Thus, there may be restrictions imposed on the emission of
greenhouse gases if Congress does not adopt new legislation specifically
addressing emissions of greenhouse gases.
Operational
components of our stationary facilities that require the combustion of
carbon-based fuel (such as internal combustion engine-driven pumps) produce
greenhouse gas emissions in the form of CO
2
. Although
it is not possible at this time to predict how legislation that may be enacted
or new regulations that may be adopted to address greenhouse gas emissions would
impact our business, any such new federal, regional or state restrictions on
emissions of CO2 or other greenhouse gases that may be imposed in the areas in
which we conduct business could result in increased compliance costs or
additional operating restrictions, and could have a material adverse effect on
our business, financial condition, demand for our services, results of
operations, and cash flows.
Safety
and Security Regulations
Our crude
oil, natural gas and CO
2
pipelines
are subject to construction, installation, operation and safety regulation by
the Department of Transportation, or DOT, and various other federal, state and
local agencies. The Pipeline Safety Act of 1992, among other things,
amends the Hazardous Liquid Pipeline Safety Act of 1979, or HLPSA, in several
important respects. It requires the Pipeline and Hazardous Materials
Safety Administration of DOT to consider environmental impacts, as well as its
traditional public safety mandates, when developing pipeline safety
regulations. In addition, the Pipeline Safety Improvement Act of 2005
mandates the establishment by DOT of pipeline operator qualification rules
requiring minimum training requirements for operators, the development of
standards and criteria to evaluate contractors’ methods to qualify their
employees and requires that pipeline operators provide maps and other records to
the DOT. It also authorizes the DOT to require that pipelines be
modified to accommodate internal inspection devices, to mandate the evaluation
of emergency flow restricting devices for pipelines in populated or sensitive
areas, and to order other changes to the operation and maintenance of petroleum
pipelines. 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.
On March
31, 2001, the DOT promulgated Integrity Management Plan, or IMP, regulations.
The IMP regulations 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 IMP
regulation required us to prepare an Integrity Management Plan 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
risk factors to be considered include proximity to population areas, waterways
and sensitive areas, known pipe and coating conditions, leak history, pipe
material and manufacturer, adequacy of cathodic protection, operating pressure
levels and external damage potential. The IMP regulations required
that the baseline assessment be completed by April 1, 2008, with 50% of the
mileage assessed by September 30, 2004. Reassessment is then required
every five years. As testing is complete, we are required to take
prompt remedial action to address all integrity issues raised by the
assessment. 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 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.
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 and CO
2
pipelines,
and natural gas pipelines that do not engage in interstate
operations. 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 crude
oil pipelines are also subject to the requirements of the federal Department of
Transportation regulations requiring qualification of all pipeline
personnel. The Operator Qualification, or OQ, program requires
operators to develop and submit a written program. The regulations
also require all pipeline operators to develop a training program for pipeline
personnel and to qualify them on covered tasks at the operator’s pipeline
facilities. The intent of the OQ regulations is to ensure a qualified
workforce by pipeline operators and contractors when performing covered tasks on
the pipeline and its facilities, thereby reducing the probability and
consequences of incidents caused by human error.
Our crude
oil, refined products and refinery services operations are also subject to the
requirements of OSHA and comparable state statutes. We believe that
our operations have been operated in substantial compliance with OSHA
requirements, including general industry standards, record keeping requirements
and monitoring of occupational exposure to regulated
substances. 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.
We have
an operating authority issued by the Federal Motor Carrier Administration of the
Department of Transportation for our trucking operations, and we are subject to
certain motor carrier safety regulations issued by the DOT. The
trucking regulations cover, among other things, driver operations, maintaining
log books, truck manifest preparations, the placement of safety placards on the
trucks and trailer vehicles, drug testing, safety of operation and equipment,
and many other aspects of truck operations. We are subject to federal
EPA regulations for the development of written Spill Prevention Control and
Countermeasure, or SPCC, Plans for our trucking facilities and crude oil
injection stations. Annually, trucking employees receive training
regarding the transportation of hazardous materials and the SPCC
Plans.
The USCG
regulates occupational health standards related to DG Marine’s vessel
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 DOT guidance. We will institute, as appropriate,
additional security measures or procedures indicated by the DOT or the
Transportation Safety Administration (an agency of the Department of Homeland
Security, which has assumed responsibility from the DOT). None of
these measures or procedures should be construed as a guarantee that our assets
are protected in the event of a terrorist attack.
Commodities
Regulation
When we
use futures and options contracts that are traded on the NYMEX, these contracts
are subject to strict regulation by the Commodity Futures Trading Commission and
the rules of the NYMEX.
Website
Access to Reports
We make
available free of charge on our internet website (
www.genesis
energylp
.com
) our annual
report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K
and amendments to those reports filed or furnished pursuant to Section 13(a) or
15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable
after we electronically file the material with, or furnish it to, the
SEC.
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 continue to be, disrupted and volatile
as a result of adverse conditions. There can be no assurance that
government response to the disruptions in the financial markets will 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.
Recent
disruptions in the credit markets and concerns about local and global economic
growth have had a significant adverse impact on global financial markets and
commodity prices, both of which have contributed to a decline in our unit price
and corresponding market capitalization. If these disruptions, which
existed throughout the fourth quarter of 2008, continue, they could negatively
impact our profitability. The current financial turmoil affecting the
banking system and financial markets, and the possibility that financial
institutions may consolidate or go out of business has resulted in a tightening
of the credit markets, a low level of liquidity in many financial markets, and
extreme volatility in fixed income, credit and equity markets. Our
credit facility arrangements involve over fifteen different lending
institutions. While none of these institutions have combined or
ceased operations, further consolidation of the credit markets could result in
lenders desiring to limit their exposure to an individual
enterprise. Additionally, some institutions may desire to limit
exposure to certain business activities in which we are engaged. Such
consolidations or limitations could limit our access to capital and could impact
us when we desire to extend or make changes to our existing credit
arrangements.
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, 2008, 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 are variable. Global financial market conditions have
reduced interest rates to unprecedented low rates, reducing our interest
costs. 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.
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, including payments to our general partner.
The
amount of cash we distribute on our units principally depends upon margins we
generate from our refinery services, pipeline transportation, logistics and
supply and industrial gases businesses which will fluctuate from quarter to
quarter based on, among other things:
|
·
|
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
volumes of CO
2
we
sell and the prices at which we sell
it;
|
|
·
|
the
demand for our terminal storage
services;
|
|
·
|
the
level of our operating costs;
|
|
·
|
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 established by our general partner in its sole
discretion 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, 2008, we
had approximately $320 million outstanding of senior secured
indebtedness.
We must
comply with various affirmative and negative covenants contained in our credit
facilities. Among other things, these covenants limit our ability
to:
|
·
|
incur
additional indebtedness or liens;
|
|
·
|
make
payments in respect of or redeem or acquire any debt or equity issued by
us;
|
|
·
|
make
loans or investments;
|
|
·
|
enter
into any hedging agreement for speculative
purposes;
|
|
·
|
acquire
or be acquired by other companies;
and
|
|
·
|
amend
some of our contracts.
|
The
restrictions under our indebtedness may prevent us from engaging in certain
transactions which might otherwise be considered beneficial to us and could have
other important consequences to unitholders. For example, they
could:
|
·
|
increase
our vulnerability to general adverse economic and industry
conditions;
|
|
·
|
limit
our ability to make distributions; to fund future working capital, capital
expenditures and other general partnership requirements; to engage in
future acquisitions, construction or development activities; 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;
|
|
·
|
limit
our flexibility in planning for, or reacting to, changes in our businesses
and the industries in which we operate;
and
|
|
·
|
place
us at a
competit
ive
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 which 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. If an event of default occurs under our joint ventures’ credit
facilities, we may be required to repay amounts previously distributed to us and
our subsidiaries. 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, 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.
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
CO
2
-
volumes, which often depends 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 CO
2
— 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 (as in the case of oil marketing and CO
2
operations).
Our
source of volumes depends on successful exploration and development of
additional oil reserves by others and other matters beyond our
control.
The oil
and other 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. We cannot assure unitholders that
production will rise to sufficient levels to allow us to maintain or increase
the commodity volumes we are experiencing.
We
face intense competition to obtain 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.
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 reserves, NaHS or
refined products produced. We compete with others for any such volumes on the
basis of many factors, including:
|
·
|
geographic
proximity to the production;
|
|
·
|
logistical
efficiency in all of our
operations;
|
|
·
|
operational
efficiency in our refinery services
business;
|
|
·
|
customer
relationships; and
|
Additionally,
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 transmitted 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, and CO
2
prices are
volatile and could have an adverse effect on our profits and cash flow. Our
operations are affected by price reductions in those commodities. Price
reductions in those commodities can cause material long and short term
reductions in the level of throughput, volumes and margins in our logistic and
supply businesses. Price changes for NaHS and caustic soda affect the
margins we achieve in our refinery services business.
Prices
for commodities can fluctuate in response to changes in supply, market
uncertainty and a variety of additional factors that are beyond our
control.
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 pipeline transportation business.
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
are exposed to the credit risk of our customers in the ordinary course of our
business activities.
When we
market any of our products or services, we must determine the amount, if any, of
the line of credit we will extend to any given customer. Since typical sales
transactions can involve very large volumes, the risk of nonpayment and
nonperformance by customers is an important consideration in our
business.
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 parties. 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. Even if our credit review and analysis
mechanisms work properly, we have, and we could continue to experience losses in
dealings with other parties.
Additionally,
many of our customers are impacted by the weakening economic outlook and
declining commodity prices in a manner that could influence the need for our
products and services.
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 environmental protection and safety laws and regulations that restrict our
operations, impose relatively harsh consequences 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.
FERC
Regulation and a changing regulatory environment could affect our cash
flow.
The FERC
extensively 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:
|
·
|
rates
of return on equity;
|
|
·
|
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.
|
Given the
extent of this regulation, the extensive changes in FERC policy over the last
several years, 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.
A
substantial portion of our CO
2
operations
involves us supplying CO
2
to industrial customers using reserves attributable to our volumetric production
payment interests, which are a finite resource and projected to terminate around
2015.
The cash
flow from our CO
2
operations
involves us supplying CO
2
to
industrial customers using reserves attributable to our volumetric production
payments, which are projected to terminate around 2015. Unless we are able to
obtain a replacement supply of CO
2
and enter
into sales arrangements that generate substantially similar economics, our cash
flow could decline significantly around 2015.
Fluctuations
in demand for CO
2
by our
industrial customers could have a material adverse impact on our profitability,
results of operations and cash available for distribution.
Our
customers are not obligated to purchase volumes in excess of specified minimum
amounts in our contracts. As a result, fluctuations in our customers’ demand due
to market forces or operational problems could result in a reduction in our
revenues from our sales of CO
2
.
Our
wholesale CO
2
industrial
operations are dependent on five customers and our syngas operations are
dependent on one customer.
If one or
more of those customers experience financial difficulties such that they fail to
purchase their required minimum take-or-pay volumes, our cash flows could be
adversely affected, and we cannot assure unitholders that an unanticipated
deterioration in those customers’ ability to meet their obligations to us might
not occur.
Our
Syngas joint venture has dedicated 100% of its syngas processing capacity to one
customer pursuant to a processing contract. The contract term expires in 2016,
unless our customer elects to extend the contract for two additional five year
terms. If our customer reduces or discontinues its business with us, or if we
are not able to successfully negotiate a replacement contract with our sole
customer after the expiration of such contract, or if the replacement contract
is on less favorable terms, the effect on us will be adverse. In addition, if
our sole customer for syngas processing were to experience financial
difficulties such that it failed to provide volumes to process, our cash flow
from the syngas joint venture could be adversely affected. We believe this
customer is creditworthy, but we cannot assure unitholders that unanticipated
deterioration of its ability to meet its obligations to the syngas joint venture
might not occur.
Our
CO
2
operations are exposed to risks related to Denbury’s operation of its CO
2
fields,
equipment and pipeline as well as any of our facilities that Denbury
operates.
Because
Denbury produces the CO
2
and
transports the CO
2
to our
customers (including Denbury), any major failure of its operations could have an
impact on our ability to meet our obligations to our CO
2
customers
(including Denbury). We have no other supply of CO
2
or method
to transport it to our customers. Sandhill relies on us for its
supply of CO
2
therefore
our share of the earnings of Sandhill would also be impacted by any major
failure of Denbury’s operations.
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 2008, approximately 63% of our refinery
services’ division NaHS by-product was attributable to Conoco’s refinery located
in Westlake, Louisiana. That contract requires Conoco to make
available minimum volumes of acid gas to us (except during periods of force
majeure). Although the primary term of that contract extends until
2018, if Conoco is excused from performing, or refuses or is unable to perform,
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
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
|
|
·
|
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, depletion and amortization expenses. A
substantial increase in our indebtedness and contingent liabilities could have a
material adverse effect on our business, as discussed above.
Our
actual construction, development and acquisition costs could exceed our
forecast, and our cash flow from construction and development projects may not
be immediate.
Our
forecast contemplates significant expenditures for the development, construction
or other acquisition of energy infrastructure assets, including some
construction and development projects with technological challenges. We may not
be able to complete our projects at the costs currently estimated. If we
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
financial derivative instruments and other hedging mechanisms from time to time
to limit a portion of the adverse effects resulting from changes in commodity
prices, although there are times when we do not have any hedging mechanisms in
place. 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.
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.
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 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, or in
the case of DG Marine, only one of which is appointed by us. In
addition, the other 50% owners in our T&P Syngas and Sandhill joint ventures
operate those joint venture facilities and the other 51% owner of our DG Marine
joint venture controls key operational decisions of the joint venture. Thus,
without the concurrence of the other joint venture participant, 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.
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 used in the provision of sour gas treatment services
provided by us to refineries. NaHS, the resulting product from the refinery
services we provide, is a vital ingredient in a number of industrial and
consumer products and processes. Any decrease in the supply of caustic soda
could affect our ability to provide 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
operating results from our trucking operations may fluctuate and may be
materially adversely affected by economic conditions and business factors unique
to the trucking industry.
Our
trucking business is dependent upon factors, many of which are beyond our
control. Those factors include excess capacity in the trucking industry,
difficulty in attracting and retaining qualified drivers, significant increases
or fluctuations in fuel prices, fuel taxes, license and registration fees and
insurance and claims costs, to the extent not offset by increases in freight
rates. Our results of operations from our trucking operations also are affected
by recessionary economic cycles and downturns in customers’ business cycles.
Economic and other conditions may adversely affect our trucking customers and
their ability to pay for our services.
In the
past, there have been shortages of drivers in the trucking industry and such
shortages may occur in the future. Periodically, the trucking industry
experiences substantial difficulty in attracting and retaining qualified
drivers. If we are unable to continue to retain and attract drivers, we could be
required to adjust our driver compensation package, let trucks sit idle or
otherwise operate at a reduced level, which could adversely affect our
operations and profitability.
Significant
increases or rapid fluctuations in fuel prices are major issues for the
transportation industry. Increases in fuel costs, to the extent not offset by
rate per mile increases or fuel surcharges, have an adverse effect on our
operations and profitability.
Denbury
is the only shipper (other than us) on our Mississippi System.
Denbury
is our only customer on the Mississippi System. This relationship may subject
our operations to increased risks. Any adverse developments concerning Denbury
could have a material adverse effect on our Mississippi System business. Neither
our partnership agreement nor any other agreement requires Denbury to pursue a
business strategy that favors us or utilizes our Mississippi System. Denbury may
compete with us and may manage their assets in a manner that could adversely
affect our Mississippi System business.
Our
investment in DG Marine exposes us to certain risks that are inherent to the
barge transportation industry as well certain risks applicable to our other
operations.
DG
Marine’s inland barge transportation business has exposure to certain risks
which are significant to our other operations and certain risks inherent to the
barge transportation industry. For example, unlike our other
operations, DG Marine operates barges that transport products to and from
numerous marine locations, which exposes us to new risks,
including:
|
·
|
being
subject to the Jones Act and other federal laws that restrict U.S.
maritime transportation to vessels built and registered in the U.S. and
owned and manned by U.S. citizens, with any failure to comply with such
laws potentially resulting in severe penalties, including permanent loss
of U.S. coastwise trading rights, fines or forfeiture of
vessels;
|
|
·
|
relying
on a limited number of customers;
|
|
·
|
having
primarily short-term charters which DG Marine may be unable to renew as
they expire; and
|
|
·
|
competing
against businesses with greater financial resources and larger operating
crews than DG Marine.
|
In
addition, like our other operations, DG Marine’s refined products transportation
business is an integral part of the energy industry infrastructure, which
increases our exposure to declines in demand for refined petroleum products or
decreases in U.S. refining activity.
Risks
Related to Our Partnership Structure
Denbury
and its affiliates have conflicts of interest with us and limited fiduciary
responsibilities, which may permit them to favor their own interests to
unitholder detriment.
Denbury
indirectly owns the majority interest in, and controls, our general partner.
Conflicts of interest may arise between Denbury and its affiliates, including
our general partner, on the one hand, and us and our unitholders, on the other
hand. As a result of these conflicts, our general partner may favor its own
interest and the interest of its affiliates or others over the interest of our
unitholders. These conflicts include, among others, the following
situations:
|
·
|
neither
our partnership agreement nor any other agreement requires Denbury to
pursue a business strategy that favors us or utilizes our assets.
Denbury’s directors and officers have a fiduciary duty to make these
decisions in the best interest of the stockholders of
Denbury;
|
|
·
|
Denbury
may compete with us. Denbury owns the largest reserves of CO
2
used
for tertiary oil recovery east of the Mississippi River and may manage
these reserves in a manner that could adversely affect our CO
2
business;
|
|
·
|
our
general partner is allowed to take into account the interest of parties
other than us, such as Denbury, 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 the limitations, might constitute breaches of
fiduciary duty;
|
|
·
|
our
general partner determines the amount and timing of asset purchases and
sales, capital expenditures, borrowings, including for incentive
distributions, issuance of additional partnership securities,
reimbursements and enforcement of obligations to the general partner and
its affiliates, retention of counsel, accountants and service providers,
and cash reserves, each of which can also affect the amount of cash that
is distributed to our unitholders;
|
|
·
|
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
general partner controls the enforcement of obligations owed to us by our
general partner and its affiliates;
|
|
·
|
our
general partner decides whether to retain separate counsel, accountants or
others to perform services for us;
and
|
|
·
|
in
some instances, our general partner may cause us to borrow funds in order
to permit the payment of distributions even if the purpose or effect of
the borrowing is to make incentive
distributions.
|
Denbury
is not obligated to enter into any transactions with (or to offer any
opportunities to) us, although we expect to continue to enter into substantial
transactions and other activities with Denbury and its subsidiaries because of
the businesses and areas in which we and Denbury currently operate, as well as
those in which we plan to operate in the future.
Further,
Denbury’s beneficial ownership interest in our outstanding partnership interests
could have a substantial effect on the outcome of some actions requiring partner
approval. Accordingly, subject to legal requirements, Denbury makes the final
determination regarding how any particular conflict of interest is
resolved.
Some more
recent transactions in which we, on the one hand, and Denbury and its
subsidiaries, on the other hand, had a conflict of interest
include:
|
·
|
transportation
services
|
|
·
|
pipeline
monitoring services; and
|
|
·
|
CO
2
volumetric production payment.
|
Even
if unitholders are dissatisfied, they cannot easily remove our general
partner.
Unlike
the holders of common stock in a corporation, unitholders have only limited
voting rights on matters affecting our business and, therefore, limited ability
to influence management’s decisions regarding our business.
Unitholders
did not elect our general partner or its board of directors and will have no
right to elect our general partner or its board of directors on an annual or
other continuing basis. The board of directors of our general partner is chosen
by the stockholders of our general partner. In addition, if the unitholders are
dissatisfied with the performance of our general partner, they will have little
ability to remove our general partner. As a result of these limitations, the
price at which the common units trade could be diminished because of the absence
or reduction of a takeover premium in the trading price.
The vote
of the holders of at least a majority of all outstanding units (excluding any
units held by our general partner and its affiliates) is required to remove our
general partner without cause. If our general partner is removed without cause,
(i) Denbury will have the option to acquire a substantial portion of our
Mississippi pipeline system at 110% of its then fair market value, and (ii) our
general partner will have the option to convert its interest in us (other than
its common units) into common units or to require our replacement general
partner to purchase such interest for cash at its then fair market value. In
addition, unitholders’ voting rights are further restricted by our partnership
agreement provision providing that any units held by a person that owns 20% or
more of any class of units then outstanding, other than our general partner, its
affiliates, their transferees, and persons who acquired such units with the
prior approval of the board of directors of our general partner, cannot vote on
matters relating to the succession, election, removal, withdrawal, replacement
or substitution of our general partner. Our partnership agreement also contains
provisions limiting the ability of unitholders to call meetings or to acquire
information about our operations, as well as other provisions limiting the
unitholders’ ability to influence the manner of direction of
management.
As a
result of these provisions, the price at which our common units trade may be
lower because of the absence or reduction of a takeover premium.
The
control of our general partner may be transferred to a third party without
unitholder consent, which could affect our strategic direction and
liquidity.
Our
general partner may transfer its general partner interest to a third party in a
merger or in a sale of all or substantially all of its assets without the
consent of the unitholders. Furthermore, there is no restriction in our
partnership agreement on the ability of the owner of our general partner from
transferring its ownership interest in our general partner to a third party. The
new owner of our general partner would then be in a position to replace the
board of directors and officers of our general partner with its own choices and
to control the decisions made by the board of directors and
officers.
In
addition, unless our creditors agreed otherwise, we would be required to repay
the amounts outstanding under our credit facilities upon the occurrence of any
change of control described therein. We may not have sufficient funds available
or be permitted by our other debt instruments to fulfill these obligations upon
such occurrence. A change of control could have other consequences to us
depending on the agreements and other arrangements we have in place from time to
time, including employment compensation arrangements.
Our
general partner and its affiliates or members of the Davison family 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, 2008 our general partner and its affiliates own 4,028,096
(approximately 10.2%) of our common units and members of the Davison family
owned 11,781,379 (approximately 30%) of 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, the sale could reduce the market price of common units. Our
partnership agreement, and other agreements to which we are party, allow our
general partner and certain of its subsidiaries to cause us to register for sale
the partnership interests held by such persons, including common units. These
registration rights allow our general partner and its subsidiaries to request
registration of those partnership interests and to include any of those
securities in a registration of other capital securities by
us Additionally, we have filed a shelf registration statement for the
units held by members of the Davison family, and the Davison family may sell
their common units at any time, subject to certain restrictions under securities
laws.
Our
general partner has anti-dilution rights.
Whenever
we issue equity securities to any person other than our general partner and its
affiliates, our general partner and its affiliates have the right to purchase an
additional amount of those equity securities on the same terms as they are
issued to the other purchasers. This allows our general partner and its
affiliates to maintain their percentage partnership interest in us. No other
unitholder has a similar right. Therefore, only our general partner may protect
itself against dilution caused by the issuance of additional equity
securities.
Due
to our significant relationships with Denbury, adverse developments concerning
Denbury could adversely affect us, even if we have not suffered any similar
developments.
Through
its subsidiaries, Denbury controls our general partner, is a significant
stakeholder in our limited partner interests and has historically, with its
affiliates, employed the personnel who operate our businesses. In
addition, we are parties to numerous agreements with Denbury, including the
lease of the NEJD CO
2
pipeline
and the transportation arrangements related to the Free State
pipeline. Denbury is also a significant customer of our Mississippi
System. See “Our General Partner and Our Relationship with Denbury
Resources Inc.” under Item 1 – Business. We could be adversely
affected if Denbury experiences any adverse developments or fails to pay us
timely.
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 common units at an undesirable time or price.
If at any
time our general partner and its affiliates own more than 80% of the common
units, our general partner will have the right, but not the obligation, which it
may assign to any of its affiliates or to us, to acquire all, but not less than
all, of the common 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 common 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 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 debt service requirements. The value of our units and other limited
partner interests will 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.
An
impairment of goodwill and intangible assets could adversely affect some of our
accounting and financial metrics and, possibly, result in an event of default
under our revolving credit facility.
At
December 31, 2008, our balance sheet reflected $325.0 million of
goodwill and $166.9 million of intangible assets. Goodwill is recorded when
the purchase price of a business exceeds the fair market value of the tangible
and separately measurable intangible net assets. Generally accepted accounting
principles in the United States (“GAAP”) require us to test goodwill for
impairment on an annual basis or when events or circumstances occur indicating
that goodwill might be impaired. Long-lived assets such as intangible assets
with finite useful lives are reviewed for impairment whenever events or changes
in circumstances indicate that the carrying amount may not be recoverable.
Financial and credit markets volatility directly impacts our fair value
measurements for tests of impairment through our weighted average cost of
capital that we use to determine our discount rate. If we determine
that any of our goodwill or intangible assets were impaired, we would be
required to record the impairment. Our assets, equity and earnings as
recorded in our financial statements would be reduced, and it could adversely
affect certain of our borrowing metrics. While such a write-off would
not reduce our primary borrowing base metric of EBITDA, it would reduce our
consolidated capitalization ratio, which, if significant enough, could result in
an event of default under our credit agreement. At December 31, 2008,
such a write-off would need to exceed $330 million in order to result in an
event of default.
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 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 us 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.
In
addition, 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. Any change to current law could negatively
impact the value of an investment in our common units. In addition,
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. Imposition of any such taxes may substantially reduce the
cash available for distribution to our unitholders.
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 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 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, and these costs will reduce our cash available for
distribution.
Unitholders
will be required to pay taxes on income 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 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 even the tax
liability that results from that income.
Tax
gain or loss on disposition of common units could be different 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 is less than their original cost. A substantial
portion of the amount realized, whether or not representing gain, may be
ordinary income. In addition, 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 foreign persons face unique tax issues from owning 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), and non-U.S. persons raises issues unique to them. For example,
a significant amount of our income allocated to organizations exempt from
federal income tax, including individual retirement accounts and other
retirement plans, may be unrelated business taxable income and will be taxable
to such a unitholder. Distributions to non-U.S. persons will be reduced by
withholding tax at the highest effective tax rate applicable to individuals, and
non-U.S. persons will be required to file federal income tax returns and pay tax
on their share of our taxable income.
We
will treat each purchaser of 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 common units, we adopt
depreciation and amortization positions that may not conform with all aspects of
applicable Treasury regulations. A successful IRS challenge to those positions
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 the 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 25 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 unitholders’ responsibility to file all 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.
We
have adopted certain valuation methodologies that may result in a shift of
income, gain, loss and deduction between our general partner and our
unitholders. The IRS may challenge this treatment, which could adversely affect
the value of the common units.
When we
issue additional common units or engage in certain other transactions, we
determine the fair market value of our assets and allocate any unrealized gain
or loss attributable to our assets to the capital accounts of our unitholders
and our general partner. Our methodology may be viewed as
understating the value of our assets. In that case, there may be a
shift of income, gain, loss and deduction between certain unitholders and our
general partner, which may be unfavorable to such
unitholders. Moreover, subsequent purchasers of common units may have
a greater portion of their Internal Revenue Code Section 743(b) adjustment
allocated to our tangible assets and a lesser portion allocated to our
intangible assets. The IRS may challenge our methods, or our
allocation of the Section 743(b) adjustment attributable to our tangible and
intangible assets, and allocations of income, gain, loss and deduction between
our general partner and certain of our unitholders.
A
successful IRS challenge to these methods or allocations could adversely affect
the amount of taxable income or loss being allocated to our
unitholders. It also could affect the amount of gain from a
unitholder’s sale of common units and could have a negative impact on the value
of the common units or result in audit adjustments to the unitholder’s tax
returns.
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 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-1’s) 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 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. U
nresolv
ed Staff Comments
None.
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 of the
Notes to Consolidated Financial Statements for the future minimum rental
payments. Such information is incorporated herein by
reference.
Item
3. Legal Pro
ceedi
ngs
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 of the Notes to Consolidated Financial
Statements.)
Item
4. Subm
issio
n of Matters to a Vote of Security
Holders
No
matters were submitted to a vote of the security holders during the fiscal year
covered by this report.
Part
III
Item
10. Directors, Executive
Officer
s and Corporate
Governance
Management
of Genesis Energy, L.P.
Our
general partner manages our operations and activities. Our general partner is
not elected by our unitholders and will not be subject to re-election on a
regular basis in the future. Unitholders are not entitled to elect the directors
of our general partner or directly or indirectly participate in our management
or operation. However, in connection with the Davison acquisition, our general
partner has agreed to let the Davison family designate two directors through
July 27, 2010 and, subsequent to that date, one director so long as it holds at
least 10% of our common units. Our general partner owes a fiduciary
duty to our unitholders, but our partnership agreement contains various
provisions modifying and restricting the fiduciary duty. Our general partner is
liable, as general partner, for all of our debts (to the extent not paid from
our assets), except for indebtedness or other obligations that are made
expressly nonrecourse to it. Our general partner therefore may cause us to incur
indebtedness or other obligations that are nonrecourse to it.
The
directors of our general partner oversee our operations. As of February 28, 2009
our general partner has eleven directors. Denbury, indirectly, elects all
members to the board of directors of our general partner other than the Davison
appointee. Currently nine members of the board of directors, which we
refer to as our Board, were selected by Denbury and two were selected by the
Davisons. The independence standards established by the
NYSE Alternext US (formerly the American Stock Exchange) require us to
have at least three independent directors on the
Board. NYSE Alternext US does not require a listed
limited partnership like us to have a majority of independent directors on the
Board of our general partner or to establish a compensation committee or a
nominating committee. Although we currently have a compensation
committee, it does not satisfy the independence standards established by
NYSE Alternext US, and we are not required to maintain a compensation
committee in the future.
The
compensation committee of our general partner oversees compensation decisions
for the employees of our general partner, as well as the compensation plans of
our general partner. The members of the Compensation Committee are
Gareth Roberts and Susan O. Rheney, both of whom are non-employee directors of
our general partner. The Compensation Committee adopted a written
Compensation Committee charter that is available on our website.
In
addition, our general partner has an audit committee composed of directors who
meet the independence and experience standards established by
NYSE Alternext US and the Securities Exchange Act of 1934, as
amended. Susan O. Rheney, David C. Baggett and
Martin G. White serve as the members of the audit
committee. The audit committee assists the board in its oversight of
the quality and integrity of our financial statements and our compliance with
legal and regulatory requirements and partnership policies and controls. The
audit committee has the following responsibilities:
|
·
|
has
the sole authority to retain and terminate our independent registered
public accounting firm, approve all auditing services and related fees and
the terms thereof, and pre-approve any non-audit services to be rendered
by our independent registered public accounting
firm;
|
|
·
|
is
responsible for confirming the independence and objectivity of our
independent registered public accounting
firm;
|
|
·
|
can
help us resolve conflicts of interest;
and
|
|
·
|
oversees
our anonymous complaint procedure established for our
employees.
|
Our
independent registered public accounting firm is given unrestricted access to
the audit committee. The Board believes that Susan O. Rheney qualifies as
an audit committee financial expert as such term is used in the rules and
regulations of the SEC. The audit committee adopted a written Audit
Committee Charter in August 2003. The full text of the Audit
Committee Charter is available on our website.
In
addition, the members of our Audit Committee may review specific matters that
the board believes may involve conflicts of interest. When requested
to by our general partner, the audit committee determines if the resolution of
the conflict of interest is fair and reasonable to us. The members of the audit
committee may not be officers or employees of our general partner or directors,
officers, or employees of its affiliates, and must meet the independence and
experience standards established by the NYSE Alternext US and the Securities
Exchange Act of 1934, as amended, to serve on an audit committee of a board of
directors, and certain other requirements. Any matters approved by the audit
committee in good faith will be conclusively deemed to be fair and reasonable to
us, approved by all of our partners, and not a breach by our general partner of
any duties it may owe us or our unitholders.
As is
common with MLPs, we do not have any employees. All of our executive management
personnel are employees of our general partner. Such personnel devote all of
their time to conduct our business and affairs. The officers of our general
partner manage the day-to-day affairs of our business, operate our business, and
provide us with general and administrative services. We reimburse our general
partner for allocated expenses of operational personnel who perform services for
our benefit, allocated general and administrative expenses and certain direct
expenses.
Directors
and Executive Officers of our general partner
Set forth
below is certain information concerning the directors and executive officers of
our general partner. All executive officers serve at the discretion
of our general partner.
Name
|
|
Age
|
|
Position
|
|
|
|
|
|
Gareth
Roberts
|
|
56
|
|
Director
and Chairman of the Board
|
Grant
E. Sims
|
|
53
|
|
Director
and Chief Executive Officer
|
Mark
C. Allen
|
|
40
|
|
Director
|
David
C. Baggett
|
|
47
|
|
Director
|
James
E. Davison
|
|
71
|
|
Director
|
James
E. Davison, Jr.
|
|
42
|
|
Director
|
Ronald
T. Evans
|
|
46
|
|
Director
|
Susan
O. Rheney
|
|
49
|
|
Director
|
Phil
Rykhoek
|
|
52
|
|
Director
|
J.
Conley Stone
|
|
77
|
|
Director
|
Martin
G. White
|
|
63
|
|
Director
|
Joseph
A. Blount, Jr.
|
|
48
|
|
President
and Chief Operating Officer
|
Robert
V. Deere
|
|
54
|
|
Chief
Financial Officer
|
Ross
A. Benavides
|
|
55
|
|
Senior
Vice President, General Counsel and Secretary
|
Karen
N. Pape
|
|
50
|
|
Senior
Vice President and
Controller
|
Gareth
Roberts has served as a director and chairman of the Board since May
2002. Mr. Roberts is President, Chief Executive Officer and a
director of Denbury Resources Inc. and has been employed by Denbury since
1992.
Grant E.
Sims has served as Director and Chief Executive Officer of our general partner
since August 2006. 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.
Mark C.
Allen has served as a director of our general partner since June
2006. Mr. Allen is Vice President and Chief Accounting Officer of
Denbury, and has been employed by Denbury since April 1999.
David C.
Baggett has served as a director of our general partner since March
2008. Mr. Baggett is the founder and managing partner of Opportune
LLP, a financial consulting firm formed in June 2005. From April 2003
until June 2005 he was a private investor. From October 1998 until
April 2003, he held various positions at American Plumbing and Mechanical,
including President, Chief Operating Officer, Chief Financial Officer and board
member.
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.
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 Bank and serves on its executive, audit,
finance and compensation committees.
Ronald T.
Evans has served as a director of our general partner since May
2002. Mr. Evans is Senior Vice President of Reservoir Engineering of
Denbury and has been employed by Denbury since September 1999.
Susan O.
Rheney has served as a director of our general partner since March
2002. Ms. Rheney is a private investor and formerly was a principal
of The Sterling Group, L.P., a private financial and investment organization,
from 1992 to 2000. Ms. Rheney serves on the board of directors, audit
committee and finance committee of CenterPoint Energy, Inc., an energy delivery
company headquartered in Texas.
Phil
Rykhoek has served as a director of our general partner since May
2002. Mr. Rykhoek is Chief Financial Officer, Senior Vice President,
Secretary and Treasurer of Denbury, and has been employed by Denbury since
1995.
J. Conley
Stone has served as a director of our general partner since January
1997. From 1987 to his retirement in 1995, he served as President,
Chief Executive Officer, Chief Operating Officer and Director of Plantation Pipe
Line Company, a common carrier liquid petroleum products pipeline
transporter.
Martin G.
White has served as a director of our general partner since March
2008. Mr. White retired in 2006 from Occidental Chemical Corporation
(OxyChem) after most recently serving as Vice President of OxyChem’s joint
venture, OxyVinyls, a position he held since the formation of OxyVinyls in May
1999.
Joseph A.
Blount, Jr. has served as President and Chief Operating Officer of our general
partner since August 2006. Mr. Blount served as President and Chief
Operating Officer of Unocal Midstream & Trade from March of 2000 to
September of 2005. Upon the acquisition of Unocal by Chevron in
September of 2005, Mr. Blount left to pursue personal interests, including
investments.
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) for the last five years, and in positions of
increasing responsibility with Shell for five years prior to that
appointment.
Ross A.
Benavides has served as General Counsel and Secretary of our general partner
since December 1999. He previously also held the position of Chief
Financial Officer from October 1998 until October 2008.
Karen N.
Pape served as Vice President and Controller of our general partner since March
2002, and was named Senior Vice President in 2007. Ms. Pape served as
Controller and as Director of Finance and Administration of our general partner
since December 1996.
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,
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 the officers and directors
of our general partner and persons who own more than ten percent of a registered
class of our equity securities to file reports of ownership and changes in
ownership with the SEC and the NYSE Alternext US. 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 one filing
that was not timely made by Mr. Martin G. White, Director, who failed to timely
file a Form 4 reporting the purchase of 100 common units in September
2008. Such transaction was subsequently included on a Form
5.
Item
11. Executive C
omp
ensation
We are
managed by our general partner, who employs our executive officers and
employees. Under the terms of our partnership agreement, we are
required to reimburse our general partner for expenses relating to managing our
operations, including salaries and bonuses of employees employed on our behalf,
as well as the costs of providing benefits to such persons under employee
benefit plans and for the costs of health and life insurance. Our
general partner has agreed that it will not seek reimbursement for compensation
pursuant to the Class B Membership Interest Awards and deferred compensation
awards discussed below. See "Certain Relationships and Related
Transactions."
Compensation
Discussion and Analysis
Compensation
Committee.
The compensation committee of our Board, or the
Committee, consists of the chairman of the board of directors and one
independent director. The Committee is responsible for making
recommendations to the Board regarding compensation policies, incentive
compensation policies and employee benefit plans, and recommends awards
thereunder. The Committee recommends specific compensation levels for
our named executive officers, or NEOs. The Committee also administers our Stock
Appreciation Rights Plan, 2007 Long-Term Incentive Plan, Bonus Plan, and
Severance Protection Plan. Our Board has adopted a Compensation Committee
Charter setting forth the Committee’s purpose and
responsibilities.
Board Process
.
Following
the end of the year, management reviews the compensation of all employees of our
general partner, and, based on their review, the results of the Partnership as a
whole, and the internal recommendations of supervisory personnel, makes a
proposal to the Committee. Final review of this recommendation is
made by the Committee and the Board in February. Depending on the
magnitude of the anticipated changes, there may also be additional Committee
meetings and discussions with management in advance of the February
meeting.
Committee and Board
Approval.
The Committee approves all compensation and
long-term awards for all executive officers, taking into consideration the
recommendation of the Senior Executives (defined below) with regard to
compensation for the Other Executives (defined below). The Committee
also reviews and approves our overall compensation programs for all employees,
taking into consideration the recommendation of management described above, and
any significant changes to these programs. The Committee administers
all of our compensation plans (other than our 401(k) plan, health and other
fringe benefit plans), including our Bonus Plan, 2007 Long-Term Incentive
Compensation Plan, and Stock Appreciation Rights Plan, under which all of our
long-term equity awards are granted. The Board considers, reviews and
ratifies the compensation package based on a recommendation from the
Committee. Following approval of the entire compensation program in
February, any applicable salary increases and/or long-term incentive are made or
awarded in the first quarter of the year. Bonuses are paid in
March.
Executive
Officers. Our NEOs consist of our Senior Executives: Grant E. Sims,
our chief executive officer, Joseph A. Blount, Jr., our president and chief
operating officer and Robert V. Deere, our chief financial officer. Our Other
Executives: consist of Ross A. Benavides, our senior vice president and general
counsel, and Karen N. Pape, our senior vice president and
controller.
Compensation
Objectives and Philosophy
. Our compensation programs are
designed by the Committee to attract, retain, and motivate key personnel who
possess the skills and qualities necessary to perform effectively in an MLP in
the industries in which we operate. We pay base salaries at a level
that we feel are appropriate for the skills and qualities of the individual
employees based on their past performance and current responsibilities with the
Partnership. The other components of employees’ compensation are
consistent among employee groups and generally are proportional to base
salary. We reward employees primarily for the effort and results of
the Partnership as a whole, the results of the business segment, and for
individual performance.
On
December 31, 2008, we finalized the compensation arrangements (including
underlying documentation) for our Senior Executives. These
arrangements are intended to incentivize our Senior Executives to create value
for our common unitholders by maintaining and increasing (over time) the
distribution rate we pay on our common units.
As
described in more detail below, we believe that the combination of base
salaries, cash bonuses, Long-Term Incentive Plans and the Class B Membership
Interests provides 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 and employees with the interests of our common
unitholders and Denbury, the owner of the majority of our general
partner. Our Bonus Plan is driven by the generation of available
cash, which is an important metric of value for our unitholders, before reserves
and bonuses, and our safety record. Our Stock Appreciation Rights
Plan and 2007 Long Term Incentive Plan are linked primarily to the appreciation
in our common unit price. The Class B Membership Interests have the
potential to provide participation in our incentive distribution rights to our
Senior Executives, as well as redemption of those rights in specified
circumstances, including most events involving their termination of
employment. The level of participation by our Senior Executives in
the Class B Membership Interests is largely driven by the generation of
available cash as well as the level of distributions we pay to our common
unitholders and general partner.
Components
of our Compensation Program. Two distinct compensation programs apply
to our employees. The first applies to our Senior Executives, the
second applies to our Other Executives and to certain other
employees. The elements of the compensation program for our Senior
Executives consist of:
|
·
|
an
ability to earn a increasing share of the cash distributions attributable
to the incentive distribution rights (IDRs) held by our general partner,
referred to as the Class B Membership Interests below,
and
|
|
·
|
other
compensation (including reimbursement for certain self-employment taxes
and other costs borne by the executive as a result of their status as
members of our general partner).
|
The
elements of our Company-wide compensation program that applies to the Other
Executives and to certain other employees (excluding the Senior Executives)
consist of:
|
·
|
annual
cash bonuses (performance-based cash incentive
compensation),
|
|
·
|
a
Stock Appreciation Rights Plan (however participation will cease in
2009),
|
|
·
|
our
2007 Long Term Incentive Plans (phantom units and distribution equivalent
rights),
|
|
·
|
a
Severance Protection Plan, and
|
|
·
|
other
compensation (including contributions to the 401(k) plan and annual term
life insurance premiums).
|
The Other
Executives’ compensation programs are generally available to other members of
our management team.
Base
Salaries.
Senior
Executives
. On December 31, 2008, each of our Senior
Executives, Messrs. Sims, Blount and Deere, entered into an
employment agreement with our general partner under which he will receive an
annual salary of $340,000, $300,000, and $369,600, respectively, subject to
certain upward adjustments. Each senior executive’s annual salary
rate will be increased by (i) $30,000 if our market capitalization is at least
$1.0 billion for any 90-consecutive-day period, and (ii) an additional amount
equal to 10% of his then effective base salary each time our market
capitalization increases by an additional $300 million. See
additional disclosure in the Employment Agreements section below.
Other
Executives.
The Committee seeks to establish and maintain base
salaries for our Other Executives at a competitive level based on several
factors. These factors include our objectives, the nature and
responsibility of the position (considering our size and complexity), the
expertise of the individual executive, and the recommendation of the Senior
Executives. In making recommendations, the Committee exercises
subjective judgment using no specific weights for these factors. Base
salaries are the primary part of the compensation package whereby a distinction
is made for individual performance of the Other Executives.
The Other
Executives received salary increases mid-year in 2007 and did not receive salary
increases for 2008. For 2009, the Other Executives, Mr. Benavides and
Ms. Pape, will receive a salary increase of three percent to a base
salary of $234,300, and a salary increase of thirteen percent to a base salary
of $225,000, respectively. For 2008, all employees other than the
Senior Executives and Other Executives received average salary increases of
approximately four percent. For 2009, other employees will average
salary increases of approximately three percent.
The
Class B Membership Interest in Our General Partner.
Senior
Executives.
As part of finalizing the compensation
arrangements for our Senior Executives in December 2008, our general partner
awarded them an equity interest in our general partner as long-term incentive
compensation. These Class B Membership Interests compensate the holders thereof
by providing rewards based on increased shares of the cash distributions
attributable to our incentive distribution rights (or IDRs) to the extent we
increase Cash Available Before Reserves, or CABR (defined below) (from which we
pay distributions on our common units) above specified
targets. CABR generally means Available Cash before Reserves,
as defined in Item 7 – “Management’s Discussion and Analysis” above, less
Available Cash before Reserves generated from specific transactions with our
general partner and its affiliates (including Denbury Resources Inc.) The Class
B Membership Interests do not provide any Senior Executive with a direct
interest in any assets (including our IDRs) owned by our general
partner.
These
arrangements are intended to incentivize our Senior Executives to create value
for our common unitholders and general partner by maintaining and increasing
(over time) the distribution rate to them. Each holder of a Class B
Membership Interest is entitled (a) to receive from our general partner
quarterly cash distributions in an amount equal to a varying percentage of the
incentive distributions we make to our general partner, and (b) upon the
occurrence of specified events and circumstances, to receive from our general
partner a payment of cash (or, in certain circumstances, common units owned by
our general partner) in redemption of such Class B Membership
Interests.
Our Board
has made the following awards of Class B Membership Interests:
|
|
Class
B
|
|
|
|
|
|
Membership
|
|
Potential
|
|
|
Interest
|
|
IDR
|
Senior
Executive
|
|
Percentage
|
|
Percentage
|
|
|
|
|
|
|
|
Grant
E. Sims
|
|
|
38.7
|
%
|
|
|
7.74
|
%
|
Joseph
A. Blount, Jr.
|
|
|
33.3
|
|
|
|
6.66
|
|
Robert
V. Deere
|
|
|
14.0
|
|
|
|
2.80
|
|
Total
Awarded
|
|
|
86.0
|
|
|
|
17.20
|
|
Available
for Future Awards
|
|
|
14.0
|
|
|
|
2.80
|
|
Total
|
|
|
100.0
|
%
|
|
|
20.00
|
%
|
Our
general partner is not obligated to award the remaining 14.0% of the unissued
Class B Membership Interests.
The
potential IDR percentage will be subject to the effects of vesting and future
levels of available cash and distributions to our common unitholders and general
partner, as discussed below, in determining the portion of the
general partner’s IDRs distributable to them.
The
amount of the quarterly cash distribution, if any, a Class B Membership Interest
holder is entitled to receive from our general partner will vary depending on
the amount of cash we distribute in respect of our IDRs and the amount by which
the growth in Cash Available before Reserves, or CABR, per common unit for an
annual period ending with the current quarter exceeds specified base
levels. CABR generally means Available Cash before Reserves, as
defined in Item 7 – “Management’s Discussion and Analysis” above, less Available
Cash before Reserves generated from specific transactions with our general
partner and related Denbury affiliates In other words, all other
things being equal, if our Available Cash before Reserves increases on a per
unit basis (other than from specific transactions with our general partner and
its affiliates) above specified base levels and our distribution rate on our
common units increases above specified thresholds such that our incentive
distributions to our general partner increase, each Senior Executive would be
entitled to receive distributions from our general partner that constitute a
larger share of our general partner’s IDR distributions.
Each
holder will be entitled to receive a quarterly distribution in an amount equal
to the product of (i) the IDR distributions made by us to our general
partner and attributable to the applicable quarter, (ii) that Senior Executive’s
Class B Membership Interest percentage and (iii) the percentage associated
with the growth in CABR per common unitt actually achieved for an annual period
ending with the current quarter over specified base levels. The CABR
per unit base levels, as well as the related target percentages, are set forth
below. Based on the CABR per unit for the annual period ending at December 31,
2008, the percentages associated with our CABR per unit were 14% for
Messrs. Sims and Blount and zero for Mr. Deere. For purposes of
determining the applicable base percentage for a relevant quarter, Messrs. Sims’
and Blount’s base levels per unit are $0.925, and Mr. Deere’s base level per
unit is $1.975.
|
|
Applicable
|
Excess
of our CABR per Unit
|
|
Percentage
|
for
the relevant quarter over
|
|
(for
the relevant
|
each
Senior Executive's Base Amount per Unit:
(1)
|
|
quarter)
|
|
|
|
Excess
of $0.14 or less of CABR per Unit over Senior Executive's Base Amount per
Unit
|
|
0%
|
Excess
of $0.14 through $0.29 of CABR per Unit over Senior Executive's Base
Amount per Unit
|
|
2%
|
Excess
of $0.30 through $0.44 of CABR per Unit over Senior Executive's Base
Amount per Unit
|
|
4%
|
Excess
of $0.45 through $0.59 of CABR per Unit over Senior Executive's Base
Amount per Unit
|
|
6%
|
Excess
of $0.60 through $0.74 of CABR per Unit over Senior Executive's Base
Amount per Unit
|
|
8%
|
Excess
of $0.75 through $0.89 of CABR per Unit over Senior Executive's Base
Amount per Unit
|
|
10%
|
Excess
of $0.90 through $1.04 of CABR per Unit over Senior Executive's Base
Amount per Unit
|
|
12%
|
Excess
of $1.05 through $1.19 of CABR per Unit over Senior Executive's Base
Amount per Unit
|
|
14%
|
Excess
of $1.20 through $1.34 of CABR per Unit over Senior Executive's Base
Amount per Unit
|
|
16%
|
Excess
of $1.35 through $1.49 of CABR per Unit over Senior Executive's Base
Amount per Unit
|
|
18%
|
Excess
of $1.50 or greater of CABR per Unit over Senior Executive's Base Amount
per Unit
|
|
20%
|
___________
(1) Senior Executive’s Base
Amount per Unit is specified in his Class B Membership Interest Award
Agreement. The base amount for Messrs. Sims and Blount is
$0.925. The base amount for Mr. Deere is $1.975
.
For
example, our Senior Executives received the following distributions from our
general partner in the first quarter of 2009 with respect to the quarter ended
December 31, 2008:
|
|
Distribution
|
|
Senior
Executive
|
|
Amount
|
|
|
|
|
|
Grant
E. Sims
|
|
$
|
44,595
|
|
Joseph
A. Blount, Jr.
|
|
|
38,373
|
|
Robert
V. Deere
|
|
|
-
|
|
Total
|
|
$
|
82,968
|
|
The above
distributions were calculated as follows (in thousands, except per unit
amounts):
|
|
Total
|
|
|
|
|
|
Available
Cash before Reserves generated for the four quarters
|
|
$
|
89,784
|
|
Less: Adjustment
to Available Cash before Reserves relating to specific Transaction with
our general partner and its affiliates
|
|
|
11,628
|
|
CABR
for the four quarters
|
|
$
|
78,156
|
|
|
|
|
|
|
Weighted
average units outstanding, including implied general partner units
(1)
|
|
|
39,089
|
|
|
|
|
|
|
Adjusted
annual CABR at December 31, 2008 per adjusted unit
(2)
|
|
$
|
2.00
|
|
|
|
|
|
|
Base
amount for Messrs. Sims and Blount
|
|
|
0.925
|
|
|
|
|
|
|
Excess
of CABR per Unit over base amount
|
|
$
|
1.075
|
|
|
|
|
|
|
Applicable
Percentage for Messrs. Sims and Blount for the quarter
|
|
|
14
|
%
|
____________
(1) Adjusted
units outstanding is calculated separately for each quarter in the annual period
and applied to the CABR for the respective quarter. The calculation
excludes common units issued to our general partner and its affiliates resulting
from any transaction between us and our general partner and its affiliates after
March 31, 2008.
(2) This
amount represents the sum of the individual quarterly calculations in the annual
period.
The
distribution that Mr. Sims received for the quarter is calculated as the product
of (i) $823,093 (which is the amount of IDR distributions
attributable to that quarter that we actually paid to our general partner) (ii)
the CABR-related percentage of 14%, and (iii) Mr. Sims Class B Membership
Interest of 38.7%. The calculation of Mr. Blount’s distribution
amount is similar to that of Mr. Sims utilizing his Class B Membership Interest
of 33.3%. Mr. Deere was not entitled to a distribution for the
quarter because the adjusted annual CABR per adjusted unit only exceeded his
base amount of $1.975 by $0.025.
In
addition, our general partner has agreed to redeem each Senior Executive’s
equity interest for cash (or, in specified circumstances, for common units owned
by our general partner) in certain circumstances including most events involving
termination of that Senior Executive’s employment with our general partner or
when a change of control occurs. The amount of the redemption payment
will depend on the nature of the triggering event (i.e. termination with or
without cause or good reason or due to death, disability or a change of control)
and/or the time at which the triggering event occurs. In general, each Senior
Executive will be entitled to receive a redemption amount if our general partner
did not terminate his employment for cause, which redemption amount is subject
to vesting as described below.
The
redemption amount for each executive will be an amount equal to the vested
portion of the excess, if any, of (a) the then current value of the general
partner’s future IDRs multiplied by the product of (i) the relevant
member’s Class B Membership Interest percentage and (ii) his then effective
CABR-related percentage over (b) $1,007,229 for Mr. Sims, $866,685 for Mr.
Blount, and zero for Mr. Deere. The determined value of our IDRs will
be the present value of the annualized cash flows attributable to the IDRs at
the time of the triggering event discounted at an annual interest rate equal to
the average of the annualized yield of ten specified publicly-traded entities
which are general partners of publicly traded master limited
partnerships. The vesting percentage of each executive will be the
percentage, in general, determined as of the relevant valuation date, indicated
below:
(i)
|
termination
for cause:
|
|
0%
|
(ii)
|
after
a change of control; upon such Class B Member’s termination for good
reason; or upon a termination during the period beginning six months prior
to and ending on a change of control other than termination by our general
partner for cause or termination by the Class B Member without good
reason:
|
|
100%
|
(iii)
|
if
the Class B Member voluntarily terminates his employment other than for
good reason, if termination occurs:
|
|
|
|
(a
)
|
prior
to the 1
st
anniversary of the Class B Member’s award:
|
|
0%
|
|
(b)
|
on
or after the 1
st
anniversary, and prior to the 2
nd
anniversary, of the Class B Member’s award:
|
|
25%
|
|
(c)
|
on
or after the 2
nd
anniversary, and prior to the 3
rd
anniversary, of the Class B Member’s award:
|
|
50%
|
|
(d)
|
on
or after the 3
rd
anniversary, and prior to the 4
th
anniversary, of the Class B Member’s award:
|
|
75%
|
|
(e)
|
after
the 4
th
anniversary of the Class B Member’s award:
|
|
100%
|
On
December 31, 2008, the redemption amount for each Class B Member was zero
($0).To the extent our general partner or any of its affiliates own any of our
common units, a Class B Member may elect to receive any portion of his
redemption payment in the form of such common units (in lieu of cash), the
number of which would be based on the average closing price of our common units
during a specified five trading day period.
In
general, the holders of the Class B Membership Interests will not have any
contractual rights limiting the manner in which our general partner may operate
its business. For example, without obtaining the consent of any
holder of the Class B Membership Interest, our general partner could sell all or
any portion of our IDRs or merge, consolidate or otherwise
reorganize. If our general partner sells all or any portion of our
IDRs, the distribution and redemption payments due to the holders of its Class B
Membership Interest will be determined based on the assets our general partner
receives in exchange for such IDRs.
Our
general partner has agreed that it will not seek reimbursement (on behalf of
itself or its affiliates) under our partnership agreement for the costs of these
Senior Executive compensation arrangements to the extent relating to their
ownership of Class B Membership Interests (including current cash distributions
and redemption payments made by our general partner in respect thereof) and the
deferred compensation amounts. Our general partner has retained its
right to (and intends to) seek reimbursement for the costs of these Senior
Executive compensation arrangements to the extent relating to the employment
agreements (including base salary and fringe benefits) and cash bonuses, if any,
which costs will be borne by us.
Although
our general partner will not seek reimbursement for the costs of the Class B
Membership Interests and deferred compensation plan arrangements, we will record
non-cash expense during the four-year vesting period. The Class
B Membership Interests awarded to our senior executives will be accounted for as
liability awards under the provisions of SFAS 123(R). As such, the
fair value of the compensation cost we record for these awards will be
recomputed at each measurement date and the expense to be recorded will be
adjusted based on that fair value. Management’s estimates of the fair
value of these awards are based on assumptions regarding a number of future
events, including estimates of the Available Cash before Reserves we will
generate each quarter through the final vesting date of December 31, 2012,
estimates of the future amount of incentive distributions we will pay to our
general partner, and assumptions about appropriate discount
rates. Additionally the determination of fair value will be affected
by the distribution yield of ten publicly-traded entities that are the general
partners in publicly-traded master limited partnerships, a factor over which we
have no control. Included within the assumptions used to prepare
these estimates are projections of available cash and distributions to our
common unitholders and general partner, including an assumed level of growth and
the effects of future new growth projects during the four-year vesting
period. At December 31, 2008, Management estimates that the fair
value of the Class B Membership Awards and the related deferred compensation
awards granted to our Senior Executives on that date is approximately $12
million. The fair value of these incentive awards will be recomputed
each quarter beginning with the quarter ending March 31, 2009 through the final
settlement of the awards. Compensation expense of $3.4 million was
recorded in the fourth quarter of 2007 related to the previous arrangements
between our general partner and our Senior Executives. The fair value
to be recorded by us as compensation expense will be the excess of the
recomputed estimated fair value over the previously recorded $3.4
million. Due to the vesting conditions for the awards, the amount to
which the Senior Executives were entitled on December 31, 2008 for the Class B
Membership Awards and the related deferred compensation was zero.
Management’s estimates of fair value are made in order to record non-cash
compensation expense over the vesting period, and do not necessarily represent
the contractual amounts payable under these awards at December 31,
2008.
Other
Executives.
Only our Senior Executives may hold Class B
Membership Interests.
Bonuses
and Deferred Compensation Awards.
Senior
Executives.
In connection with the Senior Executives’
compensation agreements, we paid a bonus to each of Messrs. Sims and Blount of
$107,751 and $97,599, respectively, in December 2008.
Additionally,
our general partner adopted an unfunded, nonqualified deferred compensation plan
and made awards under that plan to Messrs. Sims and Blount in a maximum amount
of $1,007,229 and $866,685, respectively.
Our
deferred compensation plan provides Messrs. Sims and Blount with incentive
compensation that is deferred until after such participant’s separation from
service with our general partner. Under that plan, Messrs. Sims and
Blount were awarded a maximum deferred compensation amount equal to the lesser
of $1,007,229 for Mr. Sims and $866,685 for Mr. Blount, or the value of such
participant’s Class B Membership Interest on the date such interest is valued
for purposes of determining the redemption amount. In general, each
participant will be entitled to receive his deferred compensation award to the
same extent he will be entitled to receive a payment in respect of the
redemption of his Class B Membership Interest, subject to the same general
vesting requirements summarized above regarding each executive’s redemption
amount.
Like the
redemption payment, a participant may elect to receive his deferred compensation
payment in the form of our common units (in lieu of cash) to the extent our
general partner or any of its affiliates own any of our common
units.
Bonus Plan for Other
Executives and other employees.
In January 2009, the Committee
of the Board of our general partner approved a bonus program, referred to below
as the “Bonus Plan,” for all employees of our general partner that is applicable
to 2008. The Senior Executives are excluded from participation in the
Bonus Plan. The Bonus Plan is paid at the discretion of our Board
based on the recommendation of the Committee, and can be amended or changed at
any time. Since the determination of whether bonuses will be paid
each year and in what amounts is determined by the Committee on a company-wide
basis, the Other Executives only receive bonuses if other employees receive
bonuses.
The Bonus
Plan is based primarily on the amount of money we generate for distributions to
our unitholders, and is measured on a calendar-year basis. For 2008,
two metrics are 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 generate and our company-wide safety record
improvement. The level of Available Cash before Reserves generated for the year
as a percentage of a target set by our Committee is weighted ninety percent and
the achieved level of the targeted improvement in our safety record is weighted
ten percent. The sum of the weighted percentage achievement of these
targets is multiplied by the eligible compensation and the target percentages
established by our Committee for the various levels of our employees to
determine the maximum general bonus pool.
The general bonus pool will be
distributed as follows:
|
·
|
Each
eligible employee will be eligible to receive a bonus after the end of the
year up to a specified percentage of their year-to-date gross
wages. Certain compensation, such as awards under our Stock
Appreciation Rights Plan, car allowances and relocation expenses, will be
excluded from the calculation. Each employee must be a regular,
full-time active employee, not on probation, at the time the bonus is paid
in order to be eligible to receive a bonus. The date of payment
of the bonuses is at the discretion of management, but is expected to be
before March 15 each year.
|
|
·
|
There
are five levels of participation in the Bonus Plan. Employees in each
level will be eligible for a bonus each year in accordance with the
following table. The determination of what level applies to
each employee will be made by the Committee based on the recommendation of
the Senior Executives.
|
|
·
|
The
percentage of adjusted year-to-date gross wages paid as a bonus will be a
function of the general bonus pool available and the employee’s
Participation Level in the Bonus Plan. The bonus amount each
employee will be eligible to receive will be determined in accordance with
the table shown below. The bonus may be adjusted up or down to
reflect business unit contribution and individual
performance. These adjustments are discretionary and will be
determined by the Senior Executives with approval by the
Committee.
|
Bonus
Targets
|
Job
Classifications
|
|
|
0 -
10%
|
Operations
and administrative clerical personnel
|
0 -
20%
|
Professional/supervisory
personnel
|
0 -
25%
|
Senior
professionals/management personnel
|
0 -
50%
|
Senior
management/executive personnel
|
0 -
100%
|
Key
executive personnel, including the Other
Executives
|
A
separate marketing bonus pool is available for compensating certain marketing
personnel that is based on the contribution of that group to Available Cash
before Reserves. A minimum level of contribution to Available Cash
before Reserves is required before any amounts are allocated to the marketing
bonus pool. Our Other Executives do not participate in this
pool.
The Bonus
Plan is designed to enhance our financial performance by rewarding employees for
achieving financial performance and safety objectives. Since
Available Cash before Reserves 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, we believe the Bonus Plan is
designed to reward employees on a basis that is aligned with the interests of
the unitholders. We believe that this generates a bonus that
represents a meaningful level of compensation for the employee population and
that encourages employees to operate as a unified team to generate results that
are aligned with the interests of the unitholders. By including
safety improvement in the calculation of the Bonus Pool, we encourage our
employees to focus on the impact their job performance has on the environment in
which we operate.
For 2008,
the Committee established a target of approximately $81 million for Available
Cash before Reserves and before bonus expense and related employer tax burdens,
with a hurdle rate of 105%. We achieved 117% of the target which
exceeded the target level set at the beginning of the 2008 for Available Cash
before Reserves. We did not achieve our safety incident rate goal for
2008. As a result, the Bonus Pool for 2008 bonuses to be paid in
March 2009 was calculated as 90% of 117% divided by 105%, or 100%. In accordance
with the Bonus Plan, the total pool available for bonuses for 2008 was $5.1
million. Our Committee approved bonuses totaling $4.5 million, which
represents approximately 15.5 percent of total eligible
compensation. These bonuses were paid in March 2009.
Long-Term
Incentive Compensation and Stock Appreciation Rights.
The 2007
Long-Term Incentive Compensation Plan (2007 LTIP).
Senior
Executives. Our Senior Executives are not eligible and do not
participate in our 2007 LTIP.
Non-Employee Directors,
Other Executives and other Employees.
Our unitholders approved
a Long-Term Incentive Plan on December 18, 2007 which provides for awards of
Phantom Units and Distribution Equivalent Rights to our non-employee directors
and employees. Phantom units are notional units representing unfunded
and unsecured promises to deliver a common unit to the participant should
specified vesting requirements be met. Distribution Equivalent Rights
are rights to receive an amount of cash equal to all or a portion of the cash
distributions made by us during a specified period. The 2007 LTIP is
administered by the Committee. Subject to adjustment as provided in
the 2007 LTIP, awards with respect to up to an aggregate of 1,000,000 units may
be granted under the 2007 LTIP.
The 2007
LTIP is intended to provide a means whereby employees and directors providing
services to us may develop a sense of proprietorship and personal involvement in
our development and financial success through the award of phantom units, and/or
distribution equivalent rights; and the 2007 LTIP allows for various forms of
equity or equity-based awards, providing flexible incentives to employees and
directors.
The
Committee (at its discretion) will designate participants in the 2007 LTIP,
determine the types of awards to grant to participants, determine the number of
units to be covered by any award, and determine the conditions and terms of any
award including vesting, settlement and forfeiture conditions. The
2007 LTIP may be amended or terminated at any time by the Board or the
Committee; however, any material amendment, such as a material increase in the
number of units available under the 2007 LTIP or a change in the types of awards
available under the 2007 LTIP, will also require the approval of our
unitholders. The Committee is also authorized to make adjustments to
the terms and conditions of and the criteria included in awards under the plan
in specified circumstances. The 2007 LTIP is effective until December
18, 2017 or, if earlier, the time which all available units under the 2007 LTIP
have been delivered to participants or the time of termination of the plan by
the Board or the Committee.
In
February 2009, the Committee approved awards granting phantom units with a total
value (assuming a market price of $13 per common unit) as of February 26, 2009
of $0.6 million (47,601 phantom units) to 17 employees of our general
partner. Grants were made to Mr. Benavides and Ms. Pape with values
in amounts of $113,800 (8,750 phantom units) and $100,000 (7,692 phantom units)
respectively, or approximately 50 percent of their base salaries. The
amounts awarded were entirely discretionary and were based on the recommendation
of the Senior Executives to the Committee.
Additionally,
the Committee awarded each non-employee director an award of 3,500 phantom units
on February 26, 2009.
Stock Appreciation Rights
Plan.
Other Executives and
employees.
In December 2003, the Board approved a Stock
Appreciation Rights plan or SAR plan. Under the terms of this plan,
regular, full-time active employees and the members of the Board, excluding the
Senior Executives, are eligible to participate in the plan. The plan
is administered by the Committee, who shall determine, in its full discretion,
the number of rights to award, the grant date of the rights and the formula for
allocating rights to the participants and the strike price of the rights
awarded.
Beginning
in 2009, rights will be awarded to our professional/supervisory personnel,
senior professional/managerial personnel and senior management/executive
personnel. Our Senior Executives and key executive personnel,
including our Other Executives, as well as our directors, will no longer receive
awards under the Stock Appreciation Rights plan. Our operations and
administrative clerical personnel will also no longer participate in this
plan.
In
February 2008, awards of rights were made to all personnel including our Other
Executives. Grants of SARs were made to all personnel in February
2008 totaling 500,983 units. This grant included the personnel of the
Davison entities, who received initial grants in 2008 totaling 387,512 SARs in
individual allocations similar to what they would have received had they been
employed in 2003, and 113,471 SARs to the personnel employed in the operations
we owned prior to the Davison acquisition. The total SARs allocated
to the employees of the legacy operations was approximately the same number of
SARs awarded at the end of 2006. Mr. Benavides and Ms. Pape
received grants at February 14, 2008 of 5,448 and 4,790 rights,
respectively. The number of SARs allocated to these individuals was a
product of the total 113,471 and the ratio of the maximum bonus for Mr.
Benavides and Ms. Pape under the Bonus Plan in effect in 2007 to the total of
the maximum bonuses for all employees who participated in the Bonus Plan in
2007.
The
exercise price of the annual awards of rights has been the average of the
closing market price of our units for the ten days prior to the date of the
grant. This methodology has been used by the Committee for annual
grants so that the exercise price is not unduly influenced by trading of our
units on one particular date. The volume of units that trade each day
is frequently small, such that one or a few small trade can have a significant
influence on the price. Additionally, we may see unusual trading
occur in the late months of the year at prices that do not necessarily
correspond to the latest market prices. For 2009, we will adjust the exercise
price to reflect a more accurate representation of the unit value in the current
market environment, but not below the closing price of our common units on the
grant date. This methodology is subject to change for any grant in the
future. Additional details describing the operation of the SAR plan
are included below.
Other Compensation and
Benefits.
Severance
Benefits. We believe that companies should provide reasonable
severance benefits to employees. With respect to our Other
Executives, these severance benefits should reflect the fact that it may be
difficult for employees to find comparable employment within a short period of
time. Although we typically pay severance when we terminate any
employee unless such termination is for “cause”, we do not have any pre-defined
severance benefits for our Other Executives, except in the case of a change in
control, a plan adopted in June 2005. This plan is described
under “Change of Control” below.
Other Benefits.
Each
Senior Executive is entitled to vacation, medical and health coverage, and
similar fringe benefits received by the Other Executives; provided; however,
that none of our Senior Executives will be eligible to participate in our
general partner’s Stock Appreciation Rights Plan, Severance Protection Plan, or
2007 Long-Term Incentive Plan. Our Senior Executives and Other
Executives participate in our benefit plans on the same terms as our other
employees. These plans include medical, dental, disability and life
insurance, and matching and profit-sharing contributions to our 401(k)
plan. We match up to 100 percent of the first three percent that the
participant contributes to the 401(k) plan and 50 percent of the next three
percent contributed. Additionally, we make a contribution to our
401(k) plan in the amount of three percent as a profit-sharing contribution to
our 401(k) for each eligible employee. As reflected in the Summary
Compensation Table, the cost to Genesis of the 401(k) matching contributions and
profit-sharing contributions and term life premiums aggregated $69,331 in 2008
for our Senior Executives and Other Executives. As a result of their
status as Class B Members in our general partner, our Senior Executives will be
reimbursed for the additional taxes they will owe individually related to
certain benefits they receive from us including medical, dental, disability and
life insurance, and matching and profit-sharing contributions to our 401(k)
plan, as well as the self-employment taxes they will owe. These
reimbursements will begin in 2009.
Our only
retirement benefits are our 401(k) plan and a retirement vesting provision
included in our Stock Appreciation Rights Plan. We do not have any pension plans
or post-retirement medical benefits.
Compensation
Committee Report
The
information contained in this report shall not be deemed to be soliciting
material or filed with the SEC or subject to the liabilities of Section 18 of
the Exchange Act, except to the extent that we specifically incorporate it by
reference into a document filed under the Securities Act of the Exchange
Act.
The
Compensation Committee has reviewed and discussed with management the
Compensation Discussion and Analysis included above. Based on the
review and discussions, the Compensation Committee approved that the
Compensation Discussion and Analysis be included in this Form 10-K.
This
report is submitted by the Compensation Committee.
Gareth
Roberts (Chairman)
Susan O.
Rheney
Executive
Compensation
2008
SUMMARY COMPENSATION TABLE
The
following table summarizes certain information regarding the compensation paid
or accrued by Genesis during 2008 to those persons who served as NEOs at the end
of 2008.
2008
Summary Compensation Table
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Name
& Principal Position
|
|
Year
|
|
Salary
($)
|
|
|
Bonus
(1) ($)
|
|
|
Stock
Awards (2) ($)
|
|
|
Option
Awards (3) ($)
|
|
|
Non-Equity
Incentive Plan Compen- sation (4) ($)
|
|
|
All
Other Compen- sation (5) ($)
|
|
|
Total
($)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Grant E. Sims
(6)
|
|
2008
|
|
|
310,000
|
|
|
|
107,751
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
9,834
|
|
|
|
427,585
|
|
Chief
Executive Officer
|
|
2007
|
|
|
310,000
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,838,476
|
|
|
|
2,148,476
|
|
(Principal
Executive Officer)
|
|
2006
|
|
|
112,077
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
56
|
|
|
|
112,133
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Joseph A. Blount, Jr.
(6)
|
|
2008
|
|
|
270,000
|
|
|
|
97,599
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
19,936
|
|
|
|
387,535
|
|
President
& Chief Operating
|
|
2007
|
|
|
270,000
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,618,984
|
|
|
|
1,888,984
|
|
Officer
|
|
2006
|
|
|
97,615
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
4,449
|
|
|
|
102,064
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Robert V. Deere
(7)
(8)
|
|
2008
|
|
|
89,557
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
621
|
|
|
|
90,178
|
|
Chief
Financial Officer (Principal Financial Officer)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ross A. Benavides
(8)
|
|
2008
|
|
|
227,500
|
|
|
|
170,000
|
|
|
|
65,638
|
|
|
|
(215,195
|
)
|
|
|
-
|
|
|
|
19,584
|
|
|
|
267,527
|
|
Senior
Vice President and
|
|
2007
|
|
|
211,000
|
|
|
|
68,250
|
|
|
|
2,511
|
|
|
|
100,448
|
|
|
|
111,581
|
|
|
|
16,680
|
|
|
|
510,470
|
|
General
Counsel
|
|
2006
|
|
|
195,000
|
|
|
|
-
|
|
|
|
-
|
|
|
|
101,231
|
|
|
|
78,000
|
|
|
|
16,668
|
|
|
|
390,899
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Karen
N. Pape
|
|
2008
|
|
|
200,000
|
|
|
|
180,000
|
|
|
|
58,341
|
|
|
|
(164,728
|
)
|
|
|
-
|
|
|
|
19,356
|
|
|
|
292,969
|
|
Senior
Vice President &
|
|
2007
|
|
|
184,000
|
|
|
|
52,500
|
|
|
|
2,232
|
|
|
|
77,139
|
|
|
|
94,577
|
|
|
|
16,680
|
|
|
|
427,128
|
|
Controller
(Principal Accounting Officer)
|
|
2006
|
|
|
150,000
|
|
|
|
-
|
|
|
|
-
|
|
|
|
77,430
|
|
|
|
60,000
|
|
|
|
15,032
|
|
|
|
302,462
|
|
|
(1)
|
Amounts
in this column represent for Mr. Sims and Mr. Blount represent the amount
that was paid as a bonus at the time of execution of their employment
agreements. Amounts in this column for Mr. Benavides and Ms.
Pape for 2008 represent bonuses paid in March 2009 relative to 2008 under
our bonus program that was effective for 2008. Amounts in this
column for Mr. Benavides and Ms. Pape in 2007 represent the amount that
was paid as a retention bonus in September
2007.
|
|
(2)
|
Amounts
in this column represent the amounts, before consideration of expected
forfeiture rate, that are included in the determination of net income for
the period under the provisions of SFAS 123(R) for awards of phantom units
under our 2007 LTIP. The forfeiture rate that was applied to
these awards at December 31, 2008 and 2007 was
zero.
|
|
(3)
|
Amounts
in this column represent the amounts, before consideration of expected
forfeiture rate, that are included in the determination of net income for
in each period under the provisions of SFAS 123(R) for awards under our
Stock Appreciation Rights plan. The forfeiture rate that was
applied to these amounts in each year was 10%. Because of the
decline in our common unit market price and the effects of that decline on
the fair value of outstanding stock appreciation rights, we recorded a
reduction in the liability for these awards in 2008. These
reductions are reflected as negative amounts in the table
above.
|
|
(4)
|
Amounts
in this column represent the amount that will be paid to the Named
Executive Officer as an award under our Bonus Plan. Messrs.
Sims, Blount and Deere do not participate in the Bonus
Plan.
|
|
(5)
|
Information
on the amounts included in this column is included in the table
below.
|
|
(6)
|
Mr.
Sims and Mr. Blount were employed by our general partner effective August
6, 2006.
|
|
(7)
|
Mr.
Deere was employed by our general partner effective October 6,
2008.
|
|
(8)
|
Mr.
Deere served as Chief Financial Officer from October 2008 to the
present. Mr. Benavides served as Chief Financial Officer from
January to October 2008.
|
Name
|
|
Year
|
|
401(k)
Matching Contributions (a)
|
|
|
401(k)
Profit-Sharing Contributions (b)
|
|
|
Insurance
Premiums (c)
|
|
|
Other
Compensation (d)
|
|
|
Totals
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Grant
E. Sims
|
|
2008
|
|
$
|
-
|
|
|
$
|
7,350
|
|
|
$
|
2,484
|
|
|
$
|
-
|
|
|
$
|
9,834
|
|
|
|
2007
|
|
$
|
-
|
|
|
$
|
6,600
|
|
|
$
|
180
|
|
|
$
|
1,831,696
|
|
|
$
|
1,838,476
|
|
|
|
2006
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
56
|
|
|
$
|
-
|
|
|
$
|
56
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Joseph
A. Blount, Jr.
|
|
2008
|
|
$
|
10,350
|
|
|
$
|
7,350
|
|
|
$
|
2,236
|
|
|
$
|
-
|
|
|
$
|
19,936
|
|
|
|
2007
|
|
$
|
9,900
|
|
|
$
|
6,600
|
|
|
$
|
180
|
|
|
$
|
1,602,304
|
|
|
$
|
1,618,984
|
|
|
|
2006
|
|
$
|
4,393
|
|
|
$
|
-
|
|
|
$
|
56
|
|
|
$
|
-
|
|
|
$
|
4,449
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Robert
V. Deere
|
|
2008
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
621
|
|
|
$
|
-
|
|
|
$
|
621
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ross
A. Benavides
|
|
2008
|
|
$
|
10,350
|
|
|
$
|
7,350
|
|
|
$
|
1,884
|
|
|
$
|
-
|
|
|
$
|
19,584
|
|
|
|
2007
|
|
$
|
9,900
|
|
|
$
|
6,600
|
|
|
$
|
180
|
|
|
$
|
-
|
|
|
$
|
16,680
|
|
|
|
2006
|
|
$
|
9,900
|
|
|
$
|
6,600
|
|
|
$
|
168
|
|
|
$
|
-
|
|
|
$
|
16,668
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Karen
N. Pape
|
|
2008
|
|
$
|
10,350
|
|
|
$
|
7,350
|
|
|
$
|
1,656
|
|
|
$
|
-
|
|
|
$
|
19,356
|
|
|
|
2007
|
|
$
|
9,900
|
|
|
$
|
6,600
|
|
|
$
|
180
|
|
|
$
|
-
|
|
|
$
|
16,680
|
|
|
|
2006
|
|
$
|
8,264
|
|
|
$
|
6,600
|
|
|
$
|
168
|
|
|
$
|
-
|
|
|
$
|
15,032
|
|
Amounts
in this table represent:
|
(a)
|
Matching
contributions by Genesis to our 401(k) plan on each NEO’s
behalf.
|
|
(b)
|
Profit-sharing
contributions by Genesis to our 401(k) plan on each NEO’s
behalf.
|
|
(c)
|
Term
life insurance premiums paid by Genesis on each NEO’s
behalf.
|
|
(d)
|
Represents
an amount for the estimated value of the compensation earned in 2007 under
the proposed arrangements between the Senior Executive and our general
partner that existed at that time. Beginning in 2009, the
fair value of the awards of the Class B Membership Interests and the
deferred compensation awards, less these previously recorded amounts, will
be recorded as non-cash compensation expense over their four-year vesting
period, and adjusted quarterly until final settlement. The
expense recorded for this arrangement in 2007 was an amount agreed to by
the parties as a fair representation of the value provided and earned in
2007. While our general partner will bear the cash cost of the
Class B Membership Interests and the deferred compensation awards to our
Senior Executives, the expense will be recognized as compensation by us
and as a capital contribution by our general partner, as the purpose of
the Senior Executive compensation arrangements is to incentivize these
individuals to grow the
partnership.
|
Employment
Agreements.
On
December 31, 2008, each of our Senior Executives, Messrs. Sims, Blount and
Deere, entered into an employment agreement with our general partner under which
he will receive an annual salary of $340,000, $300,000, and $369,600,
respectively, subject to certain upward adjustments. Each senior
executive’s annual salary rate will be increased by (i) $30,000 if our market
capitalization is at least $1.0 billion for any 90-consecutive-day period, and
(ii) an additional amount equal to 10% of his then effective base salary each
time our market capitalization increases by an additional $300
million.
Under his
employment agreement, each Senior Executive will be entitled to specified
severance benefits under certain circumstances. No Senior Executive
will be entitled to severance benefits if our general partner terminates him for
cause. Each Senior Executive (or family) will be 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 dies, if he is terminated due
to a disability or if he terminates his employment for good
reason. If our general partner terminates a Senior Executive (other
than for cause) within two years after a change of control, he will be entitled
to continued health benefits for 18 months after his termination and to the
payment of his base salary through the later of December 31, 2012 or three years
from his date of termination.
Each
employment agreement contains customary non-solicitation and non-competition
provisions that prohibit our Senior Executives from competing with us after
termination, including working for, supervising, assisting, or participating in
any competing business (as defined in the employment agreements) in
any capacity in the states of Louisiana, Mississippi, and Texas during the term
of the employment agreement and for a period of two years after
termination if the employment agreement is terminated for cause or without good
reason, and for a period of one year after termination if the employment
agreement is terminated other than by our general partner for cause or by the
Senior Executive without good reason.
Either
our general partner or a Senior Executive may terminate his agreement at any
time subject to the economic consequences resulting from such
termination. For example, if a Senior Executive terminates his
employment agreement prior to December 31, 2012 other than for good reason, he
will not receive any severance payments or continuing fringe benefits under his
employment agreement, and he will effectively forfeit his Class B Membership
Interest and his deferred compensation award. On the other hand, if
our general partner terminates a Senior Executive’s employment prior to that
date without cause or due to a disability, or if that Senior Executive
terminates his employment for good reason, of if our general partner terminates
a Senior Executive’s employment without cause within two years after a change of
control, that Senior Executive will be entitled to receive a severance payment
and continuing fringe benefits under his employment agreement, as well as a
payment of the redemption amount (if any) in redemption of his Class B
Membership Interest.
Change in Control and Other
Termination Payments
.
Senior
Executives. Based upon a hypothetical termination date of December
31, 2008, the change in control termination benefits for our Senior Executives
would have been as follows:
|
|
Grant
E.
|
|
|
Joseph
A.
|
|
|
Robert
V.
|
|
|
|
Sims
|
|
|
Blount,
Jr.
|
|
|
Deere
|
|
|
|
|
|
|
|
|
|
|
|
Severance
payment pursuant to employment agreement
|
|
$
|
1,020,000
|
|
|
$
|
900,000
|
|
|
$
|
1,108,800
|
|
Healthcare
and other insurance benefits
|
|
|
23,238
|
|
|
|
23,238
|
|
|
|
23,238
|
|
Class
B Membership Interest and deferred compensation
(1)
|
|
|
4,609,185
|
|
|
|
3,966,043
|
|
|
|
1,667,405
|
|
Total
|
|
$
|
5,652,423
|
|
|
$
|
4,889,281
|
|
|
$
|
2,799,443
|
|
|
(1)
|
Upon
termination due to a change in control, each Senior Executive will be
entitled to his deferred compensation amount, if any, and redemption of
his Class B Membership Interest. Such payment will be paid no
later than sixty days after our general partner receives its distribution
payment from us for the quarter ended September 30, 2010, and will be
based on the IDR payment for such quarter. Additionally each
Senior Executive will be entitled to continue to receive a share of the
quarterly IDR payment our general partner receives from us through the
quarter ended September 30, 2010. These amounts will be
computed assuming that each Senior Executive’s CABR-related percentage is
no less than 16%. The amounts in this table represent
management
’
s estimates
of the amount each Senior Executive would receive using assumptions
regarding a number of future events, including estimates of the Available
Cash before Reserves we will generate each quarter through the September
30, 2010 and estimates of the future amount of incentive distributions we
will pay to our general partner related to quarters through September 30,
2010. Additionally our estimate of the redemption of the Class
B Membership Interests assumes that the distribution yield of ten
publicly-traded entities that are the general partners in publicly-traded
master limited partnerships will be the same as the average at December
31, 2008.
|
Based
upon a hypothetical termination date of December 31, 2008, the termination
benefits for our Senior Executives for voluntary termination or termination for
cause would be zero. Based upon a hypothetical termination date of
December 31, 2008, the termination benefits for our Senior Executives for
termination without cause or for good reason, including death or disability
would have been:
|
|
Grant
E.
|
|
|
Joseph
A.
|
|
|
Robert
V.
|
|
|
|
Sims
|
|
|
Blount,
Jr.
|
|
|
Deere
|
|
|
|
|
|
|
|
|
|
|
|
Severance
payment pursuant to employment agreement
|
|
$
|
1,020,000
|
|
|
$
|
900,000
|
|
|
$
|
1,108,800
|
|
Healthcare
and other insurance benefits
|
|
|
23,238
|
|
|
|
23,238
|
|
|
|
23,238
|
|
Class
B Membership Interest and deferred compensation
(1)
|
|
|
3,456,888
|
|
|
|
2,974,532
|
|
|
|
-
|
|
Total
|
|
$
|
4,500,126
|
|
|
$
|
3,897,770
|
|
|
$
|
1,132,038
|
|
|
(1)
|
As
with a termination for a change in control, termination without cause or
for good reason would entitle each Senior Executive to his deferred
compensation amount, if any, and redemption of his Class B Membership
Interest. The termination payment would be paid no later than
sixty days after our general partner receives its distribution payment
from us for the quarter ended September 30, 2010, and will be based on the
IDR payment for such quarter. Additionally each Senior
Executive will be entitled to continue to receive a share of the quarterly
IDR payment our general partner receives from us through the quarter ended
September 30, 2010. The difference from a termination for a
change in control is that these amounts will be computed utilizing each
Senior Executive’s CABR-related percentage at the date of
termination. The amounts in this table were calculated
similarly to the amounts for a change in control, except the CABR-related
percentages were 12% for Messrs. Sims and Blount and zero for Mr. Deere at
December 31, 2008.
|
Other
Executives. Based upon a hypothetical termination date of December 31, 2008, the
change in control termination benefits for our Other Executives would have been
as follows (based on the closing price for our units of $8.69 at that
time):
|
|
Ross
A.
|
|
|
Karen
N.
|
|
|
|
Benavides
|
|
|
Pape
|
|
|
|
|
|
|
|
|
Severance
plan payment
|
|
$
|
1,069,247
|
|
|
$
|
910,616
|
|
Healthcare
and other insurance benefits
|
|
|
12,751
|
|
|
|
12,322
|
|
Fair
market value of stock appreciation rights
|
|
|
-
|
|
|
|
-
|
|
Fair
market value of phantom units
|
|
|
79,739
|
|
|
|
70,876
|
|
Total
|
|
$
|
1,161,737
|
|
|
$
|
993,814
|
|
It is our
belief that the interests of unitholders will best be served if the interests of
our Other Executives are aligned with theirs. Providing change of
control benefits should eliminate, or at least reduce, the reluctance of
management to pursue potential change of control transactions that may be in the
best interests of our unitholders.
We have
two benefits for our employees and Other Executives in the event of a change of
control: (i) our cash Severance Protection Plan, and (ii) vesting of
SARs. Under the terms of our Severance Protection Plan, an employee
is entitled to receive a severance payment if a change of control occurs and the
employee is terminated within two years of that change (i.e. a “double trigger”
award). The Severance Protection Plan will not apply to any employee
who is terminated for cause or by an employee’s own decision for other than good
reason (e.g., change of job status or a required move of more than 25
miles). If entitled to severance payments under the terms of the
Severance Protection Plan, Mr. Benavides and Ms. Pape will receive three times
the sum of their annual salary and the average of their bonus amounts in the
last twenty-four months, certain other members of management will receive two
times the sum of their annual salary and the average of their bonus amounts in
the last twenty-four months, and all other employees will receive between
one-third to one and one-half times the sum of their annual salary and the
average of their bonus amounts in the last twenty-four months depending upon
their salary level and length of service with us. All employees will
also receive medical and dental reimbursement benefits for one-half the number
of months for which they receive severance benefits.
A change
in control is defined in the Severance Protection Plan. Generally, a
change in control is a change in the control of Denbury, a disposition by
Denbury of more than 50% of our general partner, or a transaction involving the
disposition of substantially all of our assets.
The
Severance Protection Plan also provides that if our Other Executives are subject
to the “parachute payment” excise tax under IRC Section 4999, then we will pay
the employee under the severance plan an additional amount to “gross up” the
severance payment so that the employee will receive the full amount due under
the terms of the severance plan after payment of the excise tax.
If a
participant in our SAR Plan is terminated within one year of a change in
control, all SARs would immediately vest.
Other
Compensation
Long
Term Incentive Plan
As
discussed in the Compensation Discussion and Analysis, our unitholders approved
the Genesis Energy, Inc. 2007 Long Term Incentive Plan, or 2007 LTIP, on
December 18, 2007 which provides for awards of Phantom Units and Distribution
Equivalent Rights to non-employee directors and employees of Genesis Energy,
LLC, our general partner. Phantom Units are notional units
representing unfunded and unsecured promises to deliver a common unit to the
participant should specified vesting requirements be
met. Distribution Equivalent Rights are rights to receive an amount
of cash equal to all or a portion of the cash distributions made by us during a
specified period. The 2007 LTIP will be administered by the
Committee. Subject to adjustment as provided in the 2007 LTIP, awards
with respect to up to an aggregate of 1,000,000 units may be granted under the
2007 LTIP.
The
Committee (at its discretion) will designate participants in the 2007 LTIP,
determine the types of awards to grant to participants, determine the number of
units to be covered by any award, and determine the conditions and terms of any
award including vesting, settlement and forfeiture conditions. The
2007 LTIP may be amended or terminated at any time by the Board or the
Committee; however, any material amendment, such as a material increase in the
number of units available under the 2007 LTIP or a change in the types of awards
available under the 2007 LTIP, will also require the approval of our
unitholders. The Committee is also authorized to make adjustments in
the terms and conditions of and the criteria included in awards under the plan
in specified circumstances. The 2007 LTIP is effective until December
18, 2017 or, if earlier, the time which all available units under the 2007 LTIP
have been delivered to participants or the time of termination of the plan by
the Board or the Committee.
Stock
Appreciation Rights Plan
As
discussed in the Compensation Discussion and Analysis, we have a Stock
Appreciation Rights plan, or SAR, for our employees. Our Senior
Executives do not participate in this plan and, beginning in 2009, our Other
Executives, certain key employees and the Board will no longer receive awards
under this plan. Under the terms of this plan, certain employees are
eligible to participate in the plan. The plan is administered by the
Committee, who shall determine, in its full discretion, the number of rights to
award, the grant date of the rights, the vesting period of the rights awarded
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 his rights to receive a cash payment equal
to 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. The cash payment to the participant will
be net of any applicable withholding taxes required by law. If the
Committee determines, in its full discretion, that it would cause significant
financial harm to us to make cash payments to participants who have exercised
rights under the plan, then the 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 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.
Bonus
Program
As
discussed in the Compensation Disclosure and Analysis, we have a bonus program
for all eligible employees of our general partner, with the exception of our
Senior Executives. This program provides for our Other Executives to
receive bonuses annually at the discretion of our Board based on the
recommendation of the Committee. A bonus pool is determined based on
our achieving certain levels of Available Cash before Reserves and bonus expense
and the improvement in our safety record. Each eligible employee will be
eligible to receive a bonus; however, the actual amounts paid will be determined
by the Senior Executives with the approval of the Committee. The
total paid for 2008 bonuses was $4.5 million.
GRANTS OF
PLAN BASED AWARDS IN FISCAL YEAR 2008
The
following tables show the non-equity incentive plan awards granted to the Other
Executives for 2008 and the outstanding SARs and phantom units awards at
December 31, 2008 that were issued to our Other
Executives. Information on rights granted to non-employee directors
is included in the section entitled Director Compensation. These
tables do not include the phantom unit awards made to Mr. Benavides and Ms. Pape
in February 2009 of 8,750 and 7,692, respectively.
Grants
of Plan-Based Awards in Fiscal Year 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Name
|
|
Grant
Date
|
|
All
Other Stock Awards: Number of Shares of Stock or Units (#)
(1)
|
|
|
Exercise
or Base Price of Option Awards ($/Sh)
(2)
|
|
|
Market
Price of Common Units on Award Date
(3)
|
|
|
Grant
Date Fair Value of Stock and Option Awards
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Grant
E. Sims
|
|
12/31/2008
|
|
|
|
|
|
|
|
|
|
|
$
|
6,225,068
|
(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Joseph
A. Blount, Jr.
|
|
12/31/2008
|
|
|
|
|
|
|
|
|
|
|
$
|
5,356,454
|
(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Robert
V. Deere
|
|
12/31/2008
|
|
|
|
|
|
|
|
|
|
|
$
|
429,222
|
(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ross
A. Benavides
|
|
2/14/2008
|
|
|
5,448
|
|
|
$
|
20.92
|
|
|
$
|
21.19
|
|
|
$
|
22,031
|
(5)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Karen
N. Pape
|
|
2/14/2008
|
|
|
4,790
|
|
|
$
|
20.92
|
|
|
$
|
21.19
|
|
|
$
|
19,370
|
(5)
|
(1)
|
The
amounts in this column represent stock appreciation rights granted to the
named Executive Officer during
2008.
|
(2)
|
We
accrue for the fair value of our liability for the SARs we have issued to
our employees and directors under the provisions of SFAS No. 123(R),
Share-Based Payments,
as amended and interpreted. These provisions require us
to make estimates that affect the determination of the fair value of the
outstanding stock appreciation rights, including estimates of the expected
life of the rights, expected forfeiture rates of the rights, expected
future volatility of our unit price and expected future distribution yield
on our units. We base our estimates of these factors on historical
experience and internal data. A summary of the assumptions used
for the valuation at December 31, 2008 is included in Note 15 of the Notes
to our Consolidated Financial Statements. The actual timing and
amounts of payments to employees that will ultimately be made under the
SAR plan will most likely differ from the estimates that are used in
determining fair value. Since the value of our common units is
affected more by actual cash distributions and Available Cash and
expectations for growth of our business, which factors are not fully
contemplated under the methodology of SFAS 123(R), our Committee does not
consider the accounting method for the SAR plan in determining the amount
of SARs to grant our employees.
|
(3)
|
For
the awards granted on February 14, 2008, the exercise price represents the
average of the closing market price of our units for the ten days
preceding February 14, 2008. The closing market price for our
units on February 14, 2008 was
$21.19.
|
(4)
|
Amount
represents management’s estimate of the fair value of the Class B
Membership award and deferred compensation award granted on December 31,
2008 to the NEO. See a description of these awards at “The
Class B Membership Interest in Our General Partner” above in “Compensation
Discussion and Analysis.” This fair value was estimated under
the methodology of SFAS 123(R) and will be recorded as non-cash
compensation expense during the four-year vesting period that begins in
2009. Subsequent to the vesting period, the previously
recorded compensation expense will be adjusted to fair value at each
reporting date.
|
(5)
|
The
amounts in this column represent the fair value of the award on the date
of the grant, February 14, 2008, as calculated in accordance with the
provisions of SFAS 123(R).
|
The
compensation described in the table above for our Senior Executives is a result
of finalizing their compensation arrangements (including the underlying
documentation) in December 2008. These arrangements are intended to
incentivize our Senior Executives to create value for our common unitholders and
general partnerby maintaining and increasing (over time) the distribution rate
we pay to them. Our Senior Executives, including Mr. Deere, will be
rewarded based on whether the shares of the cash distributions attributable to
our incentive distribution rights (or IDRs) increase, which is based upon the
extent to which we increase Cash Available Before Reserves, or CABR (defined
below) per unit and cash distributions. CABR generally means
Available Cash before Reserves, as defined in Item 7 – “Management’s Discussion
and Analysis” above, less Available Cash before Reserves generated from specific
transactions with our general partner and other Denbury
affiliates. These specific transactions include the Free State
Pipeline, the NEJD Pipeline, and any future transactions.
In
summary, each of our Senior Executives has received an equity interest in our
general partner (Class B Membership Interest) and is entitled to receive a base
salary and to participation in our customary fringe benefits, such as health,
medical and severance benefits, with reimbursement of taxes for the effects of
the receipt of the base salary and fringe benefits as a member in the general
partner rather than as an employee. Messrs. Sims and Blount also
received awards under a deferred compensation plan. The Class B
Membership Interests awarded to our senior executives will be accounted for as
liability awards under the provisions of SFAS 123(R). As such, the
fair value of the compensation cost we record for these awards will be
recomputed at each measurement date and the expense to be recorded will be
adjusted based on that fair value. Management’s estimates of the fair
value of these awards are based on assumptions regarding a number of future
events, including estimates of the Available Cash before Reserves we will
generate each quarter through the final vesting date of December 31, 2012,
estimates of the future amount of incentive distributions we will pay to our
general partner, and assumptions about appropriate discount
rates. Additionally the determination of fair value will
be affected by the distribution yield of ten publicly-traded entities that are
the general partners in publicly-traded master limited partnerships, a factor
over which we have no control. Included within the assumptions used
to prepare these estimates are projections of available cash and distributions
to our common unitholders and general partner, including an assumed
level of growth and the effects of future new growth projects
during the four-year vesting period. At December 31, 2008, management
estimates that the fair value of the Class B Membership Awards and the related
deferred compensation awards granted to our Senior Executives on that date is
approximately $12 million. The fair value of these incentive awards
will be recomputed each quarter beginning with the quarter ending March 31, 2009
through the final settlement of the awards. Compensation expense of
$3.4 million was recorded in the fourth quarter of 2007 related to the previous
arrangements between our general partner and our Senior Executives. The fair
value to be recorded by us as compensation expense will be the excess of the
recomputed estimated fair value over the previously recorded $3.4
million. Due to the vesting conditions for the awards, the amount to
which the Senior Executives were entitled on December 31, 2008 for the Class B
Membership Awards and the related deferred compensation was zero.
Management’s estimates of fair value are made in order to record non-cash
compensation expense over the vesting period, and do not represent necessarily
contractual amounts payable under these awards at December 31, 2008. This
expense will be recorded on an accelerated basis to align with the requisite
service period of the award. Changes in our assumptions will change
the amount of compensation cost we record. Changes in these
assumptions would not, however, affect our Available Cash before Reserves, as
the cash cost of the Class B Membership Interests will be borne by
Denbury.
OUTSTANDING
EQUITY AWARDS AT 2008 FISCAL YEAR-END
The
following table presents information regarding the outstanding equity awards to
our Other Executives at December 31, 2008.
Outstanding
Equity Awards at 2008 Fiscal Year-End
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock
Appreciation Rights
|
|
Stock
Awards
|
|
Name
|
|
Number
of Securities Underlying Stock Appreciation Rights (#)
Exercisable
|
|
|
Number
of Securities Underlying Unexercised Stock Appreciation Rights (#)
Unexercisable (1)
|
|
|
Stock
Appreciation Rights Exercise Price ($)
|
|
Stock
Appreciation Rights Expiration Date
|
|
Number
of Phantom Units That Have Not Vested (#) (2)
|
|
|
Market
Value of Phantom Units That Have Not Vested ($)
|
|
|
Fair
Value of Class B Membership Interests That Have Not Vested
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Grant
E. Sims
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6,225,068
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Joseph
A. Blount, Jr.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
5,356,454
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Robert
V. Deere
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
429,222
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ross
A. Benavides
|
|
|
15,889
|
|
|
|
|
|
$
|
9.26
|
|
12/31/2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,777
|
|
|
$
|
12.48
|
|
12/31/2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,015
|
|
|
$
|
11.17
|
|
12/31/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,003
|
|
|
$
|
16.95
|
|
8/29/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,270
|
|
|
$
|
19.57
|
|
12/29/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,448
|
|
|
$
|
20.92
|
|
2/14/2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,176
|
|
|
$
|
79,739
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Karen
N. Pape
|
|
|
12,153
|
|
|
|
|
|
|
$
|
9.26
|
|
12/31/2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,889
|
|
|
$
|
12.48
|
|
12/31/2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,071
|
|
|
$
|
11.17
|
|
12/31/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
767
|
|
|
$
|
16.95
|
|
8/29/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,254
|
|
|
$
|
19.57
|
|
12/29/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,790
|
|
|
$
|
20.92
|
|
2/14/2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,156
|
|
|
$
|
70,876
|
|
|
|
|
|
|
(1)
|
The
unexercisable rights of each named executive officer vest on the following
dates in the order they are listed: January 1, 2009, January 1,
2010, January 1, 2010, December 31, 2010 and February 14,
2012.
|
|
(2)
|
These
phantom units vest on December 18,
2010.
|
|
(3)
|
Amount
represents management’s estimate of the fair value of the Class B
Membership award and deferred compensation award granted on December 31,
2008 to the NEO. See a description of these awards at “The
Class B Membership Interest in Our General Partner” above in “Compensation
Discussion and Analysis.” This fair value was estimated under
the methodology of SFAS 123(R) and will be recorded as non-cash
compensation expense during the four-year vesting period that begins in
2009. Subsequent to the vesting period, the previously
recorded compensation expense will be adjusted to fair value at each
reporting date.
|
DIRECTOR
COMPENSATION FOR FISCAL YEAR 2008
The table
below reflects compensation for the directors. Directors who are employees of
our general partner, like Mr. Sims, do not receive compensation for service as a
director. During 2008, compensation for the independent and Davison
directors consisted of an annual fee of $40,000. The Audit Committee
Chairman received an additional annual fee of $10,000. Audit
Committee members received an additional annual fee of $2,500. We
paid Denbury fees totaling $160,000 for providing four of its executives as
directors of Genesis. Additionally, non-employee directors
received a fee for attendance at meetings of $2,000 for each meeting attended in
person and $1,000 for meetings attended telephonically. This fee was
applicable to meetings of the Board and committee meetings, however only one
meeting fee could be earned per day. Meeting fees for the four
executives provided by Denbury as directors totaling $35,000 were paid to
Denbury.
Director
Compensation in Fiscal 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Name
|
|
Fees
Earned or Paid in Cash ($)
(1)
|
|
|
Stock
Awards ($)
(2)
|
|
|
Option Awards
($)
(3)
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark
C. Allen
(4)
|
|
$
|
50,000
|
|
|
$
|
26,805
|
|
|
$
|
(9,692
|
)
|
|
$
|
67,113
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
David
C. Baggett, Jr.
|
|
$
|
49,250
|
|
|
$
|
26,805
|
|
|
$
|
-
|
|
|
$
|
76,055
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
James
E. Davison
|
|
$
|
50,000
|
|
|
$
|
26,805
|
|
|
$
|
165
|
|
|
$
|
76,970
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
James
E. Davison, Jr.
|
|
$
|
51,000
|
|
|
$
|
26,805
|
|
|
$
|
165
|
|
|
$
|
77,970
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ronald
T. Evans
(4)
|
|
$
|
50,000
|
|
|
$
|
26,805
|
|
|
$
|
(34,691
|
)
|
|
$
|
42,114
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Susan
O. Rheney
|
|
$
|
73,000
|
|
|
$
|
26,805
|
|
|
$
|
(45,964
|
)
|
|
$
|
53,841
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gareth
Roberts
(4)
|
|
$
|
45,000
|
|
|
$
|
26,805
|
|
|
$
|
(34,691
|
)
|
|
$
|
37,114
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Phil
Rykhoek
(4)
|
|
$
|
50,000
|
|
|
$
|
26,805
|
|
|
$
|
(30,926
|
)
|
|
$
|
45,879
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
J.
Conley Stone
|
|
$
|
60,250
|
|
|
$
|
26,805
|
|
|
$
|
(24,354
|
)
|
|
$
|
62,701
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Martin
G. White
|
|
$
|
49,875
|
|
|
$
|
26,805
|
|
|
$
|
-
|
|
|
$
|
76,680
|
|
(1)
|
Amounts
include annual retainer fees and fees for attending
meetings.
|
(2)
|
Amounts
in this column represent the amounts, before consideration of expected
forfeiture rate, that are included in the determination of net income for
the period under the provisions of SFAS 123(R) for awards of phantom units
under our 2007 LTIP. The forfeiture rate that was applied to
the phantom unit awards at December 31, 2008 was zero. Each
director received an award of 2,300 phantom units. The grant
date fair value of these awards was $20.12 per phantom
unit.
|
(3)
|
Amounts
in this column represent the amounts, before consideration of expected
forfeiture rate, that are included in the determination of net income for
the period under the provisions of SFAS123(R) for awards of stock
appreciation rights. The forfeiture rate that was applied to
these stock appreciation rights at December 31, 2008 was ten
percent. Under our stock appreciation rights plan, the director
will receive cash upon exercise of the right. Because of the
decline in our common unit market price and the effects of that decline on
the fair value of outstanding stock appreciation rights, we recorded a
reduction in the liability for most of these awards in
2008. These reductions are reflected as negative amounts in the
table above.
|
(4)
|
Fees
were paid in cash for these directors to Denbury. The phantom
unit and stock appreciation rights awards are individual awards of the
named director.
|
OUTSTANDING
EQUITY AWARDS AT 2008 FISCAL YEAR END
The
outstanding awards of stock appreciation rights to the directors of our general
partner are shown in the table below.
Oustanding
Equity Awards at 2008 Fiscal Year-End to Directors
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock
Appreciation Rights
|
|
Stock
Awards
|
|
Name
|
|
Number
of Securities Underlying Stock Appreciation Rights (#)
Exercisable
|
|
|
Number
of Securities Underlying Unexercised Stock Appreciation Rights (#)
Unexercisable
|
|
|
Stock
Appreciation Rights Exercise Price ($)
|
|
Stock
Appreciation Rights Expiration Date
|
|
Number
of Phantom Units That Have Not Vested (#)
(1)
|
|
|
Market
Value of Phantom Units That Have Not Vested ($)
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark
C. Allen
(3)
|
|
|
1,288
|
|
|
|
|
|
$
|
15.77
|
|
9/29/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,000
|
|
|
$
|
19.57
|
|
12/29/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,000
|
|
|
$
|
20.92
|
|
2/14/2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,300
|
|
|
|
19,987
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
David
C. Baggett
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,300
|
|
|
|
19,987
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
James
E. Davison
(4)
|
|
|
|
|
|
|
1,000
|
|
|
$
|
20.92
|
|
2/14/2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,300
|
|
|
|
19,987
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
James
E. Davison, Jr.
(4)
|
|
|
|
|
|
|
1,000
|
|
|
$
|
20.92
|
|
2/14/2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,300
|
|
|
|
19,987
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ronald
T. Evans
(5)
|
|
|
2,576
|
|
|
|
|
|
|
$
|
9.26
|
|
12/31/2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
612
|
|
|
$
|
12.48
|
|
12/31/2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
651
|
|
|
$
|
11.17
|
|
12/31/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,000
|
|
|
$
|
19.57
|
|
12/29/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,000
|
|
|
$
|
20.92
|
|
2/14/2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,300
|
|
|
|
19,987
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Susan
O. Rheney
(5)
|
|
|
3,435
|
|
|
|
|
|
|
$
|
9.26
|
|
12/31/2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
816
|
|
|
$
|
12.48
|
|
12/31/2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
868
|
|
|
$
|
11.17
|
|
12/31/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,000
|
|
|
$
|
19.57
|
|
12/29/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,000
|
|
|
$
|
20.92
|
|
2/14/2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,300
|
|
|
|
19,987
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gareth
Roberts
(5)
|
|
|
2,576
|
|
|
|
|
|
|
$
|
9.26
|
|
12/31/2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
612
|
|
|
$
|
12.48
|
|
12/31/2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
651
|
|
|
$
|
11.17
|
|
12/31/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,000
|
|
|
$
|
19.57
|
|
12/29/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,000
|
|
|
$
|
20.92
|
|
2/14/2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,300
|
|
|
|
19,987
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Phil
Rykhoek
(5)
|
|
|
2,576
|
|
|
|
|
|
|
$
|
11.00
|
|
8/25/2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
612
|
|
|
$
|
12.48
|
|
12/31/2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
651
|
|
|
$
|
11.17
|
|
12/31/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,000
|
|
|
$
|
19.57
|
|
12/29/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,000
|
|
|
$
|
20.92
|
|
2/14/2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,300
|
|
|
|
19,987
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
J.
Conley Stone
(5)
|
|
|
773
|
|
|
|
|
|
|
$
|
9.26
|
|
12/31/2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
735
|
|
|
$
|
12.48
|
|
12/31/2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
781
|
|
|
$
|
11.17
|
|
12/31/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,000
|
|
|
$
|
19.57
|
|
12/29/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,000
|
|
|
$
|
20.92
|
|
2/14/2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,300
|
|
|
|
19,987
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Martin
G. White
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,300
|
|
|
|
19,987
|
|
|
(1)
|
These
phantom units vest on June 3, 2009.
|
|
(2)
|
The
market value of the phantom units that have not vested was determined by
multiplying the number of phantom units by the closing price of our common
units on December 31, 2008 of
$8.69.
|
|
(3)
|
Mr.
Allen’s first stock appreciation rights award will vest one-fourth
annually beginning September 29, 2007 through September 29,
2010. Mr. Allen’s remaining unexercisable stock appreciation
rights will vest on January 1, 2011 and February 14,
2012.
|
|
(4)
|
The
unexercisable stock appreciation rights of this director vest on February
14, 2012.
|
|
(5)
|
The
unexercisable stock appreciation rights of this director vest on the
following dates in the order they are listed: January 1, 2009,
January 1, 2010, January 1, 2011 and February 14,
2012.
|
Compensation
Committee Interlocks and Insider Participation
None of
the members of the Compensation Committee has at any time been an officer or
employee of our general partner or us. None of our executive officers
serves, or in the past year has served, as a member of the board of directors or
compensation committee of any entity that has one or more of its executive
officers serving on our Compensation Committee.
Item
12. Security
Owner
ship of Certain Beneficial Owners
and Management and Related Stockholder Matters
Securities
Authorized for Issuance Under Equity Compensation Plans
See Item
5 – Equity Compensation Plans.
Beneficial
Ownership of Partnership Units
The
following table sets forth certain information as of February 28, 2009,
regarding the beneficial ownership of our units by beneficial owners of 5% or
more of the 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.
|
|
|
Beneficial Ownership of Common
Units
|
|
|
|
|
|
|
|
Percent
|
|
Title
of Class
|
Name
and Address of Beneficial Owner
|
|
Number
of Units
|
|
|
of
Class
|
|
|
|
|
|
|
|
|
|
Genesis
Energy, L.P.
|
Genesis
Energy, LLC
|
|
|
2,829,055
|
|
|
|
7.2
|
|
Common
Units
|
Gareth
Roberts
(1)
|
|
|
12,300
|
|
|
|
*
|
|
|
Grant
E. Sims
(2)
|
|
|
6,000
|
|
|
|
*
|
|
|
Mark
C. Allen
(1)
|
|
|
7,300
|
|
|
|
*
|
|
|
David
C. Baggett, Jr.
(1)
|
|
|
2,300
|
|
|
|
*
|
|
|
James
E. Davison
(1) (3)
(4)
|
|
|
2,877,838
|
|
|
|
7.3
|
|
|
James
E. Davison, Jr.
(1)
(5)
|
|
|
3,157,067
|
|
|
|
8.0
|
|
|
Ronald
T. Evans
(1)
|
|
|
15,300
|
|
|
|
*
|
|
|
Susan
O. Rheney
(1)
|
|
|
3,000
|
|
|
|
*
|
|
|
Phil
Rykhoek
(1)
|
|
|
12,300
|
|
|
|
*
|
|
|
J.
Conley Stone
(1)
|
|
|
4,300
|
|
|
|
*
|
|
|
Martin
G. White
(1)
|
|
|
4,400
|
|
|
|
*
|
|
|
Ross
A. Benavides
(6)
|
|
|
18,459
|
|
|
|
*
|
|
|
Karen
N. Pape
(7)
|
|
|
11,542
|
|
|
|
*
|
|
|
|
|
|
|
|
|
|
|
|
|
All
directors and executive
|
|
|
|
|
|
|
|
|
|
officers
as a group (13 in total)
|
|
|
6,132,106
|
|
|
|
15.5
|
|
|
|
|
|
|
|
|
|
|
|
|
Denbury
Onshore LLC
(8)
|
|
|
|
|
|
|
|
|
|
5100
Tennyson Parkway
|
|
|
1,199,041
|
|
|
|
3.0
|
|
|
Plano,
Texas 75024
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Todd
A. Davison
(9)
|
|
|
2,875,537
|
|
|
|
7.3
|
|
|
Steven
K. Davison
(10)
|
|
|
2,875,537
|
|
|
|
7.3
|
|
|
Terminal
Service, Inc.
(11)
|
|
|
1,010,835
|
|
|
|
2.6
|
|
|
|
|
|
|
|
|
|
|
|
|
Swank
Capital, LLC, Swank
|
|
|
|
|
|
|
|
|
|
Energy
Income Advisors,
|
|
|
|
|
|
|
|
|
|
L.P.
and Mr. Jerry V. Swank
(12)
|
|
|
2,871,087
|
|
|
|
7.3
|
|
|
3300
Oak Lawn Ave., Suite 650
|
|
|
|
|
|
|
|
|
|
Dallas,
Texas 75219
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Neuberger
Berman, Inc.
(13)
|
|
|
2,181,894
|
|
|
|
5.5
|
|
|
605
Third Avenue
|
|
|
|
|
|
|
|
|
|
New
York, NY 10158
|
|
|
|
|
|
|
|
|
|
(1)
|
Number
of units includes phantom units for which the holder has the right to
receive 2,300 common units upon vesting on June 3,
2009.
|
|
(2)
|
1,000
of these common units are held by Mr. Sims’ father. Mr. Sims
disclaims beneficial ownership of these
units.
|
|
(3)
|
James
E. Davison is the sole stockholder of Davison Terminal Service, Inc.,
which directly owns 1,010,835
units.
|
|
(4)
|
We
have been granted a lien on 1,327,007 of these units to secure the Davison
unitholders indemnification obligations to us under the terms of our
acquisition of the Davison
businesses.
|
|
(5)
|
We
have been granted a lien on 1,352,226 of these units to secure the Davison
unitholders indemnification obligations to us under the terms of our
acquisition of the Davison
businesses.
|
|
(6)
|
Includes
9,176 phantom units which will vest on December 18,
2010.
|
|
(7)
|
Includes
8,156 phantom units which will vest on December 18,
2010.
|
|
(8)
|
Denbury
Onshore, LLC is an affiliate of our general partner and a wholly-owned
subsidiary of Denbury.
|
|
(9)
|
Todd
A. Davison is the son of James E. Davison and the brother of James E.
Davison, Jr., and an employee of our general partner. The
mailing address for Mr. Davison is 2000 Farmerville Hwy., Ruston, LA
71270. We have been granted a lien on 1,352,226 of these
units to secure the Davison unitholders indemnification obligations to us
under the terms of our acquisition of the Davison
businesses.
|
|
(10)
|
Steven
K. Davison is the son of James E. Davison and the brother of James E.
Davison, Jr. and Todd A. Davison, and an employee of our general
partner. The mailing address for Mr. Davison is 207 W.
Alabama,
Ruston, LA 71270. We have been granted a lien on 1,352,226 of
these units to secure the Davison unitholders indemnification obligations
to us under the terms of our acquisition of the Davison
businesses.
|
|
(11)
|
This
entity is owned by James E. Davison. It was formerly known as
Davison Terminal Service, Inc. The mailing address of this
entity is PO Box 607, Ruston, LA
71273.
|
|
(12)
|
Information
based on Schedule 13G filed with the SEC on February 17,
2009. Swank Capital, LLC and Mr. Jerry V. Swank claim sole
voting and dispositive powers over these units. Swank Energy
Income Advisors, L.P. claims shared voting and dispositive powers over
these units.
|
|
(13)
|
Information
based on Schedule 13G filed with the SEC on February 12,
2009.
|
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 all of our 2% general partner interest and all of our incentive
distribution rights, in addition to 7.2% of our units. Genesis
Energy, LLC is a majority-owned subsidiary of Denbury. Denbury has
advised us that it has not pledged any of its interest in our general partner
under any agreements or arrangements.
Item
13. Certain R
elation
ships and Related Transactions,
and Director Independence
Our
General Partner
Our
operations are managed by, and our employees are employed by, Genesis Energy,
LLC, our general partner. Our general partner does not receive any
management fee or other compensation in connection with the management of our
business, but is reimbursed for all direct and indirect expenses incurred on our
behalf. During 2008, these reimbursements totaled $51.9
million. As of December 31, 2008, we owed our general partner $2.1
million related to these services.
Our
general partner owns the 2% general partner interest and all incentive
distribution rights. Our general partner is entitled to receive
incentive distributions if the amount we distribute with respect to any quarter
exceeds levels specified in our partnership agreement. Under the
quarterly incentive distribution provisions, generally our general partner is
entitled to 13.3% of amounts we distribute to our common unitholders in excess
of $0.25 per unit, 23.5% of the amounts we distribute to our common unitholders
in excess of $0.28 per unit, and 49% of the amounts we distribute to our common
unitholders in excess of $0.33 per unit. See Item 11. Executive
Compensation for information regarding our Senior Executives interest in the
incentive distribution rights owned by our general partner.
Our
general partner also owns 2,829,055 limited partner units and has the same
rights and is entitled to receive distributions as the other limited partners
with respect to those units.
During
2008, our general partner received a total of $6.5 million from us as
distributions, with $3.5 million attributable to its limited partner units, $1.0
million for its general partner interest, and $2.0 million related to its
incentive distribution rights.
Relationship
with Denbury Resources, Inc.
Historically,
we have entered into transactions with Denbury and its subsidiaries to acquire
assets from time to time. We have instituted specific procedures for
evaluating and valuing our material transactions with Denbury and its
subsidiaries. Before we consider entering into a material transaction
with Denbury or any of its subsidiaries, 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. In
addition, our general partner’s board of directors may seek “Special Approval”
(as defined in our partnership agreement) from our Audit Committee, which is
comprised solely of independent directors. That
committee:
|
·
|
evaluates
and, where appropriate, negotiates the proposed
transaction;
|
|
·
|
engages
an independent legal counsel and, if it deems appropriate, an independent
financial advisor to assist with its evaluation of the proposed
transaction; and
|
|
·
|
determines
whether to reject or approve and recommend the proposed
transaction.
|
Traditionally,
we have consummated proposed material acquisitions or dispositions with Denbury
only when we have evaluated the transaction, our Audit Committee has approved
and recommended the transaction and our general partner’s full board has
approved the transaction, however, such approvals are not required under our
partnership agreement.
During
2005, 2004 and 2003, we acquired CO
2
volumetric
production payments and related wholesale marketing contracts from Denbury for
$14.4 million, $4.7 million and $24.4 million, respectively. In May
2008, we completed two transactions with Denbury involving CO
2
pipelines. We acquired the Free State CO
2
pipeline
for $75 million, comprised of $50 million of cash and $25 million of our common
units. These common units are owned by Denbury Onshore LLC, a
wholly-owned subsidiary of Denbury and an affiliate of our general
partner. Additionally, we entered into a twenty-year financing lease
transaction with Denbury valued at $175 million related to Denbury’s NEJD
Pipeline System.
Additionally
we enter into transactions with Denbury in the ordinary course of our
operations. During 2008, these transactions included:
|
·
|
Provision
of transportation services for crude oil by truck totaling $3.6
million.
|
|
·
|
Provision
of crude oil pipeline transportation services totaling $10.7
million.
|
|
·
|
Provision
of CO
2
and
crude oil pipeline transportation services under lease arrangements for
which we received payments totaling $11.5
million.
|
|
·
|
Provision
of CO
2
transportation services to our wholesale industrial customers by Denbury’s
pipeline. The fees for this service totaled $6.4 million in
2008.
|
|
·
|
Provision
of pipeline monitoring services to Denbury for its CO
2
pipelines totaling $120,000 in
2008.
|
|
·
|
Provision
of services by Denbury officers as directors of our general
partner. We paid Denbury $195,000 for these services in
2007.
|
At
December 31, 2008, we owed Denbury $1.0 million for provision of CO
2
transportation services. Denbury owed us $2.0 million for crude oil
trucking and pipeline transportation services.
Our
partnership agreement provides that, with the approval of at least a majority of
our limited partners, our general partner also may be removed without
cause. Any limited partner interests held by our general partner and
its affiliates would be excluded from such a vote. If it is proposed
that the removal is without cause and an affiliate of Denbury is not proposed as
a successor, then any action for removal must also provide for Denbury to be
granted an option effective upon its removal to purchase our Mississippi
pipeline system at a price that is 110 percent of its fair market value at that
time. Denbury also has the right to purchase the Mississippi CO
2
pipeline
to Brookhaven field at its fair market value at that time. Fair value
is to be determined by agreement of two independent appraisers, one chosen by
the successor general partner and the other by Denbury or if they are unable to
agree, the mid-point of the values determined by them. Additionally,
in the event our general partner is removed by our common unitholders without
the approval of Denbury, Denbury has the option to prepay its obligation under
the NEJD Pipeline lease.
Relationship
with Davison family
We have
entered into an aircraft interchange agreement with the Davison family where
each party will make available to the other party its aircraft on an
as-available basis, in exchange for equal flight-time on the other party’s
aircraft any appropriate difference between the cost of owning, operating, and
maintaining the aircraft. The estimated value of the equal
flight-time owed to the Davison family at December 31, 2008 was approximately
$16,000.
In
connection with the terms of our acquisition of the Davison businesses, the
Davison unitholders have registration rights with respect to their
units.
These
rights include the following provisions:
|
·
|
the
right to require us to file a shelf registration statement, which we filed
in 2008;
|
|
·
|
the
right to demand five registrations of their units, one per calendar year,
and piggyback rights for other unit registrations;
and
|
|
·
|
the
Davison unitholders have agreed to specified restrictions on the sale and
transfer of the units they received in consideration of this
acquisition. The Davison unitholders cannot sell any of the
units issued as consideration except that portion provided below (subject
to certain exceptions):
|
At
closing (July 25, 2007)
|
|
|
20
|
%
|
At
July 25, 2008
|
|
|
20
|
%
|
At
January 25, 2009
|
|
|
20
|
%
|
At
July 25, 2009
|
|
|
30
|
%
|
At
July 25, 2010
|
|
|
10
|
%
|
|
|
|
100
|
%
|
Pursuant
to a unitholder agreement between the Davison unitholders and us, executed on
July 25, 2007, the Davison unitholders have the right to designate up to two
directors to our board of directors, depending on their continued level of
ownership in us. Until July 25, 2010, the Davison unitholders have
the right to designate two directors to our board of
directors. Thereafter, the Davison unitholders will have the right to
designate (i) one director if they beneficially own at least 10% but less than
35% of our outstanding common units, or (ii) two directors if they beneficially
own 35% or more of our outstanding common units. If their percentage
ownership in our common units drops below 10% after July 25, 2010, the Davison
unitholders would have no rights to designate directors. At December
31, 2008, the Davison unitholders held approximately 30% of our outstanding
common units.
On July
25, 2007, the Davison unitholders designated James E. Davison and James E.
Davison, Jr. as directors to the Board of Directors of our general
partner.
To secure
their indemnification obligations under the agreement with us for the
acquisition of their businesses, the Davison unitholders have granted to us a
lien on 5,383,684 units, or 40% of the units they received as
consideration. On July 24, 2009, 4,037,763 of these units will be
released, with the remaining 1,345,921 units released on July 26,
2010.
Our joint
venture partner in DG Marine is TD Marine, LLC, an entity owned by James E.
Davison and two of his sons. Additionally, Community
Trust Bank is a 17% participant in the DG Marine credit
facility. Davison family members own approximately 14% of Community
Trust Bank, and James E. Davison, Jr. serves on the board of the holding company
that owns Community Trust Bank.
During
2008, 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.
Director
Independence
Susan O.
Rheney, David C. Baggett and Martin G. White, all members of our Audit
Committee, meet the listing standard requirements of NYSE Alternext US, and the
SEC rules to be considered independent directors of
Genesis. Additionally, J. Conley Stone also meets the requirements to
be considered an independent director. The term “independent
director” means a person other than an officer or employee of our general
partner, the Partnership or its subsidiaries, or Denbury or its subsidiaries, or
any other individual having a relationship that, in the opinion of the Board of
Directors, would interfere with the exercise of independent judgment in carrying
out the responsibilities of a director. To be considered independent,
neither the director nor an immediate family member of the director has had any
direct or indirect material relationship with Genesis.
The
independent directors meet regularly in executive sessions outside of the
presence of the non-independent directors or members of our management after
each of the regularly scheduled quarterly Audit Committee
meetings. See additional discussion of director independence at Item
10. Directors, Executive Officers and Corporate Governance –
Management of Genesis Energy,
L.P
.
Item
14. Principal
Acc
ounting Fees and
Services
The
following table summarizes the fees for professional services rendered by
Deloitte & Touche LLP for the years ended December 31, 2008 and
2007.
|
|
2008
|
|
|
2007
|
|
|
|
(in
thousands)
|
|
Audit
Fees
(1)
|
|
$
|
3,634
|
|
|
$
|
3,107
|
|
Audit-Related
Fees
(2)
|
|
|
296
|
|
|
|
1,945
|
|
Tax
Fees
(3)
|
|
|
368
|
|
|
|
165
|
|
All
Other Fees
(4)
|
|
|
3
|
|
|
|
2
|
|
Total
|
|
$
|
4,301
|
|
|
$
|
5,219
|
|
|
(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. Also
includes audits of our general partner and separate audits of certain of
our consolidated subsidiaries and joint
ventures.
|
|
(2)
|
Includes
fees for the audit of our employee benefit plan and assistance in the
documentation of internal controls over financial
reporting. Also includes fees for audits of acquired
businesses.
|
|
(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 2008 and 2007 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 (collectively, the “Disclosure Categories”) that the
independent auditor may perform. The policy requires that each fiscal
year, a description of the services (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 2008
and 2007, 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.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization
We are a
growth-oriented limited partnership focused on the midstream segment of the oil
and gas industry in the Gulf Coast area of the United States. We
conduct our operations through our operating subsidiaries and joint
ventures. We manage our businesses through four
divisions:
|
·
|
Pipeline
transportation of crude oil, carbon dioxide (or CO
2
)
and, to a lesser degree, natural
gas;
|
|
·
|
Refinery
services involving processing of high sulfur (or “sour”) gas streams for
refineries to remove the sulfur, and sale of the related by-product,
sodium hydrosulfide (or NaHS, commonly pronounced
nash);
|
|
·
|
Industrial
gas activities, including wholesale marketing of CO
2
and
processing of syngas through a joint venture;
and
|
|
·
|
Supply
and logistics services, which includes terminaling, blending, storing,
marketing, and transporting by trucks and barge of crude oil and petroleum
products.
|
Our
2% general partner interest is held by Genesis Energy, LLC, a Delaware limited
liability company and an indirect, majority-owned subsidiary of Denbury
Resources Inc. Denbury and its subsidiaries are hereafter referred to
as Denbury. Our general partner and its affiliates also own 10.2% of
our outstanding common units.
Our
general partner manages our operations and activities and employs our officers
and personnel, who devote 100% of their efforts to our management.
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, 2008 and 2007 and our results of
operations, cash flows and changes in partners’ capital for the years ended
December 31, 2008, 2007 and 2006. All intercompany 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.
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 three joint ventures: DG Marine Transportation, LLC
(DG Marine), T&P Syngas Supply Company (T&P Syngas) and Sandhill Group,
LLC (Sandhill). As of the acquisition date in July 2008, DG Marine is
consolidated in our financial statements. We account for our 50%
investments in T&P Syngas and Sandhill by the equity method of accounting.
See Note 8.
DG Marine
Transportation, LLC
In July
2008, we acquired an interest in DG Marine which acquired the inland marine
transportation business of Grifco Transportation, Ltd and two of its
affiliates. DG Marine is a joint venture with TD Marine, LLC, an
entity owned by members of the Davison family. We own an effective
49% economic interest and TD Marine, LLC owns a 51% economic interest in DG
Marine. TD Marine, LLC controls the DG Marine joint venture and the
day-to-day operations are conducted by and managed by DG Marine
employees. The provisions of Financial Interpretation No. 46(R)
“Consolidation of Variable Interest Entities” (FIN 46R), require us to
consolidate DG Marine in our consolidated financial statements. See
Note 3. The results of the operations of DG Marine have been included
in our consolidated financial statements since the date of the
acquisition.
T&P
Syngas Supply Company
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
We own a
50% interest in T&P Syngas, a Delaware general
partnership. Praxair Hydrogen Supply Inc. (“Praxair”) owns the
remaining 50% partnership interest in T&P Syngas. T&P Syngas
is a partnership that owns a syngas manufacturing facility located in Texas
City, Texas. That facility processes natural gas to produce syngas (a
combination of carbon monoxide and hydrogen) and high pressure
steam. Praxair provides the raw materials to be processed and
receives the syngas and steam produced by the facility under a long-term
processing agreement. T&P Syngas receives a processing fee for
its services. Praxair operates the facility.
Sandhill
Group, LLC
We own a
50% interest in Sandhill. At December 31, 2008, Reliant Processing
Ltd. held the other 50% interest in Sandhill. Sandhill owns a CO
2
processing
facility located in Brandon, Mississippi. Sandhill is engaged in the production
and distribution of liquid carbon dioxide for use in the food, beverage,
chemical and oil industries. The facility acquires CO
2
from us
under a long-term supply contract that we acquired in 2005 from
Denbury.
Minority
Interests
Our
general partner owns a 0.01% general partner interest in Genesis Crude Oil, L.P.
and TD Marine, LLC, a related party, owns the remaining 51% economic interest in
DG Marine. The net interest of those parties in our results of
operations and financial position are reflected in our financial statements as
minority interests.
In July
2007, we acquired the energy-related businesses of the Davison
family. See Note 3. The results of the operations of these
businesses have been included in our consolidated financial statements since
August 1, 2007.
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) estimated useful lives of assets, which
impacts depreciation and amortization, (2) liability and contingency accruals,
(3) estimated fair value of assets and liabilities acquired and identification
of associated goodwill and intangible assets, (4) estimates of future net cash
flows from assets for purposes of determining whether impairment of those assets
has occurred, and (5) 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.
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. The Partnership has 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
Our
accounts receivable are primarily from purchasers of crude oil and petroleum
products, and, to a lesser extent, purchasers of NaHS and CO
2
. These
purchasers include refineries, marketing and trading companies. The
majority of our accounts receivable relate to our supply and logistics
activities that can be described as high volume and low margin
activities.
Volatility
in the financial markets in the latter half of 2008 combined with significant
energy price volatility has caused liquidity issues impacting many companies,
which in turn have increased the potential credit risks associated with certain
counterparties with which we do business. We utilize our credit
review process to monitor these conditions and to make a determination with
respect to the amount, if any, of credit to be extended to any given customer
and the form and amount of financial performance assurances we
require.
We review
our outstanding accounts receivable balances on a regular basis and record a
reserve 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.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
The
following table presents the activity of our allowance for doubtful accounts for
the year ended December 31, 2008:
|
|
Year
Ended
|
|
|
|
December
31,
|
|
|
|
2008
|
|
Balance
at beginning of period
|
|
$
|
-
|
|
Charged
to costs and expenses
|
|
|
1,152
|
|
Amounts
written off
|
|
|
(20
|
)
|
Balance
at end of period
|
|
$
|
1,132
|
|
Inventories
Crude oil
and petroleum products inventories held for sale are valued at the lower of
average cost or market. Fuel inventories are carried at the lower of
cost or market. Caustic soda and NaHS inventories are stated 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, 25 years for push boats and barges, 10 to 20
years for machinery and equipment, 40 years for tanks, 3 to 7 years for vehicles
and transportation equipment, and 3 to 10 years for buildings, 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, natural gas and CO
2
pipelines,
barge decommissioning, removal of equipment and facilities from leased acreage
and land restoration. The fair value of a liability for an asset retirement
obligation is recorded in the period in which it is incurred, discounted to its
present value using our credit adjusted risk-free interest rate, and a
corresponding amount capitalized by increasing the carrying amount of the
related long-lived asset. The capitalized cost is depreciated over the useful
life of the related asset. Accretion of the discount increases the
liability and is recorded to expense. See Note 5.
Direct
Financing Leasing Arrangements
We lease
four pipelines to Denbury under direct financing leases. Three of
these leases of pipeline segments to Denbury will expire in 2013 to
2015. The NEJD Pipeline System lease to Denbury will expire in 2028,
subject to certain extension options.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
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
revenue in the Consolidated Statements of Operations. The pipeline
cost is not included in fixed assets. See Note 6.
CO
2
Assets
Our
CO
2
assets include three volumetric production payments and long-term contracts to
sell the CO
2
volume. The contract values are being amortized on a
units-of-production method. See Note 7.
Intangible
Assets
Statement
of Financial Accounting Standards No. 142, “Goodwill and Other Intangible
Assets,” (SFAS 142) requires that intangible assets with finite useful lives 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 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. As of December 31, 2008, no impairment
has occurred of intangible assets.
Goodwill
Goodwill
represents the excess of purchase price over fair value of net assets
acquired. We account for goodwill under SFAS 142, which prohibits
amortization of goodwill, but instead requires testing for impairment at least
annually. We test goodwill for impairment annually at October 1, and
more frequently if indicators of impairment are present. If the 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 is recorded 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. See Note 9.
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.
Unit-Based
Compensation
On
January 1, 2006, we adopted the provisions of SFAS No. 123(R), “Share-Based
Payments”. This statement requires that the compensation cost
associated with our stock appreciation rights plan, which upon exercise will
result in the payment of cash to the employee, be re-measured each reporting
period based on the fair value of the rights. Before the adoption of
SFAS 123(R), we accounted for the stock appreciation rights in accordance with
FASB Interpretation No. 28, “Accounting for Stock Appreciation Rights and Other
Variable Stock Option or Award Plans” which required that the liability under
the plan be measured at each balance sheet date based on the market price of our
common units on that date. Under SFAS 123(R), 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.
Our 2007
Long-term Incentive Plan provides for awards of phantom units to our
non-employee directors and to the employees of our general
partner. SFAS No. 123(R) requires that compensation cost
related to phantom units issued under our 2007 Long-term Incentive Plan be
recognized in our consolidated financial statements based on estimated fair
value at the date of the grant. See Note 15.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
On
December 31, 2008, our general partner awarded Class B Membership Interests in
our general partner to our senior executives. SFAS 123(R) requires
that the compensation cost related to these interests be re-measured at each
reporting date based on the fair value of the interests, and changes in that
fair value be recognized over the vesting period. Recorded expense will be
subsequently adjusted to fair value until final settlement. See Note
15.
Revenue
Recognition
Product
Sales - Revenues from the sale of crude oil, petroleum products, natural gas,
caustic soda and NaHS 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, natural gas 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 or natural gas 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 expense, 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
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.
CO
2
Sales -
Revenues from CO
2
marketing
activities are recorded when title transfers to the customer at the inlet meter
of the customer’s facility.
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 as a net amount in our consolidated statements of operations
beginning with April 2006. Transactions for periods prior to April
2006 are not reflected as a net amount; however the amounts are disclosed
parenthetically on the consolidated statements of operations, in accordance with
the provision of Emerging Issues Task Force Issue No. 04-13, “Accounting for
Purchases and Sales of Inventory with the Same Counterparty.” Had
this provision been in effect in the first quarter of 2006, our reported supply
and logistics revenues from unrelated parties for the year ended December 31,
2006 would have been reduced by $69 million to $803 million. Our
reported supply and logistics product costs from unrelated parties for the year
ended December 31, 2006 would have been reduced by $69 million to $781
million. This change had no effect on operating income, net income or
cash flows.
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.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
Cost of
sales for the CO
2
marketing
activities consists of a transportation fee charged by Denbury to transport the
CO
2
to
the customer through Denbury’s pipeline and insurance costs. The
transportation fee charged by Denbury is adjusted annually for
inflation. For the years ended December 31, 2008, 2007 and 2006, the
fee averaged $0.1927, $0.1848 and $0.1740 per Mcf, respectively.
Excise
and Sales Taxes
The
Company collects and remits 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 income statements.
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 statement of operations, is includable 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.
Derivative
Instruments and Hedging Activities
We
minimize our exposure to price risk by limiting our inventory
positions. However when we hold inventory positions in crude oil and
petroleum products, we use derivative instruments to hedge exposure to price
risk. DG Marine uses interest rate swap contracts to manage its
exposure to interest rate risk.
We
account for those derivative transactions in accordance with Statement of
Financial Accounting Standards No. 133 “Accounting for Derivative Instruments
and Hedging Activities”, as amended and interpreted. Derivative
transactions, which can include forward contracts and futures positions on the
NYMEX, are recorded on the balance sheet 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 cash and cash equivalents, accounts receivable, inventories,
other current assets, accounts payable, other current liabilities and
derivatives approximates their fair value due to their short-term
nature. The fair values of these instruments are represented in our
consolidated balance sheets.
Net
Income Per Common Unit
Our net
income is first allocated to the general partner based on the amount of
incentive distributions. The remainder is then allocated 98% to the
limited partners and 2% to the general partner. Basic net income per
limited partner unit is determined by dividing net income attributable to
limited partners by the weighted average number of outstanding limited partner
units during the period. Diluted net income per common unit is
calculated in the same manner, but also considers the impact to common units for
the potential dilution from phantom units outstanding. (See Note 15 for
discussion of phantom units.)
In a
period of net operating losses, incremental phantom units are excluded from the
calculation of diluted earnings per unit due to their anti-dilutive effect.
During 2008, we have reported net income; therefore incremental phantom units
have been included in the calculation of diluted earnings per
unit.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
EITF
03-06 addresses the computation of earnings per share by entities that have
issued securities other than common stock that contractually entitle the holder
to participate in dividends and earnings of the entity when, and if, it declares
dividends on its common stock (or partnership distributions to
unitholders). EITF 03-06 applies to any accounting period where our
aggregate net income exceeds our aggregate distribution. In such
periods, we are required to present earnings per unit as if all of the earnings
for the periods were distributed, regardless of the pro forma nature of this
allocation and whether those earnings would actually be distributed from an
economic or practical perspective. EITF 03-06 does not impact our
overall net income or other financial results; however, for periods in which
aggregate net income exceeds our aggregate distributions for such period, it
would have the impact of reducing the earnings per limited partner
units. This result occurs as a larger portion of our aggregate
earnings is allocated (as if distributed) to our general partner, even though we
make cash distributions on the basis of cash available for distributions (as
defined in our partnership agreement), not earnings, in any given
period. Our aggregate net earnings have not exceeded our aggregate
distributions; therefore EITF 03-06 has not had an impact on our calculation of
earnings per unit.
Effective
January 1, 2009, we adopted EITF 07-04 and EITF 03-06 will no longer be
applied. See “Recent and Proposed Accounting Announcements –
Implemented January 1, 2009” below.
Recent
and Proposed Accounting Pronouncements
Implemented
in 2008
FASB
Staff Position FIN 46(R)-8
In
December 2008, the FASB issued FASB Staff Position FIN 46(R)-8, “Disclosures
about Variable Interest Entities” (FSP FIN 46(R)-8). FSP FIN 46(R)-8 requires
enhanced disclosures about a company’s involvement in variable interest entities
(VIEs). The enhanced disclosures required by this FSP are intended to provide
users of financial statements with an greater understanding of: (1) the
significant judgments and assumptions made by a company in determining whether
it must consolidate a VIE and/or disclose information about its involvement with
a VIE; (2) the nature of restrictions on the assets of a VIE
that are consolidated and reported by a company in its statement of
financial position, including the carrying amounts of such assets; (3) the
nature of, and changes in, the risks associated with a company’s involvement
with a VIE; (4) how a company’s involvement with a VIE affects the
company’s financial position, financial performance, and cash flows. This FSP
was effective for us on December 31, 2008. See Note 3 for disclosures
regarding our involvement with VIEs.
SFAS
157
We
adopted Statement of Financial Accounting Standards (SFAS) No. 157,
“Fair Value Measurements” (SFAS 157), with respect to financial assets and
financial liabilities that are regularly adjusted to fair value, as of January
1, 2008. SFAS 157 provides a common fair value hierarchy to follow in
determining fair value measurements in the preparation of financial statements
and expands disclosure requirements relating to how such measurements were
developed. SFAS 157 does not require any new fair value measurements, but rather
applies to all other accounting pronouncements that require or permit fair value
measurements. On February 12, 2008 the Financial Accounting
Standards Board (FASB) issued Staff Position No. 157-2, “Effective Date of FASB
Statement No. 157” (FSP 157-2) which amends SFAS 157 to delay the effective
date for all non-financial assets and non-financial liabilities, except for
those that are recognized at fair value in the financial statements on a
recurring basis. The partial adoption of SFAS 157 as described above
had no material impact on us. We have not yet determined the impact,
if any, that the second phase of the adoption of SFAS 157 in 2009 will have
relating to its fair value measurements of non-financial assets and
non-financial liabilities. See Note 18 for further information
regarding fair-value measurements.
SFAS
159
In
February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for
Financial Assets and Financial Liabilities” (SFAS 159). This
statement was effective for us as of January 1, 2008. SFAS 159 permits entities
to choose to measure many financial instruments and certain other items at fair
value that are not currently required to be measured at fair value. We did not
elect to utilize voluntary fair value measurements as permitted by the
standard.
Implemented
January 1, 2009
SFAS
141(R)
In
December 2007, the FASB issued SFAS No. 141(R) “Business Combinations” (SFAS
141(R)). SFAS 141(R) replaces FASB Statement No. 141, “Business
Combinations.” This statement retains the purchase method of
accounting used in business combinations but replaces SFAS 141 by establishing
principles and requirements for the recognition and measurement of assets,
liabilities and goodwill, including the requirement that most transaction costs
and restructuring costs be charged to expense as incurred. In
addition, the statement requires disclosures to enable users of the financial
statements to evaluate the nature and financial effects of the business
combination. SFAS 141(R) is effective for business combinations for
which the acquisition date is on or after the beginning of the first annual
reporting period beginning on or after December 15, 2008. We adopted
SFAS 141(R) on January 1, 2009. Adoption will impact our accounting
for acquisitions we complete subsequent to that date.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
SFAS
160
In
December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in
Consolidated Financial Statements - an amendment of ARB No. 51” (SFAS 160). This
statement establishes accounting and reporting standards for noncontrolling
interests, which have been referred to as minority interests in prior
literature. A noncontrolling interest is the portion of equity in a
subsidiary not attributable, directly or indirectly, to a parent
company. This new standard requires, among other things, that (i)
ownership interests of noncontrolling interests be presented as a component of
equity on the balance sheet (i.e. elimination of the mezzanine “minority
interest” category); (ii) elimination of minority interest expense as a line
item on the statement of operations and, as a result, that net income be
allocated between the parent and the noncontrolling interests on the face of the
statement of operations; and (iii) enhanced disclosures regarding noncontrolling
interests. SFAS 160 is effective for fiscal years beginning after
December 15, 2008. We adopted SFAS 160 on January 1,
2009. Such adoption will impact the presentation of the minority
interests in Genesis Crude Oil, L.P. held by our general partner and DG Marine
held by our joint venture partner.
SFAS
161
In
March 2008, the FASB issued SFAS No. 161, “Disclosures about
Derivative Instruments and Hedging Activities-an amendment of FASB Statement
No.133” (SFAS 161). This Statement requires enhanced disclosures about (i) how
and why an entity uses derivative instruments, (ii) how derivative instruments
and related hedged items are accounted for under SFAS 133, and its related
interpretations, and (iii) how derivative instruments and related hedged items
affect an entity’s financial position, financial performance and cash flows.
This statement is effective for financial statements issued for fiscal years and
interim periods beginning after November 15, 2008. We adopted SFAS
No. 161 on January 1, 2009. Adoption did not have any material impact
on our financial position, results of operations or cash flows.
EITF
07-4
In March
2008, the Emerging Issues Task Force (or EITF) of the FASB issued EITF 07-4,
“Application of the Two-Class Method under FASB Statement No. 128,
Earnings per Share
, to Master
Limited Partnerships” (EITF 07-4). EITF 07-4 addresses the
application of the two-class method under SFAS No. 128 “Earnings Per Share” in
determining income per unit for master limited partnerships having multiple
classes of securities that may participate in partnership
distributions. To the extent the partnership agreement does not
explicitly limit distributions to the general partner, any earnings in excess of
distributions are to be allocated to the general partner and limited partners
utilizing the distribution formula for available cash specified in the
partnership agreement. When current period distributions are in
excess of earnings, the excess distributions are to be allocated to the general
partner and limited partners based on their respective sharing of losses
specified in the partnership agreement for the period. EITF 07-4 is
to be applied retrospectively for all financial statements presented and is
effective for financial statements issued for fiscal years beginning after
December 15, 2008, and interim periods within those fiscal
years. Earlier application is not permitted. We adopted
EITF 07-04 on January 1, 2009. Adoption will impact the net income
available to limited partners used in our computation of earnings per unit, but
will not impact our distributions to limited partners, financial position,
results of operations, or cash flows. For additional information on
our incentive distribution rights, see Note 10.
FASB
Staff Position No. 142-3
In April
2008, the FASB issued FASB Staff Position No. 142-3, “Determination of the
Useful Life of Intangible Assets” (FSP 142-3). This FSP amends the
factors that should be considered in developing renewal or extension assumptions
used to determine the useful life of an intangible asset under Statement of
Financial Accounting Standards No. 142, “Goodwill and other Intangible Assets.”
The purpose of this FSP is to develop consistency between the useful life
assigned to intangible assets and the cash flows from those
assets. FSP 142-3 is effective for fiscal years beginning after
December 31, 2008. We are currently evaluating the impact, if any,
that the standard will have on our consolidated financial
statements.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
3. Acquisitions
DG
Marine Transportation Investment
On July
18, 2008, DG Marine completed the acquisition of the inland marine
transportation business of Grifco Transportation, Ltd. (“Grifco”) and two of
Grifco’s affiliates. DG Marine is a joint venture we formed with TD
Marine, LLC, an entity owned by members of the Davison family. (See
discussion below on the acquisition of the Davison family businesses in 2007.).
TD Marine owns (indirectly) a 51% economic interest in the joint venture, DG
Marine, and we own (directly and indirectly) a 49% economic
interest. This acquisition gives us the capability to provide
transportation services of petroleum products by barge and complements our other
supply and logistics operations.
Grifco
received initial purchase consideration of approximately $80 million, comprised
of $63.3 million in cash and $16.7 million, or 837,690 of our common
units. A portion of the units are subject to certain lock-up
restrictions. DG Marine acquired substantially all of Grifco’s assets, including
twelve barges, seven push boats, certain commercial agreements, and
offices. Additionally, DG Marine and/or its subsidiaries
acquired the rights, and assumed the obligations, to take delivery of four new
barges in late third quarter of 2008 and four additional new barges late in
first quarter of 2009 (at a total price of approximately $27 million). Upon
delivery of the eight new barges, the acquisition of three additional push boats
(at an estimated cost of approximately $6 million), and after placing the barges
and push boats into commercial operations, DG Marine will be obligated to pay
additional purchase consideration of up to $12 million. At
December 31, 2008, DG Marine had taken delivery of four of the new barges and $6
million of the additional purchase price consideration was paid. At
December 31, 2008, the $5.9 million estimated present value of the remaining $6
million obligation is included in “Accrued Liabilities” in our consolidated
balance sheet. The effective interest rate of the obligation was
4.7%
The
Grifco acquisition and related closing costs were funded with $50 million of
aggregate equity contributions from us and TD Marine, in proportion to our
ownership percentages, and with borrowings of $32.4 million under a revolving
credit facility which is non-recourse to us and TD Marine (other than with
respect to our investments in DG Marine). Although DG
Marine’s debt is non-recourse to us, our ownership interest in DG Marine is
pledged to secure its indebtedness. We funded our $24.5 million equity
contribution with $7.8 million of cash and 837,690 of our common units, valued
at $19.896 per unit, for a total value of $16.7 million. At closing,
we also redeemed 837,690 of our common units from the Davison
family. See Notes 10 and 11.
We have
entered into a subordinated loan agreement with DG Marine whereby we may (at our
sole discretion) lend up to $25 million to DG Marine. The loan
agreement provides for DG Marine to pay us interest on any loans at the rate at
which we borrowed funds under our credit facility plus 4%. Those
loans will mature on January 31, 2012. Under that subordinated loan
agreement, DG Marine is required to make monthly payments to us of principal and
interest to the extent DG Marine has any available cash that otherwise would
have been distributed to the owners of DG Marine in respect of their equity
interest. DG Marine’s revolving credit facility includes restrictions
on DG Marine’s ability to make specified payments under the subordinated loan
agreement and distributions in respect of our equity interest. At
December 31, 2008, there were no amounts outstanding under the subordinated loan
agreement. We have, however, provided a $7.5 million guaranty to the lenders
under DG Marine’s credit facility. This guaranty will expire on May
31, 2009, if DG Marine’s leverage ratio under its credit facility is less than
4.00 to 1.00 at May 31, 2009.
The
provisions of Financial Interpretation No. 46(R) “Consolidation of Variable
Interest Entities” (FIN 46R), require the primary beneficiary to consolidate
variable interest entities. As stated in FIN 46R, in determining the
primary beneficiary of a variable interest entity ("VIE") that is held between
two or more related parties the primary beneficiary is considered to be the
party that is "most closely associated" with the VIE. We are
considered to be the primary beneficiary due to (i) our involvement in the
design of DG Marine, (ii) the ongoing involvement with regards to financial and
operating decision making of DG Marine, excluding matters related to new
contracts and vessel disposal which are decided solely by TD Marine, and (iii)
the financial support we provide to DG Marine. TD Marine has no
requirements to make any additional contributions to DG Marine.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
As we are
considered the primary beneficiary, DG Marine is consolidated in our
consolidated financial statements and the 51% ownership interest of TD Marine in
the net assets and net income of DG Marine is included in minority interests in
our consolidated financial statements.
The
acquisition cost allocated to the assets consists of $63.3 million of cash,
$16.7 million of value from the issuance of our limited partnership units to
Grifco, $11.7 million related to the discounted value of the additional
consideration that will be owed to Grifco when the barges under construction are
placed in service and $2.4 million of transaction costs. The
acquisition cost has been allocated to the assets acquired based on estimated
fair values. Such fair values were developed by
management.
The
allocation of the acquisition cost is summarized as follows:
Property
and equipment
|
|
$
|
91,772
|
|
Amortizable
intangible assets:
|
|
|
|
|
Customer
relationships
|
|
|
800
|
|
Trade
name
|
|
|
900
|
|
Non-compete
agreements
|
|
|
600
|
|
Total
allocated cost
|
|
$
|
94,072
|
|
The
weighted average amortization period for the intangible assets at the date of
acquisition is 10 years for customer relationships, 3 years for the trade name
and 7 years for the non-compete agreements. The weighted average
amortization period for all intangible assets acquired in the Grifco transaction
was 6 years.
See
additional information on intangible assets and goodwill in Note 9.
At
December 31, 2008, our Consolidated Balance Sheets included the following
amounts related to DG Marine:
Cash
|
|
$
|
623
|
|
Accounts
receivable - trade
|
|
|
2,812
|
|
Other
current assets
|
|
|
859
|
|
Fixed
assets, at cost
|
|
|
110,214
|
|
Accumulated
depreciation
|
|
|
(3,084
|
)
|
Intangible
assets, net
|
|
|
2,208
|
|
Other
assets
|
|
|
2,178
|
|
Total
assets
|
|
$
|
115,810
|
|
|
|
|
|
|
Accounts
payable
|
|
$
|
1,072
|
|
Accrued
liabilities
|
|
|
9,258
|
|
Long-term
debt
|
|
|
55,300
|
|
Other
long-term liabilities
|
|
|
1,393
|
|
Minority
interests
|
|
|
24,233
|
|
Total
liabilities
|
|
$
|
91,256
|
|
2008
Denbury Drop-Down Transactions
On May
30, 2008, we completed two “drop-down” transactions with Denbury Onshore LLC,
(Denbury Onshore), a wholly-owned subsidiary of Denbury Resources Inc., the
indirect owner of our general partner.
NEJD
Pipeline System
In 2008,
we entered into a twenty-year financing lease transaction with Denbury valued at
$175 million and related to Denbury’s North East Jackson Dome (NEJD) Pipeline
System. The NEJD Pipeline System is a 183-mile, 20” pipeline
extending from the Jackson Dome, near Jackson, Mississippi, to near
Donaldsonville, Louisiana, and is currently being leased and used by Denbury for
its Phase I area of tertiary operations in southwest Mississippi. We
recorded this lease arrangement in our consolidated financial statements as a
direct financing lease. Under the terms of the agreement, Denbury Onshore began
making quarterly rent payments beginning August 30, 2008. These
quarterly rent payments are fixed at $5,166,943 per quarter or approximately
$20.7 million per year during the lease term at an interest rate of
10.25%. At the end of the lease term, we will convey all of our
interests in the NEJD Pipeline to Denbury Onshore for a nominal
payment.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
The NEJD
Pipeline System is a 183-mile, 20” CO
2
pipeline
extending from the Jackson Dome, near Jackson, Mississippi, to near Donaldson,
Louisiana, currently being used by Denbury for its tertiary operations in
southwest Mississippi. Denbury has the rights to exclusive use of the
NEJD Pipeline System, will be responsible for all operations and maintenance on
that system, and will bear and assume all obligations and liabilities with
respect to that system. The NEJD transaction was funded with
borrowings under our credit facility.
See
additional discussion of this direct financing lease in Note 6.
Free
State Pipeline System
We
purchased Denbury’s Free State Pipeline for $75 million, consisting of $50
million in cash which we borrowed under our credit facility, and $25 million in
the form of 1,199,041 of our common units. The number of common units
issued was based on the average closing price of our common units from May 28,
2008 through June 3, 2008.
The Free
State Pipeline is an 86-mile, 20” pipeline that extends from Denbury’s CO
2
source
fields at Jackson Dome, near Jackson, Mississippi, to Denbury’s oil fields in
east Mississippi. We entered into a twenty-year transportation
services agreement to deliver CO
2
on the
Free State pipeline for Denbury’s use in its tertiary recovery
operations. Under the terms of the transportation
services agreement, we are responsible for owning, operating, maintaining and
making improvements to that pipeline. Denbury has rights to exclusive
use of that pipeline and is required to use that pipeline to supply CO
2
to its
current and certain of its other tertiary operations in east
Mississippi. The transportation services agreement provides for a
$100,000 per month minimum payment, which is accounted for as an operating
lease, plus a tariff based on throughput. Denbury has two renewal options, each
for five years on similar terms. Any sale by us of the Free State Pipeline and
related assets or of an ownership interest in our subsidiary that holds such
assets would be subject to a right of first refusal purchase option in favor of
Denbury.
Davison
Businesses Acquisition
On July
25, 2007, we acquired five energy-related businesses from several entities owned
and controlled by the Davison family of Ruston, Louisiana (the “Davison
Acquisition”). The businesses include the operations that comprise
our refinery services division, and other operations included in our supply and
logistics division, which transport, store, procure and market petroleum
products and other bulk commodities. The assets acquired in this
transaction provide us with opportunities to expand our services to energy
companies in the areas in which we operate.
For
financial reporting purposes, the consideration for this acquisition consisted
of $623 million of value, net of cash acquired. The consideration is
comprised of $293 million in cash, (which is net of $21.7 million of cash
acquired), and 13,459,209 common units of Genesis valued at $330
million. In accordance with EITF, No. 99-12, “Determination of the
Measurement Date for the Market Price of Acquirer Securities Issued in a
Purchase Business Combination,” the fair value of Genesis common units issued
was determined using an average price of $24.52, which was the average closing
price of Genesis common units for the two days before and after the date on
which the terms of the acquisition were agreed to and announced. The
direct transaction costs totaled $8.9 million and consist primarily of legal and
accounting fees and other external costs related directly to the
acquisition.
The
Davison family is our largest unitholder, with approximately 33% of our
outstanding common units. It has designated two of the family members
to the board of directors of our general partner, and as long as it maintains a
specified minimum percentage of our common units, it will have the continuing
right to designate up to two directors. The Davison family has agreed
to restrictions that limit its ability to sell specified percentages of its
common units through July 26, 2010. Pursuant to an agreement between
us and the Davison unitholders, the Davison unitholders have registration rights
with respect to their common units. These rights include the right to require us
to file a Form S-3 shelf registration statement, if we are
eligible.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
The purchase price has been allocated
to the assets acquired and liabilities assumed based on estimated fair
values. Such fair values were developed by management. The allocation
of the purchase price is summarized as follows:
Cash
and cash equivalents
|
|
$
|
21,686
|
|
Accounts
receivable
|
|
|
55,631
|
|
Inventories
|
|
|
10,825
|
|
Other
current assets
|
|
|
982
|
|
Other
assets
|
|
|
294
|
|
Property
and equipment
|
|
|
67,655
|
|
Goodwill
|
|
|
316,739
|
|
Amortizable
intangible assets:
|
|
|
|
|
Customer
relationships
|
|
|
129,284
|
|
Supplier
agreements
|
|
|
36,469
|
|
Licensing
agreements
|
|
|
38,678
|
|
Trade
name
|
|
|
17,988
|
|
Covenants
not-to-compete
|
|
|
695
|
|
Favorable
lease agreement
|
|
|
13,260
|
|
Accounts
payable and accrued expenses
|
|
|
(35,230
|
)
|
Deferred
tax liabilties assumed
|
|
|
(21,794
|
)
|
Total
allocation
|
|
$
|
653,162
|
|
See
additional information on intangible assets and goodwill in Note
9. Goodwill represents the residual of the purchase price over the
fair value of net tangible and identifiable intangible assets
acquired.
The
following table presents selected unaudited pro forma financial information
incorporating the historical operating results of the Davison
businesses. The effective closing date of our purchase of the Davison
businesses was July 25, 2007. As a result, our Consolidated
Statements of Operations for the year ended December 31, 2007 includes five
months of results of operations of these acquired businesses. The pro
forma financial information has been prepared as if the acquisition had been
completed on the first day of each period presented rather than the actual
closing date. The pro forma financial information has been prepared
based upon assumptions deemed appropriate by us and may not be indicative of
actual results.
|
|
Year
Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
Pro
Forma Earnings Data:
|
|
|
|
|
|
|
Revenue
|
|
$
|
1,574,730
|
|
|
$
|
1,479,174
|
|
Costs
and expenses
|
|
|
1,572,809
|
|
|
|
1,477,275
|
|
Operating
income
|
|
|
1,921
|
|
|
|
1,899
|
|
(Loss)
Income before extraordinary items
|
|
|
(29,666
|
)
|
|
|
(19,664
|
)
|
Net
(loss) income
|
|
|
(29,666
|
)
|
|
|
(19,664
|
)
|
|
|
|
|
|
|
|
|
|
Basic
and diluted (loss) earnings per unit:
|
|
|
|
|
|
|
|
|
As
reported units outstanding
|
|
|
20,754
|
|
|
|
13,784
|
|
Pro
forma units outstanding
|
|
|
28,319
|
|
|
|
28,319
|
|
As
reported net (loss) income per unit
|
|
$
|
(0.64
|
)
|
|
$
|
0.59
|
|
Pro
forma net (loss) income per unit
|
|
$
|
(1.05
|
)
|
|
$
|
(0.69
|
)
|
Port
Hudson Assets Acquisition
Effective
July 1, 2007, we paid $8.1 million for BP Pipelines (North America) Inc.’s Port
Hudson crude oil truck terminal, marine terminal, and marine dock on the
Mississippi River, which includes 215,000 barrels of tankage, a pipeline and
other related assets in East Baton Rouge Parish, Louisiana. The acquisition was
funded with borrowings under our credit facility.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
The
purchase price has been allocated to the assets acquired based on estimated fair
values. The allocation of the purchase price is summarized as
follows:
Property
and equipment
|
|
$
|
4,134
|
|
Goodwill
|
|
|
3,969
|
|
Total
|
|
$
|
8,103
|
|
See
additional information on goodwill in Note 9.
4. Inventories
The major
components of inventories were as follows:
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
Crude
oil
|
|
|
1,878
|
|
|
|
3,710
|
|
Petroleum
products
|
|
|
5,589
|
|
|
|
6,527
|
|
Caustic
soda
|
|
|
7,139
|
|
|
|
1,998
|
|
NaHS
|
|
|
6,923
|
|
|
|
3,557
|
|
Other
|
|
|
15
|
|
|
|
196
|
|
Total
inventories
|
|
$
|
21,544
|
|
|
$
|
15,988
|
|
Our
inventory at December 31, 2008 is net of charges totaling $1.2 million that we
recorded to reduce the cost basis of our crude oil and petroleum products
inventory to reflect market value. The lower of cost or market
adjustment is included in “Product Costs” of our Supply & Logistics segment
on our consolidated statements of operations. The costs of
inventories did not exceed market values at December 31, 2007.
5. Fixed
Assets and Asset Retirement Obligations
Fixed
Assets
Fixed
assets consisted of the following.
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
Land,
buildings and improvements
|
|
$
|
13,549
|
|
|
$
|
11,978
|
|
Pipelines
and related assets
|
|
|
139,184
|
|
|
|
63,169
|
|
Machinery
and equipment
|
|
|
22,899
|
|
|
|
25,097
|
|
Transportation
equipment
|
|
|
32,833
|
|
|
|
32,906
|
|
Barges
and push boats
|
|
|
96,865
|
|
|
|
-
|
|
Office
equipment, furniture and fixtures
|
|
|
4,401
|
|
|
|
2,759
|
|
Construction
in progress
|
|
|
27,906
|
|
|
|
7,102
|
|
Other
|
|
|
11,575
|
|
|
|
7,402
|
|
Subtotal
|
|
|
349,212
|
|
|
|
150,413
|
|
Accumulated
depreciation and impairment
|
|
|
(67,107
|
)
|
|
|
(48,413
|
)
|
Total
|
|
$
|
282,105
|
|
|
$
|
102,000
|
|
In 2008,
2007 and 2006, $276,000, $57,000 and $9,000 of interest cost, respectively, were
capitalized related to the construction of pipelines and related
assets.
Depreciation
expense was $20,415,000, $8,909,000 and $3,719,000 for the years ended December
31, 2008, 2007, and 2006, respectively.
Asset
Impairment Charge
During
the fourth quarter of 2007, changes in the source of the supply of natural gas
to our natural gas gathering pipelines (which are included in our pipeline
transportation segment) indicated to us that the carrying amount of our natural
gas gathering pipelines might not be recoverable. We made certain
assumptions when estimating future cash flows to be generated from the assets
including declines in future sales volumes and costs of testing required for
integrity purposes. As a result, we tested the carrying value of
these assets for recoverability, and determined that we should record an
impairment charge of $1,498,000 related to these assets.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
Asset
Retirement Obligations
In
general, our future asset retirement obligations relate to future costs
associated with the removal of certain segments of our oil, natural gas and
CO
2
pipelines, barge decommissioning, removal of equipment and facilities from
leased acreage and land restoration. The fair value of a liability for an asset
retirement obligation is recorded in the period in which it is incurred,
discounted to its present value using our credit adjusted risk-free interest
rate, and a corresponding amount capitalized by increasing the carrying amount
of the related long-lived asset. The capitalized cost is depreciated over the
useful life of the related asset. Accretion of the discount increases
the liability and is recorded to expense.
A
reconciliation of our liability for asset retirement obligations is as
follows:
Asset
retirement obligations as of December 31, 2006
|
|
$
|
708
|
|
Liabilities
incurred and assumed in the current period
|
|
|
468
|
|
Revisions
in estimated retirement obligations
|
|
|
(81
|
)
|
Accretion
expense
|
|
|
78
|
|
Asset
retirement obligations as of December 31, 2007
|
|
|
1,173
|
|
Liabilities
incurred and assumed in the current period
|
|
|
121
|
|
Accretion
expense
|
|
|
136
|
|
Asset
retirement obligations as of December 31, 2008
|
|
$
|
1,430
|
|
At
December 31, 2008, $0.2 million of our asset retirement obligation was
classified in “Accrued liabilities” under current liabilities in our
Consolidated Balance Sheets. Liabilities incurred and assumed during the period
are for properties acquired during each year. Certain of our
unconsolidated affiliates have asset retirement obligations recorded at December
31, 2008 and 2007 relating to contractual agreements. These amounts
are immaterial to our consolidated financial statements.
6. Net
Investment in Direct Financing Leases
In the
fourth quarter of 2004, we constructed two segments of crude oil pipeline and a
CO
2
pipeline segment to transport crude oil from and CO
2
to
producing fields operated by Denbury. Denbury pays us a minimum
payment each month for the right to use these pipeline
segments. Those arrangements have been accounted for as direct
financing leases. As discussed in Note 3, we entered into a lease
arrangement with Denbury related to the NEJD Pipeline in May 2008 that is being
accounted for as a direct financing lease. Denbury pays us fixed
payments of $5.2 million per quarter that began in August 2008.
The
following table lists the components of the net investment in direct financing
leases:
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
Total
minimum lease payments to be received
|
|
$
|
407,392
|
|
|
$
|
7,039
|
|
Estimated
residual values of leased property (unguaranteed)
|
|
|
1,287
|
|
|
|
1,287
|
|
Unamortized
initial direct costs
|
|
|
2,580
|
|
|
|
-
|
|
Less
unearned income
|
|
|
(230,298
|
)
|
|
|
(2,953
|
)
|
Net
investment in direct financing leases
|
|
$
|
180,961
|
|
|
$
|
5,373
|
|
At
December 31, 2008, minimum lease payments to be received for each of the five
succeeding fiscal years are $21.9 million per year for 2009 through 2011, $21.8
million for 2012 and $21.3 million for 2013.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
7. CO
2
Assets
CO
2
assets
consisted of the following.
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
CO
2
volumetric production payments
|
|
$
|
43,570
|
|
|
$
|
43,570
|
|
Less
- Accumulated amortization
|
|
|
(19,191
|
)
|
|
|
(14,654
|
)
|
Net
CO
2
assets
|
|
$
|
24,379
|
|
|
$
|
28,916
|
|
The
volumetric production payments entitle us to a maximum daily quantity of CO
2
of 101,375
million cubic feet, or Mcf, per day through December 31, 2009, 91,875 Mcf per
day for the calendar years 2010 through 2012 and 73,875 Mcf per day beginning in
2013 until we have received all volumes under the production
payments. Under the terms of transportation agreements with Denbury,
Denbury will process and deliver this CO
2
to our
industrial customers and receive a fee of $0.16 per Mcf, subject to inflationary
adjustments. During 2008 this fee averaged $0.1927 per
Mcf.
The terms
of the contracts with the industrial customers include minimum take-or-pay and
maximum delivery volumes. The seven industrial contracts expire at various dates
between 2010 and 2016, with one small contract extending until
2023.
The
CO
2
assets are being amortized on a units-of-production method. After
purchase price adjustments, we had 276.7 Bcf of CO
2
at
acquisition, and the total $43.6 million cost is being amortized based on the
volume of CO
2
sold each
month. For 2008, 2007 and 2006, we recorded amortization
of $4,537,000, $4,488,000 and $4,244,000, respectively. We have 153.8
Bcf of CO
2
remaining
under the volumetric production payments at December 31, 2008. Based
on the historical deliveries of CO
2
to the
customers (which have exceeded minimum take-or-pay volumes), we expect
amortization for the next five years to be approximately $4,537,000 from 2009 to
2010, $4,157,000 for 2011 and 2012 and $3,431,000 for 2013.
8. Equity
Investees and Other Investments
Equity
Investees
We are
accounting for our 50% ownership in each of two joint ventures, T&P Syngas
and Sandhill under the equity method of accounting. We paid
$7.8 million more for our interest in these joint ventures than our share of
capital on their balance sheets at the date of the acquisition. This
excess amount of the purchase price over the equity in the joint ventures has
been allocated to the tangible and intangible assets of the joint ventures based
on the fair value of those assets, with the remainder of the excess purchase
price of $0.7 million allocated to goodwill. The table below reflects
information included in our consolidated financial statements related to our
equity investees.
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Genesis'
share of operating earnings
|
|
|
1,137
|
|
|
|
1,898
|
|
|
|
1,690
|
|
Amortization
of excess purchase price
|
|
|
(628
|
)
|
|
|
(628
|
)
|
|
|
(559
|
)
|
Net
equity in earnings
|
|
$
|
509
|
|
|
$
|
1,270
|
|
|
$
|
1,131
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions
received
|
|
$
|
2,158
|
|
|
$
|
2,240
|
|
|
$
|
2,093
|
|
Other
Projects
We have
also invested $4.6 million in the Faustina Project, a petroleum coke to ammonia
project that is in the development stage. All of our investment may
later be redeemed, with a return, or converted to equity after the project has
obtained construction financing. The funds we have invested are being
used for project development activities, which include the negotiation of
off-take agreements for the products and by-products of the plant to be
constructed, securing permits and securing financing for the construction phase
of the plant. We have recorded our investment in this debt security
at cost and classified it as held-to-maturity, since we have the intent and
ability to hold it until it is redeemed.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
No events
or changes in circumstances have occurred that indicate a significant adverse
effect on the fair value of our investment at December 31, 2008, therefore the
investment is included in our consolidated balance sheet at cost.
9. Intangible
Assets, Goodwill and Other Assets
Intangible
Assets
In
connection with the Davison and DG Marine acquisitions (See Note 3), we
allocated a portion of the purchase price to intangible assets based on their
fair values. The following table reflects the components of
intangible assets being amortized at December 31, 2008:
|
|
|
|
|
December
31, 2008
|
|
|
December
31, 2007
|
|
|
|
Weighted
Amortization Period in Years
|
|
|
Gross
Carrying Amount
|
|
|
Accumulated
Amortization
|
|
|
Carrying
Value
|
|
|
Gross
Carrying Amount
|
|
|
Accumulated
Amortization
|
|
|
Carrying
Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinery
services customer relationships
|
|
5
|
|
|
$
|
94,654
|
|
|
$
|
26,017
|
|
|
$
|
68,637
|
|
|
$
|
94,654
|
|
|
$
|
9,380
|
|
|
$
|
85,274
|
|
Supply
and logistics customer relationships
|
|
5
|
|
|
|
35,430
|
|
|
|
9,957
|
|
|
|
25,473
|
|
|
|
34,630
|
|
|
|
3,287
|
|
|
|
31,343
|
|
Refinery
services supplier relationships
|
|
2
|
|
|
|
36,469
|
|
|
|
24,483
|
|
|
|
11,986
|
|
|
|
36,469
|
|
|
|
9,241
|
|
|
|
27,228
|
|
Refinery
services licensing agreements
|
|
6
|
|
|
|
38,678
|
|
|
|
7,176
|
|
|
|
31,502
|
|
|
|
38,678
|
|
|
|
2,218
|
|
|
|
36,460
|
|
Supply
and logistics trade names - Davison and Grifco
|
|
7
|
|
|
|
18,888
|
|
|
|
3,118
|
|
|
|
15,770
|
|
|
|
17,988
|
|
|
|
930
|
|
|
|
17,058
|
|
Supply
and logistics favorable lease
|
|
15
|
|
|
|
13,260
|
|
|
|
671
|
|
|
|
12,589
|
|
|
|
13,260
|
|
|
|
197
|
|
|
|
13,063
|
|
Other
|
|
5
|
|
|
|
1,322
|
|
|
|
346
|
|
|
|
976
|
|
|
|
721
|
|
|
|
97
|
|
|
|
624
|
|
Total
|
|
5
|
|
|
$
|
238,701
|
|
|
$
|
71,768
|
|
|
$
|
166,933
|
|
|
$
|
236,400
|
|
|
$
|
25,350
|
|
|
$
|
211,050
|
|
The
licensing agreements referred to in the table above relate to the agreements we
have with refiners to provide services. The trade names are the
Davison and Grifco names, which we retained the right to use in our
operations. The favorable lease relates to a lease of 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 favorable
lease and other intangible assets are being amortized on a straight-line
basis. Amortization expense on intangible assets was $46.4 million
and $25.4 million for the years ended December 31, 2008 and 2007,
respectively.
The
following table reflects our estimated amortization expense for each of the five
subsequent fiscal years:
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
Refinery
services customer relationships
|
|
$
|
15,433
|
|
|
$
|
11,689
|
|
|
$
|
8,972
|
|
|
$
|
7,056
|
|
|
$
|
7,116
|
|
Supply
and logistics customer relationships
|
|
|
5,536
|
|
|
|
4,488
|
|
|
|
3,603
|
|
|
|
2,819
|
|
|
|
2,165
|
|
Refinery
services supplier relationships
|
|
|
4,068
|
|
|
|
2,925
|
|
|
|
2,629
|
|
|
|
2,364
|
|
|
|
-
|
|
Refinery
services licensing agreements
|
|
|
4,505
|
|
|
|
4,105
|
|
|
|
3,690
|
|
|
|
3,416
|
|
|
|
3,163
|
|
Supply
and logistics trade name
|
|
|
2,326
|
|
|
|
2,086
|
|
|
|
1,851
|
|
|
|
1,432
|
|
|
|
1,237
|
|
Supply
and logistics favorable lease
|
|
|
474
|
|
|
|
474
|
|
|
|
474
|
|
|
|
474
|
|
|
|
474
|
|
Other
|
|
|
285
|
|
|
|
187
|
|
|
|
53
|
|
|
|
54
|
|
|
|
56
|
|
Total
|
|
$
|
32,627
|
|
|
$
|
25,954
|
|
|
$
|
21,272
|
|
|
$
|
17,615
|
|
|
$
|
14,211
|
|
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
Goodwill
The
carrying amount of goodwill by business segment at December 31, 2008 and 2007
was as follows:
|
|
Refinery
|
|
|
Supply
&
|
|
|
|
|
|
|
Services
|
|
|
Logistics
|
|
|
Total
|
|
2007
Additions:
|
|
|
|
|
|
|
|
|
|
Davison
acquisition
|
|
$
|
297,621
|
|
|
$
|
19,118
|
|
|
$
|
316,739
|
|
Port
Hudson Assets Acquisition
|
|
|
-
|
|
|
|
3,969
|
|
|
|
3,969
|
|
Balance,
December 31, 2007
|
|
|
297,621
|
|
|
|
23,087
|
|
|
|
320,708
|
|
Davison
acquisition, due to purchase price adjustments
|
|
|
4,338
|
|
|
|
-
|
|
|
|
4,338
|
|
December
31, 2008
|
|
$
|
301,959
|
|
|
$
|
23,087
|
|
|
$
|
325,046
|
|
We
performed our annual goodwill impairment test pursuant to SFAS 142 on October 1,
2008. The fair value of our supply and logistics and refinery
services reporting units were estimated using a combined income (discounted cash
flow) and market approach (guideline public company and comparable merged and
acquired transactions) valuation method which indicated that the fair value of
our net assets in each reporting unit exceeded the carrying value of that
reporting unit, and an impairment charge was not required. The
estimated fair value of our reporting units is dependent on several significant
assumptions and estimates, including our growth rates for revenues and costs,
changes in operating margins, future capital expenditures related to our
existing operations, our cost of capital (discount rate) and cash flow market
multiples. Our business plans and recent operating results also
impact our estimate of the fair value of our reporting units.
SFAS 142
requires the performance of an interim goodwill impairment test if an event
occurs or circumstances change that would more likely than not reduce the fair
value of a reporting unit below its carrying value. Due to the
ongoing deterioration of the credit markets and the overall macroeconomic
conditions existing at December 31, 2008, we evaluated our fourth quarter
performance and the outlook for our business segments, also considering the
decline in our market capitalization, and concluded that we did not have a
triggering event in the fourth quarter that would require the performance of an
interim goodwill impairment test.
We will
continue to monitor the general economic conditions, our operational and
financial performance measures and our market capitalization to determine if a
triggering event occurs and will perform an interim goodwill impairment
analysis, if necessary. We have not recognized any impairment losses
related to goodwill for any of the periods presented.
Other
Assets
Other
assets consisted of the following.
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
Credit
facility fees - Genesis
|
|
$
|
5,022
|
|
|
$
|
5,022
|
|
Credit
facility fees - DG Marine
|
|
|
2,536
|
|
|
|
-
|
|
Initial
direct costs related to Free State Pipeline lease
|
|
|
1,132
|
|
|
|
-
|
|
Deferred
tax asset
|
|
|
1,543
|
|
|
|
941
|
|
Other
deferred costs and deposits
|
|
|
7,502
|
|
|
|
3,284
|
|
|
|
|
17,735
|
|
|
|
9,247
|
|
Less
- Accumulated amortization
|
|
|
(2,322
|
)
|
|
|
(850
|
)
|
Net
other assets
|
|
$
|
15,413
|
|
|
$
|
8,397
|
|
Amortization
of the initial direct costs related to the Free State Pipeline lease for the
year ended December 31, 2008 was $35,000. Amortization expense of
credit facility fees for the years ended December 31, 2008, 2007 and 2006 was
$1,437,000, $779,000 and $394,000, respectively. In the fourth
quarter of 2006, we also charged to expense $575,000 of unamortized fees related
to the facility that we replaced in November 2006. Total
amortization of initial direct costs and credit facility fees for the next five
years will be $1,993,000 for 2009 and 2010, $1,465,000 in 2011 and $60,000 in
2012 and 2013.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
10. Debt
At
December 31, 2008 our obligations under credit facilities consisted of the
following:
|
|
December
31, 2008
|
|
|
December
31, 2007
|
|
|
|
|
|
|
|
|
Genesis
Credit Facility
|
|
$
|
320,000
|
|
|
$
|
80,000
|
|
DG
Marine Credit Facility (non-recourse to Genesis)
|
|
|
55,300
|
|
|
|
-
|
|
Total
Long-Term Debt
|
|
$
|
375,300
|
|
|
$
|
80,000
|
|
Genesis
Credit Facility
We have a
$500 million credit facility $100 million of which can be used for letters of
credit, with a group of banks led by Fortis Capital Corp. and Deutsche Bank
Securities Inc. The borrowing base is recalculated quarterly and at
the time of material acquisitions. The borrowing base represents the
amount that can be borrowed or utilized for letters of credit from a credit
standpoint based on our EBITDA (earnings before interest, taxes, depreciation
and amortization), computed in accordance with the provisions of our credit
facility.
The
borrowing base may be increased to the extent of pro forma additional EBITDA, as
defined in the credit agreement, attributable to acquisitions or internal growth
projects with approval of the lenders. Our borrowing base as of
December 31, 2008 exceeds $500 million.
At
December 31, 2008, we had $320 million borrowed under our credit facility and we
had $3.5 million in letters of credit outstanding. 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
November 15, 2011. The total amount available for borrowings at
December 31, 2008 was $176.5 million under our credit facility.
The key
terms for rates under our credit facility are as follows:
|
·
|
The
interest rate on borrowings may be based on the prime rate or the LIBOR
rate, at our option. The interest rate on prime rate loans can
range from the prime rate plus 0.50% to the prime rate plus
1.875%. The interest rate for LIBOR-based loans can range from
the LIBOR rate plus 1.50% to the LIBOR rate plus 2.875%. The
rate is based on our leverage ratio as computed under the credit
facility. Our leverage ratio is recalculated quarterly and in
connection with each material acquisition. At December
31, 2008, our borrowing rates were the prime rate plus 0.50% or the LIBOR
rate plus 1.50%.
|
|
·
|
Letter
of credit fees will range from 1.50% to 2.875% based on our leverage ratio
as computed under the credit facility. The rate can fluctuate
quarterly. At December 31, 2008, our letter of credit rate was
1.50%.
|
|
·
|
We
pay a commitment fee on the unused portion of the $500 million maximum
facility amount. The commitment fee will range from 0.30% to
0.50% based on our leverage ratio as computed under the credit
facility. The rate can fluctuate quarterly. At
December 31, 2008, the commitment fee rate was
0.30%.
|
Collateral
under the credit facility consists of substantially all our assets, excluding
our interest in the NEJD pipeline, our ownership interest in the Free State
pipeline, and the assets of and our equity interest in, DG Marine. All of the
equity interest of DG Marine is pledged to secure its credit facility, which is
described below. While our general partner is jointly and severally
liable for all of our obligations unless and except to the extent those
obligations provide that they are non-recourse to our general partner, our
credit facility expressly provides that it is non-recourse to our general
partner (except to the extent of its pledge of its general partner interest in
certain of our subsidiaries), as well as to Denbury and its other
subsidiaries.
Our
credit facility contains customary covenants (affirmative, negative and
financial) that limit the manner in which we may conduct our
business. Our credit facility contains three primary financial
covenants - a debt service coverage ratio, leverage ratio and funded
indebtedness to capitalization ratio – that require us to achieve specific
minimum financial metrics. In general, our debt service coverage
ratio calculation compares EBITDA (as defined and adjusted in accordance with
the credit facility) to interest expense. Our leverage ratio
calculation compares our consolidated funded debt (as calculated in accordance
with our credit facility) to EBITDA (as adjusted). Our funded
indebtedness ratio compares outstanding debt to the sum of our consolidated
total funded debt plus our consolidated net worth.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
Required
|
|
Actual
|
|
|
|
|
Ratio
through
|
|
Ratio
as of
|
|
|
|
|
December
31,
|
|
December
31,
|
Financial
Covenant
|
|
Requirement
|
|
2008
|
|
2008
|
|
|
|
|
|
|
|
Debt
Service Coverage Ratio
|
|
Minimum
|
|
2.75
to 1.0
|
|
8.53
to 1.0
|
Leverage
Ratio
|
|
Maximum
|
|
6.0
to 1.0
|
|
2.82
to 1.0
|
Funded
Indebtedness Ratio
|
|
Maximum
|
|
0.80
to 1.0
|
|
0.39
to 1.0
|
Our
credit facility includes provisions for the temporary adjustment of the required
ratios following material acquisitions and with lender approval. The
ratios in the table above are the required ratios for the period following a
material acquisition. If we meet these financial metrics and are not
otherwise in default under our credit facility, we may make quarterly
distributions; however, the amount of such distributions may not exceed the sum
of the distributable cash (as defined in the credit facility) generated by us
for the eight most recent quarters, less the sum of the distributions made with
respect to those quarters. At December 31, 2008, the excess of
distributable cash over distributions under this provision of the credit
facility was $49.7 million.
DG
Marine Credit Facility
In
connection with its acquisition of the Grifco assets on July 18, 2008, DG Marine
entered into a $90 million revolving credit facility with a syndicate of banks
led by SunTrust Bank and BMO Capital Markets Financing, Inc. In
addition to partially financing the Grifco acquisition, DG Marine may borrow
under that facility for general corporate purposes, such as paying for its newly
constructed barges and funding working capital requirements, including up to $5
million in letters of credit. That facility, which matures on July
18, 2011, is secured by all of the equity interests issued by DG Marine and
substantially all of DG Marine’s assets. Other than the pledge of our
equity interest in DG Marine and our guaranty of $7.5 million, that facility is
non-recourse to us and TD Marine. At December 31, 2008, our
consolidated balance sheet included $115.8 million of DG Marine’s assets in our
total assets.
At
December 31, 2008, DG Marine had $55.3 million outstanding under its credit
facility. Due to the revolving nature of loans under the DG Marine
credit facility, additional borrowings and periodic repayments and re-borrowings
may be made until the maturity date. The total amount available for
borrowings at December 31, 2008 was $34.7 million under this credit
facility.
The key
terms for rates under the DG Marine credit facility are as follows:
|
·
|
The
interest rate on borrowings may be based on the prime rate or the LIBOR
rate, at our option. The interest rate on prime rate loans can
range from the prime rate plus 1.50% to the prime rate plus
4.00%. The interest rate for LIBOR-based loans can range from
the LIBOR rate plus 2.50% to the LIBOR rate plus 5.00%. The
rate is based on DG Marine’s leverage ratio as computed under the credit
facility. Under the terms of DG Marine’s credit facility, the rates will
fluctuate quarterly based on the leverage ratio. At December 31, 2008, DG
Marine’s borrowing rates were the prime rate plus 4.00% or the LIBOR rate
plus 5.00%.
|
|
·
|
Letter
of credit fees will range from 2.50% to 5.00% based on DG Marine’s
leverage ratio as computed under the credit facility. The rate
can fluctuate quarterly. At December 31, 2008, there were no
letters of credit outstanding under the DG Marine credit
facility.
|
|
·
|
DG
Marine pays a commitment fee on the unused portion of the $90 million
facility amount. The commitment fee will range from 0.25% to
0.50% based on its leverage ratio as computed under the credit
facility. The rate will fluctuate quarterly based on the
leverage ratio. At December 31, 2008, the commitment fee rate
was 0.50%.
|
In August
2008, DG Marine entered into a series of interest rate swap agreements to
effectively fix the underlying LIBOR rate on $32.9 million of its borrowings
under its credit facility through July 18, 2011. The fixed interest rates in the
swap agreements range from the three-month interest rate of 3.20% in effect at
December 31, 2008 to 4.68% at July 18, 2011.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
DG
Marine’s credit facility contains customary covenants (affirmative, negative and
financial) that limit the manner in which it may conduct its
business. DG Marine’s credit facility contains three primary
financial covenants – an interest coverage ratio, leverage ratio and asset
coverage ratio – that require DG Marine to achieve specific minimum financial
metrics. In general, the interest coverage ratio calculation compares
EBITDA (as defined and adjusted in accordance with the credit facility) to
interest expense. The leverage ratio calculation compares DG Marine’s
funded debt (as calculated in accordance with the credit facility) to EBITDA (as
adjusted). The asset coverage ratio compares an estimated liquidation
value of DG Marine’s boats and barges to DG Marine’s outstanding
debt.
Maturities
of long-term debt in the next five years, including the DG Marine credit
facility, are $375.3 million in 2011. We have estimated the fair
value of our long-term debt to be approximately $358.4 million, or $16.9 million
less than the carrying value of that debt based on consideration of our credit
standing.
11. Partners’
Capital and Distributions
Partner’s
capital at December 31, 2008 consists of 39,456,774 common units, including
4,028,096 units owned by our general partner and its affiliates, representing a
98% aggregate ownership interest in the Partnership and its subsidiaries (after
giving affect to the general partner interest), and a 2% general partner
interest.
Our
general partner owns all of our general partner interest, including incentive
distribution rights (IDRs), all of the 0.01% general partner interest in Genesis
Crude Oil, L.P. (which is reflected as a minority interest in the Consolidated
Balance Sheet at December 31, 2008) and operates our business.
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.
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
and to our general partner. Available cash consists generally of all
of our cash receipts less cash disbursements adjusted for net changes to
reserves. As discussed in Note 10, our credit facility limits the
amount of distributions we may pay in any quarter. At December 31,
2008, our restricted net assets (as defined in Rule 4-03(e)(3) of Regulations
S-X) were $573.6 million.
Pursuant
to our partnership agreement, our general partner receives incremental incentive
cash distributions when unitholders’ cash distributions exceed certain target
thresholds, in addition to its 2% general partner interest. The
allocations of distributions between our common unitholders and our general
partner, including the incentive distribution rights is as follows:
|
|
|
|
|
General
|
|
|
|
Unitholders
|
|
|
Partner
|
|
Quarterly
Cash Distribution per Common Unit:
|
|
|
|
|
|
|
Up
to and including $0.25 per Unit
|
|
|
98.00
|
%
|
|
|
2.00
|
%
|
First
Target - $0.251 per Unit up to and including $0.28 per
Unit
|
|
|
84.74
|
%
|
|
|
15.26
|
%
|
Second
Target - $0.281 per Unit up to and including $0.33 per
Unit
|
|
|
74.26
|
%
|
|
|
25.47
|
%
|
Over
Second Target - Cash distributions greater than $.033 per
Unit
|
|
|
49.02
|
%
|
|
|
50.98
|
%
|
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
We paid
distributions in 2007 and 2008 as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
General
|
|
|
|
|
|
|
|
|
|
|
|
Limited
|
|
|
General
|
|
|
Partner
|
|
|
|
|
|
|
|
|
|
|
|
Partner
|
|
|
Partner
|
|
|
Incentive
|
|
|
|
|
|
|
|
|
Per
Unit
|
|
|
Interests
|
|
|
Interest
|
|
|
Distribution
|
|
|
Total
|
|
Distribution For
|
|
Date Paid
|
|
Amount
|
|
|
Amount
|
|
|
Amount
|
|
|
Amount
|
|
|
Amount
|
|
|
|
|
|
|
|
|
|
|
Fourth
quarter 2006
|
|
February
2007
|
|
$
|
0.2100
|
|
|
$
|
2,895
|
|
|
$
|
59
|
|
|
$
|
-
|
|
|
$
|
2,954
|
|
First
quarter 2007
|
|
May
2007
|
|
$
|
0.2200
|
|
|
$
|
3,032
|
|
|
$
|
62
|
|
|
$
|
-
|
|
|
$
|
3,094
|
|
Second
quarter 2007
|
|
August
2007
|
|
$
|
0.2300
|
|
|
$
|
3,170
|
(1)
|
|
$
|
65
|
|
|
$
|
-
|
|
|
$
|
3,235
|
(1)
|
Third
quarter 2007
|
|
November
2007
|
|
$
|
0.2700
|
|
|
$
|
7,646
|
|
|
$
|
156
|
|
|
$
|
90
|
|
|
$
|
7,892
|
|
Fourth
quarter 2007
|
|
February
2008
|
|
$
|
0.2850
|
|
|
$
|
10,902
|
|
|
$
|
222
|
|
|
$
|
245
|
|
|
$
|
11,369
|
|
First
quarter 2008
|
|
May
2008
|
|
$
|
0.3000
|
|
|
$
|
11,476
|
|
|
$
|
234
|
|
|
$
|
429
|
|
|
$
|
12,139
|
|
Second
quarter 2008
|
|
August
2008
|
|
$
|
0.3150
|
|
|
$
|
12,427
|
|
|
$
|
254
|
|
|
$
|
633
|
|
|
$
|
13,314
|
|
Third
quarter 2008
|
|
November
2008
|
|
$
|
0.3225
|
|
|
$
|
12,723
|
|
|
$
|
260
|
|
|
$
|
728
|
|
|
$
|
13,711
|
|
Fourth
quarter 2008
|
|
February
2009
|
|
$
|
0.3300
|
|
|
$
|
13,021
|
|
|
$
|
266
|
|
|
$
|
823
|
|
|
$
|
14,110
|
|
(1) The
distribution paid on August 14, 2007 to holders of our common units is net of
the amounts payable with respect to the common units issued in connection with
the Davison transaction. The Davison unitholders and our general
partner waived their rights to receive such distributions, instead receiving
purchase price adjustments with us.
Net
Income (Loss) per Common Unit
The
following table sets forth the computation of basic net income per common
unit.
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Numerators
for basic and diluted net income (loss)per common unit:
|
|
|
|
|
|
|
|
|
|
Income
(loss) before cumulative effect adjustment
|
|
$
|
26,089
|
|
|
$
|
(13,550
|
)
|
|
$
|
8,351
|
|
Less:
General partner's incentive distribution paid
|
|
|
(2,035
|
)
|
|
|
-
|
|
|
|
-
|
|
Subtotal
|
|
|
24,054
|
|
|
|
(13,550
|
)
|
|
|
8,351
|
|
Less:
General partner 2% ownership
|
|
|
(481
|
)
|
|
|
271
|
|
|
|
(167
|
)
|
Income
(loss) before cumulative effect adjustment available for common
unitholders
|
|
$
|
23,573
|
|
|
$
|
(13,279
|
)
|
|
$
|
8,184
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from cumulative effect adjustment
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
30
|
|
Less:
General partner 2% ownership
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Income
from cumulative effect adjustment available for common
unitholders
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator
for basic per common unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Units
|
|
|
38,961
|
|
|
|
20,754
|
|
|
|
13,784
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator
for diluted per common unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Units
|
|
|
38,961
|
|
|
|
20,754
|
|
|
|
13,784
|
|
Phantom
Units
|
|
|
64
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
39,025
|
|
|
|
20,754
|
|
|
|
13,784
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
net income per common unit
|
|
$
|
0.61
|
|
|
$
|
(0.64
|
)
|
|
$
|
0.59
|
|
Diluted
net income per common unit
|
|
$
|
0.60
|
|
|
$
|
(0.64
|
)
|
|
$
|
0.59
|
|
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
Equity
Issuances and Contributions
During
the last three years we have issued a total of 15,495,940 common units in the
acquisition of assets. A summary of these unit issuances is as
follows:
|
|
|
|
|
|
|
Value
|
|
|
|
Acquisition
|
|
|
|
|
Attributed
|
|
Period
|
|
Transaction
|
|
Units
|
|
|
to Assets
|
|
July
2008
|
|
Grifco
|
|
|
838
|
|
|
$
|
16,667
|
|
May
2008
|
|
Free
State Pipeline
|
|
|
1,199
|
|
|
$
|
25,000
|
|
July
2007
|
|
Davison
|
|
|
13,459
|
|
|
$
|
330,000
|
|
We issued
new common units to the public and our general partner for cash as
follows:
|
|
Purchaser
of
|
|
|
|
|
Gross
|
|
|
Issuance
|
|
|
GP
|
|
|
|
|
|
Net
|
|
Period
|
|
Common Units
|
|
Units
|
|
|
Unit Price
|
|
|
Value
|
|
|
Contributions
|
|
|
Costs
|
|
|
Proceeds
|
|
December
2007
|
|
Public
|
|
|
9,200
|
|
|
$
|
22.000
|
|
|
$
|
202,400
|
|
|
$
|
-
|
|
|
$
|
8,846
|
|
|
$
|
193,554
|
|
December
2007
|
|
General
Partner
|
|
|
735
|
|
|
$
|
21.120
|
|
|
$
|
15,518
|
|
|
$
|
4,447
|
|
|
$
|
-
|
|
|
$
|
19,965
|
|
July
2007
|
|
General
Partner
|
|
|
1,075
|
|
|
$
|
20.836
|
|
|
$
|
22,361
|
|
|
$
|
6,171
|
|
|
$
|
-
|
|
|
$
|
28,532
|
|
On July
18, 2008, we issued 837,690 of our common units to Grifco. The units
were issued at a value of $19.896 per unit, for a total value of $16.7 million,
as a portion of the consideration for the acquisition of the inland marine
transportation business of Grifco.
Additionally,
on July 18, 2008, we redeemed 837,690 of our common units owned by members of
the Davison family. Those units had been issued as a portion of the
consideration for the acquisition of the energy-related business of the Davison
family in July 2007. The redemption was at a value of $19.896 per
unit, for a total value of $16.7 million. After giving effect to the
issuance and redemption described above, we did not experience a change in the
number of common units outstanding
On May
30, 2008, we issued 1,199,041 common units to Denbury in connection with the
acquisition of the Free State pipeline. Our general partner also
contributed $0.5 million to maintain its capital account balance.
On
December 10, 2007 we issued 9,200,000 common units is a public offering,
providing cash of $193.6 million after underwriters discount and offering
costs. Our general partner exercised its right to maintain its
proportionate share of our outstanding units and purchased 734,732 common units
from us for $15.5 million, or $21.12 per common unit. Our general
partner also contributed approximately $4.4 million to maintain its capital
account balance.
In July
2007, we issued 13,459,209 common units to the entities owned and controlled by
the Davison family as a portion of the purchase price. Additionally
at that time, our general partner exercised its right to maintain its
proportionate share of our outstanding common units by purchasing 1,074,882
common units from us for $22.4 million cash, or $20.8036 per common
unit. As required under our partnership agreement, our general
partner also contributed approximately $6.2 million to maintain its capital
account balance.
Our
general partner made a capital contribution of $1.4 million in December 2007 to
offset a portion of the severance payment to a former executive. We
also recorded a non-cash capital contribution of $3.4 million from our general
partner for the estimated value of the compensation earned in 2007 under the
proposed arrangements with our senior management team related to an incentive
interest in our general partner. As the purpose of incentive
interest is to incentivize these individuals to grow the partnership, the
expense is recognized as compensation by us and a capital contribution by the
general partner.
12. Business
Segment Information
Our
operations consist of four operating segments: (1) Pipeline
Transportation – interstate and intrastate crude oil, and to a lesser extent,
natural gas and CO
2
pipeline
transportation; (2) Refinery Services – processing high sulfur (or “sour”) gas
streams as part of refining operations to remove the sulfur and sale of the
related by-product; (3) Industrial Gases – the sale of CO
2
acquired
under volumetric production payments to industrial customers and our investment
in a syngas processing facility, and (4) Supply and Logistics – terminaling,
blending, storing, marketing, gathering and transporting by truck and barge
crude oil and petroleum products. All of our revenues are derived from, and all
of our assets are located in the United States.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
During
the fourth quarter of 2008, we revised the manner in which we internally
evaluate our segment performance. As a result, we changed our
definition of segment margin to include within segment margin all costs that are
directly associated with the business segment. Segment margin now
includes costs such as general and administrative expenses that are directly
incurred by the business segment. Segment margin also includes all
payments received under direct financing leases. In order to improve
comparability between periods, we exclude from segment margin the non-cash
effects of our stock-based compensation plans which are impacted by changes in
the market price for our common units. Previous periods have been
restated to conform to this segment presentation. We now define
segment margin as revenues less cost of sales, operating expenses (excluding
depreciation and amortization), and segment general and administrative expenses,
plus our equity in distributable cash generated by our joint
ventures. Our segment margin definition also excludes the non-cash
effects of our stock-based compensation plans, 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 maintenance capital investment.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
Pipeline
|
|
|
Refinery
|
|
|
Industrial
|
|
|
Supply
&
|
|
|
|
|
|
|
Transportation
|
|
|
Services
|
|
|
Gases
(a)
|
|
|
Logistics
|
|
|
Total
|
|
Year Ended December 31,
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
margin excluding depreciation and amortization
(b)
|
|
$
|
33,149
|
|
|
$
|
55,784
|
|
|
$
|
13,504
|
|
|
$
|
32,448
|
|
|
$
|
134,885
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures
(c)
|
|
$
|
262,200
|
|
|
$
|
5,490
|
|
|
$
|
2,397
|
|
|
$
|
118,585
|
|
|
$
|
388,672
|
|
Maintenance
capital expenditures
|
|
$
|
719
|
|
|
$
|
1,881
|
|
|
$
|
-
|
|
|
$
|
1,854
|
|
|
$
|
4,454
|
|
Net
fixed and other long-term assets
(d)
|
|
$
|
285,773
|
|
|
$
|
434,956
|
|
|
$
|
44,003
|
|
|
$
|
245,815
|
|
|
$
|
1,010,547
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
customers
|
|
$
|
39,051
|
|
|
$
|
233,871
|
|
|
$
|
17,649
|
|
|
$
|
1,851,113
|
|
|
$
|
2,141,684
|
|
Intersegment
(e)
|
|
|
7,196
|
|
|
|
(8,497
|
)
|
|
|
-
|
|
|
|
1,301
|
|
|
|
-
|
|
Total
revenues of reportable segments
|
|
$
|
46,247
|
|
|
$
|
225,374
|
|
|
$
|
17,649
|
|
|
$
|
1,852,414
|
|
|
$
|
2,141,684
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
margin excluding depreciation and amortization
(b)
|
|
$
|
14,170
|
|
|
$
|
19,713
|
|
|
$
|
13,038
|
|
|
$
|
10,646
|
|
|
$
|
57,567
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures
(c)
|
|
$
|
6,592
|
|
|
$
|
503,765
|
|
|
$
|
1,104
|
|
|
$
|
138,403
|
|
|
$
|
649,864
|
|
Maintenance
capital expenditures
|
|
$
|
2,880
|
|
|
$
|
469
|
|
|
$
|
-
|
|
|
$
|
491
|
|
|
$
|
3,840
|
|
Net
fixed and other long-term assets
(d)
|
|
$
|
32,936
|
|
|
$
|
468,068
|
|
|
$
|
47,364
|
|
|
$
|
145,915
|
|
|
$
|
694,283
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
customers
|
|
$
|
23,226
|
|
|
$
|
62,095
|
|
|
$
|
16,158
|
|
|
$
|
1,098,174
|
|
|
$
|
1,199,653
|
|
Intersegment
(e)
|
|
|
3,985
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(3,985
|
)
|
|
|
-
|
|
Total
revenues of reportable segments
|
|
$
|
27,211
|
|
|
$
|
62,095
|
|
|
$
|
16,158
|
|
|
$
|
1,094,189
|
|
|
$
|
1,199,653
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
margin excluding depreciation and amortization
(b)
|
|
$
|
13,280
|
|
|
$
|
-
|
|
|
$
|
12,844
|
|
|
$
|
5,017
|
|
|
$
|
31,141
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures
(c)
|
|
$
|
971
|
|
|
$
|
-
|
|
|
$
|
6,058
|
|
|
$
|
356
|
|
|
$
|
7,385
|
|
Maintenance
capital expenditures
|
|
$
|
611
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
356
|
|
|
$
|
967
|
|
Net
fixed and other long-term assets
(d)
|
|
$
|
31,863
|
|
|
$
|
-
|
|
|
$
|
51,630
|
|
|
$
|
7,602
|
|
|
$
|
91,095
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
customers
|
|
$
|
25,479
|
|
|
$
|
-
|
|
|
$
|
15,154
|
|
|
$
|
877,736
|
|
|
$
|
918,369
|
|
Intersegment
(e)
|
|
|
4,468
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(4,468
|
)
|
|
|
-
|
|
Total
revenues of reportable segments
|
|
$
|
29,947
|
|
|
$
|
-
|
|
|
$
|
15,154
|
|
|
$
|
873,268
|
|
|
$
|
918,369
|
|
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
|
(a)
|
The
industrial gases segment includes our CO
2
marketing operations and the income from our investments in T&P Syngas
and Sandhill.
|
|
(b)
|
A
reconciliation of segment margin to income before income taxes and
minority interest for each year presented is as
follows:
|
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Segment
margin excluding depreciation and amortization
|
|
$
|
134,885
|
|
|
$
|
57,567
|
|
|
$
|
31,141
|
|
Corporate
general and administrative expenses
|
|
|
(22,113
|
)
|
|
|
(17,573
|
)
|
|
|
(10,238
|
)
|
Depreciation
and amortization
|
|
|
(71,370
|
)
|
|
|
(40,245
|
)
|
|
|
(7,963
|
)
|
Net
(loss) gain on disposal of surplus assets
|
|
|
(29
|
)
|
|
|
(266
|
)
|
|
|
16
|
|
Interest
expense, net
|
|
|
(12,937
|
)
|
|
|
(10,100
|
)
|
|
|
(1,374
|
)
|
Non-cash
expenses not included in segment margin
|
|
|
1,206
|
|
|
|
(1,855
|
)
|
|
|
(1,343
|
)
|
Other
non-cash items affecting segment margin
|
|
|
(4,179
|
)
|
|
|
(1,733
|
)
|
|
|
(1,898
|
)
|
Income
(loss) before income taxes and minority interest
|
|
$
|
25,463
|
|
|
$
|
(14,205
|
)
|
|
$
|
8,341
|
|
|
(c)
|
Capital
expenditures includes fixed asset additions and acquisitions of
businesses.
|
|
(d)
|
Net
fixed and other long-term assets is a measure used by management in
evaluating the results of our operations on a segment
basis. Current assets are not allocated to segments as the
amounts are not meaningful in evaluating the success of the segment’s
operations. Amounts for our Industrial Gases segment include
investments in equity investees totaling $14.5 million, $16.2 million and
$17.2 million at December 31, 2008, 2007 and 2006,
respectively.
|
|
(e)
|
Intersegment
sales were conducted on an arm’s length
basis.
|
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.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
|
|
|
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
Truck
transportation services provided to Denbury
|
|
$
|
3,578
|
|
|
$
|
1,791
|
|
|
$
|
825
|
|
Pipeline
transportation services provided to Denbury
|
|
$
|
10,727
|
|
|
$
|
5,290
|
|
|
$
|
4,228
|
|
Payments
received under direct financing leases from Denbury
|
|
$
|
11,519
|
|
|
$
|
1,188
|
|
|
$
|
1,186
|
|
Pipeline
transportation income portion of direct financing lease
fees
|
|
$
|
11,011
|
|
|
$
|
641
|
|
|
$
|
655
|
|
Pipeline
monitoring services provided to Denbury
|
|
$
|
120
|
|
|
$
|
120
|
|
|
$
|
65
|
|
Directors'
fees paid to Denbury
|
|
$
|
195
|
|
|
$
|
150
|
|
|
$
|
120
|
|
CO2
transportation services provided by Denbury
|
|
$
|
6,424
|
|
|
$
|
5,213
|
|
|
$
|
4,640
|
|
Crude
oil purchases from Denbury
|
|
$
|
-
|
|
|
$
|
101
|
|
|
$
|
1,565
|
|
Operations,
general and administrative services provided by our general
partner
|
|
$
|
51,872
|
|
|
$
|
22,490
|
|
|
$
|
16,777
|
|
Distributions
to our general partner on its limited partner units and general partner
interest, including incentive distributions
|
|
$
|
6,463
|
|
|
$
|
1,671
|
|
|
$
|
963
|
|
Sales
of CO2 to Sandhill (for the period since Sandhill became a related
party)
|
|
$
|
2,941
|
|
|
$
|
2,783
|
|
|
$
|
2,056
|
|
Petroleum
products sales to Davison family businesses
|
|
$
|
1,261
|
|
|
$
|
-
|
|
|
$
|
-
|
|
Transition
services costs to Davison family
|
|
$
|
-
|
|
|
$
|
9,880
|
|
|
$
|
-
|
|
Transportation
Services
We
provide truck transportation services to Denbury to move their crude oil from
the wellhead to our Mississippi pipeline. Denbury pays us a fee for
this trucking service that varies with the distance the crude oil is
trucked. These fees are reflected in the statement of operations as
supply and logistics revenues.
Denbury
is the only shipper on our Mississippi pipeline other than us, and we earn
tariffs for transporting their oil. We earned fees from Denbury for
the transportation of their CO
2
on our
Free State pipeline. We also earned fees from Denbury under the
direct financing lease arrangements for the Olive and Brookhaven crude oil
pipelines and the Brookhaven and NEJD CO
2
pipelines
and recorded pipeline transportation income from these
arrangements.
We also
provide pipeline monitoring services to Denbury. This revenue is
included in pipeline revenues in the statements of operations.
Directors’
Fees
We paid
Denbury for the services of each of four of Denbury’s officers who serve as
directors of our general partner, at an annual rate and for attendance at
meetings that are the same as the rates at which our independent directors were
paid.
CO
2
Operations
and Transportation
Denbury
charges us a transportation fee of $0.16 per Mcf (adjusted for inflation) to
deliver CO
2
for us to
our customers. In 2008, the inflation-adjusted transportation
fee averaged $0.1927 per Mcf.
Operations,
General and Administrative Services
We do not
directly employ any persons to manage or operate our business. Those
functions are provided by our general partner. We reimburse the
general partner for all direct and indirect costs of these services, excluding
any payments to our management team pursuant to their Class B Membership
Interests. See Note 15.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
Amounts
due to and from Related Parties
At
December 31, 2008 and 2007, we owed Denbury $1.0 million, respectively, for
CO
2
transportation charges. Denbury owed us $2.0 million and $0.9 million
for transportation services at December 31, 2008 and 2007,
respectively. We owed our general partner $2.1 million and $0.7
million for administrative services at December 31, 2008 and 2007,
respectively. At December 31, 2008 and 2007, Sandhill owed us $0.7
and $0.5 million for purchases of CO
2
,
respectively. At December 31, 2007, we owed the Davison family
entities $0.8 million for reimbursement of costs paid primarily related to
employee transition services.
Drop-down
transactions
On May
30, 2008, we entered into a $175 million financing lease arrangement with
Denbury Onshore for its NEJD Pipeline System, and acquired its Free State
CO
2
pipeline system for $75 million, consisting of $50 million cash and $25 million
of our common units. See Note 3.
Unit
redemption
As
discussed in Note 11, we redeemed 837,690 of our common units owned by members
of the Davison family. The total value of the units redeemed was
$16.7 million.
DG
Marine joint venture
Our
partner in the DG Marine joint venture is TD Marine, LLC, a joint venture
consisting of three members of the Davison family. See Note
3.
Financing
Our
credit facility is non-recourse to our general partner, except to the extent of
its pledge of its 0.01% general partner interest in Genesis Crude Oil,
L.P. Our general partner’s principal assets are its general and
limited partnership interests in us. Our credit agreement obligations
are not guaranteed by Denbury or any of its other
subsidiaries.
We
guarantee 50% of the obligation of Sandhill to a bank. At December
31, 2008, the total amount of Sandhill’s obligation to the bank was $3.0
million; therefore, our guarantee was for $1.5 million.
Approximately
14% of the outstanding common shares of Community Trust Bank are held by Davison
family members. Community Trust Bank is a 17% participant in the DG
Marine credit facility. James E. Davison, Jr., a member of our board
of directors, also serves on the board of the holding company that owns
Community Trust Bank.
As
discussed in Note 11, our general partner made capital contributions in order to
maintain its capital account totaling $0.5 million and $10.6 million in 2008 and
2007, respectively. Our general partner also purchased common units
totaling $37.9 million in 2007. In addition, our general partner made a capital
contribution of $1.4 million in December 2007 to offset a portion of the
severance payment to a former executive. In 2007, we recorded a
capital contribution from our general partner of $3.4 million related to
compensation recognized for our executive management team. See Note
15.
In
December 2008, our general partner established Class B Membership Interests in
our general partner to be used as long-term incentive compensation for our
senior executives. See Note 15.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
14. Supplemental
Cash Flow Information
The
following table provides information regarding the net changes in components of
operating assets and liabilities.
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Decrease
(increase) in:
|
|
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
$
|
61,126
|
|
|
$
|
(35,362
|
)
|
|
$
|
(6,472
|
)
|
Inventories
|
|
|
(5,557
|
)
|
|
|
(143
|
)
|
|
|
(4,664
|
)
|
Other
current assets
|
|
|
(2,419
|
)
|
|
|
(1,887
|
)
|
|
|
870
|
|
Increase
(decrease) in:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(58,224
|
)
|
|
|
34,523
|
|
|
|
1,359
|
|
Accrued
liabilities
|
|
|
3,812
|
|
|
|
6,149
|
|
|
|
34
|
|
Net
changes in components of operating assets and liabilities, net
of working capital acquired
|
|
$
|
(1,262
|
)
|
|
$
|
3,280
|
|
|
$
|
(8,873
|
)
|
Cash
received by us for interest during the years ended December 31, 2008, 2007 and
2006 was $0.1 million, $0.3 million and $0.2 million,
respectively. Payments of interest and commitment fees were $11.3
million, $8.4 million and $1.0 million, during the years ended December 31,
2008, 2007 and 2006, respectively.
Cash paid
for income taxes in during the years ended December 31, 2008 and 2007 was $2.4
million and $1.6 million, respectively.
At
December 31, 2008 and 2007, we had incurred liabilities for fixed asset
additions totaling $1.7 million and $0.9 million, respectively, that had not
been paid at the end of the year and, therefore, are not included in the caption
“Additions to property and equipment” on the Consolidated Statements of Cash
Flows. We had incurred liabilities for other assets totaling $0.3
million at December 31, 2007 that had not been paid at the end of the year and,
therefore, are not included in the caption “Other, net” under investing
activities on the Consolidated Statements of Cash Flows.
In May
2008, we issued common units with a value of $25 million as part of the
consideration for the acquisition of the Free State Pipeline from
Denbury. In July 2008, we issued common units with a value of $16.7
million as part of the consideration for the acquisition of the inland marine
transportation assets of Grifco. These common unit issuances are non-cash
transactions and the value of the assets acquired is not included in investing
activities and the issuance of the common units is not reflected under financing
activities in our Consolidated Statements of Cash
Flows. Additionally, we deferred payment of $12 million ($11.7
million discounted) of the consideration in the acquisition from Grifco to
December 2008 and 2009. This deferral of the payment of consideration
was a non-cash transaction and the value of the assets acquired is not included
in investing activities and the payments due in December 2009 is not reflected
under financing activities in our Consolidated Statements of Cash
Flows. The subsequent payment in December 2008 of one-half of the
consideration is included in financing cash flows.
In July
2007, we issued common units with a value of $330 million as part of the
consideration in the Davison acquisition. This common unit issuance
is a non-cash transaction and the value of the assets acquired is not included
under investing activities and the issuance of the common units are not
reflected under financing activities in our Consolidated Statements of Cash
Flows.
In 2007,
our general partner made a non-cash contribution to us in the amount of $3.4
million that is not included in financing activities in the Consolidated
Statements of Cash Flows. This contribution related to the estimated
compensation earned by our management team for its services in 2007 under the
proposed compensation arrangement with these individuals that existed at
December 31, 2007.
15. Employee
Benefit Plans and Equity-Based Compensation Plans
We do not
directly employ any of the persons responsible for managing or operating our
activities. Employees of our general partner provide those services
and are covered by various retirement and other benefit plans.
In order
to encourage long-term savings and to provide additional funds for retirement to
its employees, our general partner sponsors a profit-sharing and retirement
savings plan. Under this plan, our general partner’s matching
contribution is calculated as an equal match of the first 3% of each employee’s
annual pretax contribution and 50% of the next 3% of each employee’s annual
pretax contribution. Our general partner also made a profit-sharing
contribution of 3% 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 $2.2 million, $0.8
million, and $0.7 million for the years ended December 31, 2008, 2007 and 2006,
respectively.
Our
general partner also provided certain health care and survivor benefits for its
active employees. Our health care benefit programs are self-insured,
with a catastrophic insurance policy to limit our costs. Our general
partner plans to continue self-insuring these plans in the
future. The expenses included in the consolidated statements of
operations for these benefits were $1.7 million, $1.5 million, and $1.3 million
in 2008, 2007 and 2006, respectively. Effective January 1, 2008, the
employees who operate the assets we acquired from the Davison family became
participants in these plans.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
Stock
Appreciation Rights Plan
Under the
terms of our stock appreciation rights plan, regular, full-time active employees
(with the exception of our chief executive officer, chief operating officer and
chief financial officer) and the members of the Board are eligible to
participate in the plan. The plan is administered by the Compensation
Committee of the Board, who shall determine, 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 his 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 his rights and receive a cash payment
calculated as the difference between the averages 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. The cash payment to the
participant will be net of any applicable withholding taxes required by
law. If the 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 plan, then the 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 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 SFAS
No. 123 (revised December 2004), “Share-Based Payments.”, 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.
We have
elected to calculate the fair value of the rights under the plan using the
Black-Scholes valuation model. This model requires that we include
the expected volatility of the market price for our common units, the current
price of our common units, the exercise price of the rights, the expected life
of the rights, the current risk free interest rate, and our expected annual
distribution yield. This valuation is then applied to the vested
rights outstanding and to the non-vested rights based on the percentage of the
service period that has elapsed. The valuation is adjusted for
expected forfeitures of rights (due to terminations before vesting, or
expirations after vesting). The liability amount accrued on the
balance sheet is adjusted to this amount at each balance sheet date with the
adjustment reflected in the statement of operations.
The
estimates that we make each period to determine the fair value of these rights
include the following assumptions:
Assumptions Used for Fair Value of
Rights
|
|
|
|
December
31, 2008
|
|
|
December
31, 2007
|
|
|
December
31, 2006
|
|
Expected
life of rights (in years)
|
|
|
1.25
- 6.00
|
|
|
|
2.25
- 6.25
|
|
|
|
3.25
- 7.00
|
|
Risk-free
interest rate
|
|
|
0.57%
- 1.71
|
%
|
|
|
3.12%
- 3.65
|
%
|
|
|
4.53%
- 4.57
|
%
|
Expected
unit price volatility
|
|
|
42.8
|
%
|
|
|
34.2
|
%
|
|
|
32.1
|
%
|
Expected
future distribution yield
|
|
|
6.00
|
%
|
|
|
6.00
|
%
|
|
|
6.00
|
%
|
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
|
·
|
In
determining the expected life of the rights, we use the simplified method
allowed by the Securities and Exchange Commission. As our stock
appreciation rights plan was not put in place until December 31, 2003, we
have very limited experience with employee exercise
patterns.
|
|
·
|
The
expected volatility of our units is computed using the historical period
we believe is representative of future expectations. We
determined the period to use as the historical period by considering our
distribution history and distribution
yield.
|
|
·
|
The
risk-free interest rate was determined from the current yield for U.S.
Treasury zero-coupon bonds with a term similar to the remaining expected
life of the rights.
|
|
·
|
In
determining our expected future distribution yield, we considered our
history of distribution payments, our expectations for future payments,
and the distribution yields of entities similar to us. While
current market conditions result in a higher distribution yield, we
believe that the yield will be closer to 6% over the life of the
outstanding rights.
|
|
·
|
We
estimated the expected forfeitures of non-vested rights and expirations of
vested rights. We have very limited experience with employee
forfeiture and expiration patterns, as our plan was not initiated until
December 31, 2003. We reviewed the history available to us as well as
employee turnover patterns in determining the rates to use. We
also used different estimates for different groups of
employees.
|
The
following table reflects rights activity under our plan as of January 1, 2008,
and changes during the year ended December 31, 2008:
Stock
Appreciation Rights
|
|
Rights
|
|
|
Weighted
Average Exercise Price
|
|
|
Weighted
Average Contractual Remaining Term (Yrs)
|
|
|
Aggregate
Intrinsic Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding
at January 1, 2008
|
|
|
593,458
|
|
|
$
|
15.45
|
|
|
|
|
|
|
|
Granted
during 2008
|
|
|
536,308
|
|
|
$
|
20.83
|
|
|
|
|
|
|
|
Exercised
during 2008
|
|
|
(38,995
|
)
|
|
$
|
19.52
|
|
|
|
|
|
|
|
Forfeited
or expired during 2008
|
|
|
(72,786
|
)
|
|
$
|
21.23
|
|
|
|
|
|
|
|
Outstanding
at December 31, 2008
|
|
|
1,017,985
|
|
|
$
|
18.09
|
|
|
|
7.9
|
|
|
$
|
-
|
|
Exercisable
at December 31, 2008
|
|
|
381,016
|
|
|
$
|
14.82
|
|
|
|
6.2
|
|
|
$
|
-
|
|
The
weighted-average fair value at December 31, 2008 of rights granted during 2008
was $0.67 per right, determined using the following assumptions:
Assumptions
Used for Fair Value of Rights
|
|
Granted
in 2008
|
|
Expected
life of rights (in years)
|
|
|
5.25
- 6.00
|
|
Risk-free
interest rate
|
|
|
1.57% -
1.71
|
%
|
Expected
unit price volatility
|
|
|
42.8
|
%
|
Expected
future distribution yield
|
|
|
6.00
|
%
|
The total
intrinsic value of rights exercised during 2008, 2007 and 2006 was $0.4 million,
$1.6 million and $0.4 million, respectively, which was paid in cash to the
participants.
At
December 31, 2008, there was $0.2 million of total unrecognized compensation
cost related to rights that we expect will vest under the plan. This
amount was calculated as the fair value at December 31, 2008 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, 2008, the
remaining cost will be recognized over a weighted average period of
approximately one year.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
We
recorded charges and credits related to our stock appreciation rights for three
years ended December 31, 2008 as follows:
Expense (Credits to Expense) Related to Stock
Appreciation Rights
|
|
|
|
|
|
|
|
|
|
|
|
Statement
of Operations
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Supply
and logistics operating costs
|
|
$
|
(997
|
)
|
|
$
|
528
|
|
|
$
|
362
|
|
Refinery
services operating costs
|
|
|
23
|
|
|
|
-
|
|
|
|
-
|
|
Pipeline
operating costs
|
|
|
(296
|
)
|
|
|
420
|
|
|
|
289
|
|
General
and administrative expenses
|
|
|
(1,141
|
)
|
|
|
1,576
|
|
|
|
1,279
|
|
Total
|
|
$
|
(2,411
|
)
|
|
$
|
2,524
|
|
|
$
|
1,930
|
|
2007
Long Term Incentive Plan
Our
Genesis Energy, Inc. 2007 Long Term Incentive Plan (the “2007 LTIP”) provides
for awards of Phantom Units and Distribution Equivalent Rights to non-employee
directors and employees of Genesis Energy, LLC, our general partner. Phantom
Units are notional units representing unfunded and unsecured promises to deliver
a Partnership common unit to the participant should specified vesting
requirements be met. Distribution Equivalent Rights are rights to receive an
amount of cash equal to all or a portion of the cash distributions made by the
Partnership during a specified period. The 2007 LTIP is administered by the
Compensation Committee of the board of directors of our general partner (the
“Board”).
The
Compensation Committee (at its discretion) will designate participants in the
2007 LTIP, determine the types of awards to grant to participants, determine the
number of units to be covered by any award, and determine the conditions and
terms of any award including vesting, settlement and forfeiture conditions. The
2007 LTIP may be amended or terminated at any time by the Board or the
Compensation Committee; however, any material amendment, such as a material
increase in the number of units available under the 2007 LTIP or a change in the
types of awards available under the 2007 LTIP, will also require the approval of
our unitholders. The Compensation Committee is also authorized to make
adjustments in the terms and conditions of and the criteria included in awards
under the plan in specified circumstances.
The
common units to be awarded under the 2007 Plan will be obtained by our general
partner through purchases made on the open market, from us, from any affiliates
of our general partner or from any other person; however, it is generally
intended that units are to be acquired from us as newly-issued common
units.
Subject
to adjustment as provided in the 2007 LTIP, awards with respect to up to an
aggregate of 1,000,000 units may be granted under the 2007 LTIP, of which
915,429 remain authorized for issuance at December 31,
2008. Compensation expense is recognized on a straight-line basis
over the vesting period. The fair value of the units is based on the
market price of the underlying common units on the date of grant and an
allowance for estimated forfeitures. Due to the positions of the
small group of employees and non-employee directors who received these grants,
we have assumed that there will be no forfeitures of these Phantom Units in our
fair value calculation as of December 31, 2008. The grant date fair
value of the awards are measured by reducing the grant date market price by the
present value of the distributions expected to be paid on the shares during the
requisite service period, discounted at an appropriate risk-free interest
rate.
The
aggregate grant date fair value of Phantom Unit awards granted during 2008 and
2007 was $0.8 million and $0.9 million, respectively. The total fair
value of Phantom Units that vested during the year ended December 31, 2008 was
$0.1 million. Compensation expense recognized during 2008 for Phantom
Units was $0.7 million. Expense recorded during 2007 was less than
$0.1 million. As of December 31, 2008, there was $0.9 million of
unrecognized compensation expense related to these units. This
unrecognized compensation cost is expected to be recognized over a
weighted-average period of one year.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
The
following table summarizes information regarding our non-vested Phantom Unit
grants as of December 31, 2008:
|
|
|
|
|
Weighted-Average
|
|
|
|
Number
of
|
|
|
Grant-Date
|
|
Non-vested
Phantom Unit Grants
|
|
Units
|
|
|
Fair
Value
|
|
|
|
|
|
|
|
|
Non-vested
at January 1, 2007
|
|
|
-
|
|
|
|
|
Granted
during 2007
|
|
|
39,362
|
|
|
$
|
21.92
|
|
Non-vested
at December 31, 2007
|
|
|
39,362
|
|
|
$
|
21.92
|
|
Granted
during 2008
|
|
|
45,209
|
|
|
$
|
17.63
|
|
Vested
during 2008
|
|
|
(6,183
|
)
|
|
$
|
23.46
|
|
Non-vested
at December 31, 2008
|
|
|
78,388
|
|
|
$
|
19.32
|
|
The
weighted-average fair value of Phantom Units granted during 2007 and 2008 was
determined using the following assumptions:
|
|
|
|
|
Expected
|
|
|
|
|
Year
|
|
Grant
Date
|
|
|
Distribution
|
|
|
Risk
Free
|
|
Granted
|
|
Price
|
|
|
Rate
|
|
|
Rate
|
|
2007
|
|
$
|
24.52
|
|
|
$
|
0.27
|
|
|
|
3.19%
- 3.31%
|
|
2008
|
|
$
|
15.50
- $21.30
|
|
|
$
|
0.285
- $0.315
|
|
|
|
2.01%
- 2.40%
|
|
Bonus
Program
In
January 2009, the Committee of the Board of our general partner approved a bonus
program (referred to below as the Bonus Plan) for all employees of our general
partner (with the exception of our Chief Executive Officer, Chief Operating
Officer and Chief Financial Officer (collectively our “Senior Executives”)) that
was applicable to 2008. The Bonus Plan is paid at the discretion of
our Board based on the recommendation of the Compensation Committee, and can be
amended or changed at any time. The Bonus Plan is designed to enhance
the financial performance of the Partnership by rewarding employees for
achieving financial performance and safety objectives. While the
maximum amount that will be paid each year as bonuses is calculated based on two
metrics, the actual amounts paid individually are discretionary and may total to
less than the maximum that might otherwise be available.
The Bonus
Plan is based primarily on the amount of money we generate for distributions to
our unitholders, and is measured on a calendar-year basis. For 2008,
two metrics were used to determine the bonus pool – the level of Available Cash
before Reserves (before subtracting bonus expense and related employer tax
burdens) that we generate and our company-wide safety record improvement. The
level of Available Cash before Reserves generated for the year as a percentage
of a target set by our Committee is weighted ninety percent and the achieved
level of the targeted improvement in our safety record is weighted ten
percent. The sum of the weighted percentage achievement of these
targets is multiplied by the eligible compensation and the target percentages
established by our Compensation Committee for the various levels of our
employees to determine the maximum bonus pool from which the majority of our
employees are paid bonuses.
A
separate marketing bonus pool is available for compensating certain marketing
personnel that is based on the contribution of that marketing group to Available
Cash before Reserves. A minimum level of contribution to Available
Cash before Reserves is required before any amounts are allocated to the
marketing bonus pool.
For 2008,
we accrued $4.0 million for the general bonus pool and $0.5 million for the
marketing bonus pool in 2008. These bonuses were paid to employees in
March 2009. In 2007 and 2006, we accrued $2.0 million and $1.8
million for bonuses under previous bonus arrangements.
Severance
Protection Plan
In June
2005, the Compensation Committee of the Board of Directors of our general
partner approved the Genesis Energy Severance Protection Plan, or Severance
Plan, for employees of our general partner (with the exception of the new senior
management team.) The Severance Plan provides that a participant in
the Plan is entitled to receive a severance benefit if his employment is
terminated during the period beginning six months prior to a change in control
and ending two years after a change in control, for any reason other than (x)
termination by our general partner for cause or (y) termination by the
participant for other than good reason. Termination by the
participant for other than good reason would be triggered by a change in job
status, a reduction in pay, or a requirement to relocate more than 25
miles.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
A change
in control is defined in the Severance Plan. Generally, a change in
control is a change in the control of Denbury, a disposition by Denbury of more
than 50% of our general partner, or a transaction involving the disposition of
substantially all of the assets of Genesis.
The
amount of severance is determined separately for three classes of
participants. The first class, which includes two Executive Officers
of Genesis, would receive a severance benefit equal to three times that
participant’s annual salary and bonus amounts. The second class,
which includes certain other members of management, would receive a severance
benefit equal to two times that participant’s salary and bonus
amounts. The third class of participant would receive a severance
benefit based on the participant’s salary and bonus amounts and length of
service. Participants would also receive certain medical and dental
benefits.
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. These Class B Membership
Interests compensate the holders thereof by providing rewards based on increased
shares of the cash distributions attributable to our incentive distribution
rights (or IDRs)(See Note 11) to the extent we increase Cash Available Before
Reserves, or CABR (defined below) (from which we pay distributions on our common
units) above specified targets. CABR generally means Available
Cash before Reserves, less Available Cash before Reserves generated from
specific transactions with our general partner and its affiliates (including
Denbury Resources Inc.) The Class B Membership Interests do not provide any
Senior Executive with a direct interest in any assets (including our IDRs) owned
by our general partner. During his employment with our general partner, each
Senior Executive will be entitled to receive quarterly distributions in respect
of his Class B Membership Interest from our general partner in amounts equal to
a percentage of the distributions we pay in respect of our IDRs. Each
Senior Executive’s quarterly distribution percentage of our IDRs may vary from
quarter-to-quarter based on a formula included in the agreements. In
addition, upon the occurrence of specified events and circumstances, our general
partner will redeem a Senior Executive’s Class B Membership Interest when that
executive’s employment with our general partner is terminated or when a change
of control occurs. Additionally our chief executive officer and chief
operating officer participate in a deferred compensation plan, whereby they may
be entitled to receive a cash payment upon termination of
employment.
Our
general partner has agreed that it will not seek reimbursement (on behalf of
itself or its affiliates) under our partnership agreement for the costs of these
Senior Executive compensation arrangements to the extent relating to their
ownership of Class B Membership Interests (including current cash distributions
made by the general partner out of its IDRs and payment of redemption amounts
for those IDRs) and the deferred compensation amounts.
Although
our general partner will not seek reimbursement for the costs of the Class B
Membership Interests and deferred compensation plan arrangements, we will record
non-cash expense. The Class B Membership Interests awarded to
our senior executives will be accounted for as liability awards under the
provisions of SFAS 123(R). As such, the fair value of the
compensation cost we record for these awards will be recomputed at each
measurement date and the expense to be recorded will be adjusted based on that
fair value. Management’s estimates of the fair value of these awards
are based on assumptions regarding a number of future events, including
estimates of the Available Cash before Reserves we will generate each quarter
through the final vesting date of December 31, 2012, estimates of the future
amount of incentive distributions we will pay to our general partner, and
assumptions about appropriate discount rates. Additionally the
determination of fair value will be affected by the distribution yield of ten
publicly-traded entities that are the general partners in publicly-traded master
limited partnerships, a factor over which we have no
control. Included within the assumptions used to prepare these
estimates are projections of available cash and distributions to our common
unitholders and general partner, including an assumed level of growth
and the effects of future new growth projects during the four-year
vesting period. These assumptions were used to estimate the total
amount that would be paid under the Class B Membership awards through the final
vesting date and are do not represent the contractual amounts payable under
these awards at the reporting date. The estimated total amount was discounted to
December 31, 2008 using a discount rate of 16%, representing the risks inherent
in the assumptions we used and the time until final vesting. Due to
the limited number of participants in the Class B Membership awards, we assumed
a forfeiture rate of zero. At December 31, 2008, management estimates
that the fair value of the Class B Membership Awards and the related deferred
compensation awards granted to our Senior Executives on that date is
approximately $12 million. The fair value of these incentive awards will be
recomputed each quarter beginning with the quarter ending March 31, 2009 through
the final settlement of the awards. Compensation expense of $3.4
million was recorded in the fourth quarter of 2007 related to the previous
arrangements between our general partner and our Senior
Executives. The fair value to be recorded by us as compensation
expense will be the excess of the recomputed estimated fair value over the
previously recorded $3.4 million. Due to the vesting conditions for
the awards, the amount to which the Senior Executives were entitled on December
31, 2008 for the Class B Membership Awards and the related deferred compensation
was zero. Management’s estimates of fair value are made in order to record
non-cash compensation expense over the vesting period, and do not necessarily
represent the contractual amounts payable under these awards at December 31,
2008. This expense will be recorded on an accelerated basis to align with the
requisite service period of the award. Changes in our assumptions
will change the amount of compensation cost we record.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
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 the daily cash settlement procedures and other NYMEX
requirements.
We have
established various procedures to manage our credit exposure, including initial
credit approvals, credit limits, collateral requirements and rights of
offset. Letters of credit, prepayments and guarantees are also
utilized to limit credit risk to ensure that our established credit criteria are
met.
Shell Oil
Company accounted for 14.6% of total revenues in 2008. Shell Oil
Company and Occidental Energy Marketing, Inc. accounted for 20.7% and 11.2% of
total revenues in 2007, respectively. Occidental Energy Marketing,
Inc., Shell Oil Company and Calumet Specialty Products Partners, L.P. accounted
for 20.3%, 19.1% and 10.9% of total revenues in 2006,
respectively. The revenues from these five customers in all three
years relate primarily to our supply and logistics operations.
17. Derivatives
Our
market risk in the purchase and sale of crude oil and petroleum products
contracts is the potential loss that can be caused by a change in the market
value of the asset or commitment. In order to hedge our exposure to
such market fluctuations, we may enter into various financial contracts,
including futures, options and swaps. Historically, any contracts we
have used to hedge market risk were less than one year in duration, although we
have the flexibility to enter into arrangements with a longer
term. The derivative instruments that we use consist primarily of
futures and options contracts traded on the NYMEX which we use to hedge our
exposure to commodity prices, primarily crude oil, fuel oil and petroleum
products.
Additionally,
DG Marine entered into a series of interest rate swap contracts with two
financial institutions related to $32.9 million of the outstanding debt under
the DG Marine credit facility. These swaps effectively convert this
portion of DG Marine’s debt from floating LIBOR rate to a series of fixed rates
through July 2011. We have determined that these swaps are effective
cash flow hedges of DG Marine’s interest rate exposure.
At
December 31, 2008 and 2007, we had no commodity price risk derivatives that were
designated as hedges for financial reporting purposes. Therefore, the
derivative contracts were marked to fair value based on the closing price for
the contracts at the end of each period and an asset or liability was recorded
for the fair value and the change in fair value was recorded in our consolidated
statements of operations.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
The
following table summarizes the liabilities on our consolidated balance sheet
that are related to the fair value of our open derivative
positions:
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
Decrease
in other current assets
|
|
$
|
(488
|
)
|
|
$
|
(744
|
)
|
Increase
in accrued liabilities
|
|
|
(698
|
)
|
|
|
-
|
|
Increase
in other long-term liabilities
|
|
|
(1,266
|
)
|
|
|
-
|
|
Total
liabilities
|
|
$
|
(2,452
|
)
|
|
$
|
(744
|
)
|
The
liabilities related to the fair value of our open positions consists of
unrealized gains/losses recognized in earnings and unrealized losses deferred to
other comprehensive income (“OCI”) as follows, by category (losses designated in
parentheses):
|
|
December
31, 2008
|
|
|
December
31, 2007
|
|
|
|
Total
|
|
|
|
|
|
Minority
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
Liabilities
|
|
|
Losses
|
|
|
Interests
|
|
|
OCI
|
|
|
Liabilities
|
|
|
Losses
|
|
Commodity
price risk derivatives
|
|
$
|
(488
|
)
|
|
$
|
(488
|
)
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
(744
|
)
|
|
$
|
(744
|
)
|
Interest
rate risk hedging by DG Marine
|
|
|
(1,964
|
)
|
|
|
-
|
|
|
|
(1,002
|
)
|
|
|
(962
|
)
|
|
|
-
|
|
|
|
-
|
|
Total
|
|
$
|
(2,452
|
)
|
|
$
|
(488
|
)
|
|
$
|
(1,002
|
)
|
|
$
|
(962
|
)
|
|
$
|
(744
|
)
|
|
$
|
(744
|
)
|
In each
year, the impact on earnings of our unrealized losses from commodity price risk
derivatives in the table above is included in the Consolidated Statements of
Operations under the caption “Supply and logistics costs.”
The net
loss recorded in AOCI and minority interests is expected to be reclassified to
future earnings contemporaneously as interest expense associated with the
underlying debt under the DG Marine credit facility is recorded. We
expect the total net loss to be reclassified into earnings during the period the
swaps are outstanding, with $0.7 million of net loss expected to be reclassified
in 2009 and a total of $1.3 million reclassified to earnings during 2011 and
2012. Because a portion of these amounts is based on market prices at
the current period end, actual amounts to be reclassified to earnings will
differ and could vary materially as a result of changes in market
conditions.
We
determined that the remainder of our derivative contracts qualified for the
normal purchase and sale exemption and were designated and documented as such at
December 31, 2008 and December 31, 2007.
18. Fair-Value
Measurements
As
discussed in Note 2, effective January 1, 2008 we partially adopted SFAS
157. As defined in SFAS 157, fair value as the price that would be
received from selling an asset, or paid to transfer a liability in an orderly
transaction between market participants at the measurement
date. Whenever possible, we use market data that market participants
would use when pricing an asset or liability. These inputs can be
either readily observable or market corroborated. We apply the market
approach for recurring fair value measurements related to our
derivatives. SFAS 157 establishes a three-level fair value hierarchy
that prioritizes the inputs used to measure fair value. The hierarchy
gives the highest priority to unadjusted quoted prices in active markets for
identical assets or liabilities (Level 1 measurement) and the lowest priority to
unobservable inputs (Level 3 measurement)
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, 2008. As required by SFAS 157,
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.
|
|
Fair Value at December 31,
2008
|
|
Recurring
Fair Value Measures
|
|
Level
1
|
|
|
Level
2
|
|
|
Level
3
|
|
Commodity
derivatives (based on quoted market prices on NYMEX)
|
|
$
|
(488
|
)
|
|
$
|
-
|
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
rate swaps
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
(1,964
|
)
|
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
Level
1
Included
in Level 1 of the fair value hierarchy are commodity derivative contracts are
exchange-traded futures and exchange-traded option 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.
Level
3
Included
within Level 3 of the fair value hierarchy are our interest rate
swaps. The fair value of our interest rate swaps is based on
indicative broker price quotations. These derivatives are included in Level 3 of
the fair value hierarchy because broker price quotations used to measure fair
value are indicative quotations rather than quotations whereby the broker or
dealer is ready and willing to transact. However, the fair value of
these Level 3 derivatives is not based upon significant management assumptions
or subjective inputs.
The
following table provides a reconciliation of changes in fair value of the
beginning and ending balances for our derivatives measured at fair value using
inputs classified as level 3 in the fair value hierarchy:
|
|
Year
Ended
|
|
|
|
December
31, 2008
|
|
Balance
as of January 1, 2008
|
|
$
|
-
|
|
Realized
and unrealized gains (losses)-
|
|
|
|
|
Included
in other comprehensive income
|
|
|
(962
|
)
|
Included
in minority interests
|
|
|
(1,002
|
)
|
Balance
as of December 31, 2008
|
|
$
|
(1,964
|
)
|
See Note
17 for additional information on our derivative instruments.
We
generally apply fair value techniques on a non-recurring basis associated with
(1) valuing the potential impairment loss related to goodwill pursuant to SFAS
142, and (2) valuing potential impairment loss related to long-lived assets
accounted for pursuant to SFAS 144.
19. Commitments
and Contingencies
Commitments
and Guarantees
In 2008,
we entered into a new office lease for our corporate headquarters that extends
until January 31, 2016. We lease office space for field offices under
leases that expire between 2008 and 2013. To transport products, we lease
tractors and trailers for our crude oil gathering and marketing activities and
lease barges and railcars for our refinery services segment. 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, 2008, were as follows (in thousands).
|
|
Office
|
|
|
Transportation
|
|
|
Terminals
and
|
|
|
|
|
|
|
Space
|
|
|
Equipment
|
|
|
Tanks
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
$
|
745
|
|
|
$
|
3,322
|
|
|
$
|
1,257
|
|
|
$
|
5,324
|
|
2010
|
|
|
813
|
|
|
|
3,071
|
|
|
|
322
|
|
|
|
4,206
|
|
2011
|
|
|
794
|
|
|
|
2,639
|
|
|
|
322
|
|
|
|
3,755
|
|
2012
|
|
|
762
|
|
|
|
1,552
|
|
|
|
322
|
|
|
|
2,636
|
|
2013
|
|
|
733
|
|
|
|
726
|
|
|
|
322
|
|
|
|
1,781
|
|
2014
and thereafter
|
|
|
1,534
|
|
|
|
2,583
|
|
|
|
6,950
|
|
|
|
11,067
|
|
Total
minimum lease obligations
|
|
$
|
5,381
|
|
|
$
|
13,893
|
|
|
$
|
9,495
|
|
|
$
|
28,769
|
|
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
Total
operating lease expense was as follows (in thousands).
Year
ended December 31, 2008
|
|
$
|
8,757
|
|
Year
ended December 31, 2007
|
|
$
|
6,079
|
|
Year
ended December 31, 2006
|
|
$
|
3,258
|
|
We have
guaranteed the payments by our operating partnership to the banks under the
terms of our credit facility related to borrowings and letters of
credit. To the extent liabilities exist under the letters of credit,
such liabilities are included in the consolidated balance
sheet. Borrowings at December 31, 2008 were $320.0 million and are
reflected in the consolidated balance sheet. We have also guaranteed
the payments by our operating partnership under the terms of our operating
leases of tractors and trailers. Such obligations are included in
future minimum rental payments in the table above.
We
guarantee $7.5 million of the outstanding debt of DG Marine under its credit
facility. This guarantee will expire on May 31, 2009, if DG Marine’s
leverage ratio under its credit facility is less than 4.00 to
1.00. The outstanding debt of DG Marine in included in our
Consolidated Balance Sheets. We believe the likelihood we would be
required to perform or otherwise incur any significant losses associated with
this guaranty is remote.
We
guaranteed $1.2 million of residual value related to the leases of
trailers. We believe the likelihood we would be required to perform
or otherwise incur any significant losses associated with this guaranty is
remote.
We
guaranty 50% of the obligations of Sandhill under a credit facility with a
bank. At December 31, 2008, Sandhill owed $3.0 million; therefore our
guarantee was $1.5 million. Sandhill makes principal payments for
this obligation totaling $0.6 million per year. We believe the
likelihood we would be required to perform or otherwise incur any significant
losses associated with this guaranty is remote.
In
general, we expect to incur expenditures in the future to comply with increasing
levels of regulatory safety standards. While the total amount of
increased expenditures cannot be accurately estimated at this time, we expect
that our annual expenditures for integrity testing, repairs and improvements
under regulations requiring assessment of the integrity of crude oil pipelines
to average from $1.0 million to $1.5 million.
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 adverse 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.
A portion
of the operations we acquired in the Davison transactions are owned by
wholly-owned corporate subsidiaries that are taxable as
corporations. We pay federal and state income taxes on these
operations. The income taxes associated with these operations are
accounted for in accordance with SFAS 109 “Accounting for Income
Taxes.”
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
In May
2006, the State of Texas enacted a law which will require us to pay a tax of
0.5% on our “margin,” as defined in the law, beginning in 2008 based on our 2007
results. The “margin” to which the tax rate is applied generally will
be calculated as our revenues (for federal income tax purposes) less the cost of
the products sold (for federal income tax purposes), in the State of
Texas.
In June
2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in
Income Taxes—an interpretation of FASB Statement No. 109” (FIN 48). This
Interpretation provides guidance on recognition, classification and disclosure
concerning uncertain tax liabilities. The evaluation of a tax position requires
recognition of a tax benefit if it is more likely than not it will be sustained
upon examination. We adopted FIN 48 effective January 1, 2007. The adoption did
not have any impact on our consolidated financial statements.
As of
December 31, 2007 we had unrecognized tax benefits of $1.0
million. At December 31, 2008 we have unrecognized tax benefits
of $2.6 million. The change in the unrecognized tax benefits are a
result of additions related to current year tax positions. If the
unrecognized tax benefits at December 31, 2008 were recognized, $2.6 million
would affect our effective income tax rate. There are no uncertain
tax positions as of December 31, 2008 for which it is reasonably possible that
the amount of unrecognized tax benefits would significantly decrease during
2009.
Our
income tax provision (benefit) is as follows:
|
|
Year
Ended
|
|
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
Current:
|
|
|
|
|
|
|
Federal
|
|
$
|
2,979
|
|
|
$
|
1,665
|
|
State
|
|
|
872
|
|
|
|
339
|
|
Total
current income tax expense
|
|
|
3,851
|
|
|
|
2,004
|
|
|
|
|
|
|
|
|
|
|
Deferred:
|
|
|
|
|
|
|
|
|
Federal
|
|
|
(3,850
|
)
|
|
|
(2,432
|
)
|
State
|
|
|
(363
|
)
|
|
|
(226
|
)
|
Total
deferred income tax benefit
|
|
|
(4,213
|
)
|
|
|
(2,658
|
)
|
Total
income tax benefit
|
|
$
|
(362
|
)
|
|
$
|
(654
|
)
|
Deferred
income taxes relate to temporary differences based on tax laws and statutory
rates in effect at the December 31, 2008 balance sheet date. We
believe we will utilize all of our deferred tax assets at December 31, 2008, and
therefore have provided no valuation allowance against our deferred tax
assets. As of December 31, 2008, we have federal income tax net
operating loss carryforwards of $4.1 million which, if not used, will begin to
expire in 2027. Deferred tax assets and liabilities consist of the
following:
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
Deferred
tax assets:
|
|
|
|
|
|
|
Current:
|
|
|
|
|
|
|
Other
current assets
|
|
$
|
271
|
|
|
$
|
43
|
|
Other
|
|
|
97
|
|
|
|
17
|
|
Total
current deferred tax asset
|
|
|
368
|
|
|
|
60
|
|
Net
operating loss carryforwards - federal
|
|
|
1,415
|
|
|
|
861
|
|
Net
operating loss carryforwards - state
|
|
|
128
|
|
|
|
80
|
|
Total
long-term deferred tax asset
|
|
|
1,543
|
|
|
|
941
|
|
Total
deferred tax assets
|
|
|
1,911
|
|
|
|
1,001
|
|
|
|
|
|
|
|
|
|
|
Deferred
tax liabilities:
|
|
|
|
|
|
|
|
|
Current:
|
|
|
|
|
|
|
|
|
Other
|
|
|
(2
|
)
|
|
|
(24
|
)
|
Long-term:
|
|
|
|
|
|
|
|
|
Fixed
assets
|
|
|
(9,868
|
)
|
|
|
(11,125
|
)
|
Intangible
assets
|
|
|
(6,938
|
)
|
|
|
(8,962
|
)
|
Total
long-term liability
|
|
|
(16,806
|
)
|
|
|
(20,087
|
)
|
Total
deferred tax liabilities
|
|
|
(16,808
|
)
|
|
|
(20,111
|
)
|
|
|
|
|
|
|
|
|
|
Total
net deferred tax liability
|
|
$
|
(14,897
|
)
|
|
$
|
(19,110
|
)
|
Our
income tax benefit varies from the amount that would result from applying the
federal statutory income tax rate to income before income taxes as
follows:
|
|
Year
Ended
|
|
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
Income
(loss) before income taxes
|
|
$
|
25,463
|
|
|
$
|
(14,205
|
)
|
Partnership
income (loss) not subject to tax
|
|
|
(30,902
|
)
|
|
|
8,894
|
|
Income
(loss) subject to income taxes
|
|
|
(5,439
|
)
|
|
|
(5,311
|
)
|
|
|
|
|
|
|
|
|
|
Tax
benefit at federal statutory rate
|
|
|
(1,904
|
)
|
|
$
|
(1,859
|
)
|
State
income taxes, net of federal benefit
|
|
|
357
|
|
|
|
33
|
|
Effects
of FIN 48, federal and state
|
|
|
1,431
|
|
|
|
1,168
|
|
Return
to provision, federal and state
|
|
|
(258
|
)
|
|
|
-
|
|
Other
|
|
|
12
|
|
|
|
4
|
|
Income
tax benefit
|
|
$
|
(362
|
)
|
|
$
|
(654
|
)
|
|
|
|
|
|
|
|
|
|
Effective
tax rate on income (loss) before income taxes
|
|
|
-1
|
%
|
|
|
5
|
%
|
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
21. Quarterly
Financial Data (Unaudited)
The table
below summarizes our unaudited quarterly financial data for 2008 and
2007.
|
|
2008
Quarters
|
|
|
Total
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
Year
|
|
Revenues
|
|
$
|
486,185
|
|
|
$
|
640,540
|
|
|
$
|
636,919
|
|
|
$
|
378,040
|
|
|
$
|
2,141,684
|
|
Operating
income
|
|
$
|
1,759
|
|
|
$
|
11,032
|
|
|
$
|
13,381
|
|
|
$
|
11,719
|
|
|
$
|
37,891
|
|
Net
income
|
|
$
|
1,645
|
|
|
$
|
7,328
|
|
|
$
|
10,763
|
|
|
$
|
6,353
|
|
|
$
|
26,089
|
|
Net
income per common unit - basic
|
|
$
|
0.04
|
|
|
$
|
0.17
|
|
|
$
|
0.25
|
|
|
$
|
0.14
|
|
|
$
|
0.61
|
|
Net
income per common unit - diluted
|
|
$
|
0.04
|
|
|
$
|
0.17
|
|
|
$
|
0.25
|
|
|
$
|
0.14
|
|
|
$
|
0.60
|
|
Cash
distributions per common unit
(1)
|
|
$
|
0.2850
|
|
|
$
|
0.3000
|
|
|
$
|
0.3150
|
|
|
$
|
0.3225
|
|
|
$
|
1.2225
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
Quarters
|
|
|
Total
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
Year
|
|
Revenues
|
|
$
|
183,564
|
|
|
$
|
201,016
|
|
|
$
|
354,270
|
|
|
$
|
460,803
|
|
|
$
|
1,199,653
|
|
Operating
income (loss)
|
|
$
|
1,580
|
|
|
$
|
(1,319
|
)
|
|
$
|
7,043
|
|
|
$
|
(12,679
|
)
|
|
$
|
(5,375
|
)
|
Net
income (loss)
|
|
$
|
1,585
|
|
|
$
|
(1,372
|
)
|
|
$
|
1,699
|
|
|
$
|
(15,462
|
)
|
|
$
|
(13,550
|
)
|
Net
income (loss) per common unit - basic and diluted
|
|
$
|
0.11
|
|
|
$
|
(0.09
|
)
|
|
$
|
0.07
|
|
|
$
|
(0.49
|
)
|
|
$
|
(0.64
|
)
|
Cash
distributions per common unit
(1)
|
|
$
|
0.21
|
|
|
$
|
0.22
|
|
|
$
|
0.23
|
|
|
$
|
0.27
|
|
|
$
|
0.93
|
|
(1) Represents
cash distributions declared and paid in the applicable period.
Schedule
I - Condensed Financial Information
|
|
|
|
|
|
|
|
|
|
|
|
Genesis
Energy, L.P. (Parent Company Only)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed
Statements of Income and Comprehensive Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
Equity
in earnings (losses) of subsidiaries
|
|
$
|
26,089
|
|
|
$
|
(13,550
|
)
|
|
$
|
8,381
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income (loss)
|
|
|
26,089
|
|
|
|
(13,550
|
)
|
|
|
8,381
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
comprehensive loss of subsidiary
|
|
|
(962
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
comprehensive income (loss)
|
|
$
|
25,127
|
|
|
$
|
(13,550
|
)
|
|
$
|
8,381
|
|
Condensed
Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
thousands)
|
|
Assets
|
|
|
|
|
|
|
Cash
|
|
$
|
3
|
|
|
$
|
10
|
|
Investment
in subsidiaries
|
|
|
665,334
|
|
|
|
664,480
|
|
Advances
to subsidiaries
|
|
|
91
|
|
|
|
84
|
|
Total
Assets
|
|
$
|
665,428
|
|
|
$
|
664,574
|
|
|
|
|
|
|
|
|
|
|
Partners'
Capital
|
|
|
|
|
|
|
|
|
Limited
Partners
|
|
$
|
649,046
|
|
|
$
|
647,340
|
|
General
Partner
|
|
|
17,344
|
|
|
|
17,234
|
|
Accumulated
other comprehensive income
|
|
|
(962
|
)
|
|
|
-
|
|
Total
Partners' Capital
|
|
$
|
665,428
|
|
|
$
|
664,574
|
|
|
|
|
|
|
|
|
|
|
See
accompanying notes to condensed financial statements.
|
|
Schedule
I - Condensed Financial Information - Continued
|
|
|
|
|
|
|
|
|
|
|
|
Genesis
Energy, L.P. (Parent Company Only)
|
|
|
|
|
|
|
|
|
|
|
|
Condensed
Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flows from Operating Activities:
|
|
|
|
|
|
|
|
|
|
Net
income (loss)
|
|
$
|
26,089
|
|
|
$
|
(13,550
|
)
|
|
$
|
8,381
|
|
Equity
in (earnings) losses of GCO
|
|
|
(15,773
|
)
|
|
|
13,550
|
|
|
|
(8,381
|
)
|
Equity
in (earnings) losses of GNEJD
|
|
|
(10,316
|
)
|
|
|
-
|
|
|
|
-
|
|
Change
in advances to GCO
|
|
|
(7
|
)
|
|
|
4
|
|
|
|
-
|
|
Net
cash (used in) provided by operating activities
|
|
|
(7
|
)
|
|
|
4
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flows from Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
in GCO
|
|
|
(510
|
)
|
|
|
(216,172
|
)
|
|
|
-
|
|
Distributions
from GCO - return of investment
|
|
|
50,534
|
|
|
|
17,175
|
|
|
|
10,408
|
|
Net
cash provided by (used in) investing activities
|
|
|
50,024
|
|
|
|
(198,997
|
)
|
|
|
10,408
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flows from Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance
of limited and general partner interests, net
|
|
|
510
|
|
|
|
216,172
|
|
|
|
-
|
|
Distributions
to limited and general partners
|
|
|
(50,534
|
)
|
|
|
(17,175
|
)
|
|
|
(10,408
|
)
|
Net
cash (used in) provided by financing activities
|
|
|
(50,024
|
)
|
|
|
198,997
|
|
|
|
(10,408
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
(decrease) increase in cash
|
|
|
(7
|
)
|
|
|
4
|
|
|
|
-
|
|
Cash
at beginning of period
|
|
|
10
|
|
|
|
6
|
|
|
|
6
|
|
Cash
at end of period
|
|
$
|
3
|
|
|
$
|
10
|
|
|
$
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See
accompanying notes to condensed financial statements.
|
|
Schedule
I – Condensed Financial Statements – Continued
Genesis
Energy, L.P. (Parent Company Only)
Notes to
Condensed Financial Statements
1. Basis
of Presentation
Genesis
Energy, L.P., or GEL, is the owner of 99.99% of Genesis Crude Oil, L.P., or GCO
and 100% of Genesis NEJD Holdings, LLC, or GNEJD. These parent
company only financial statements for GEL summarize the results of operations
and cash flows for the years ended December 31, 2008, 2007 and 2006, and GEL’s
financial position at December 31, 2008 and 2007. In these
statements, GEL’s investments in GCO and GNEJD are stated on the equity method
basis of accounting. The GEL statements should be read in conjunction
with the consolidated financial statements of Genesis Energy, L.P.
As
discussed in Note 10 of the Notes to the Consolidated Financial Statements, the
terms of the credit facility with GCO, limit the amount of distributions that
GCO and its subsidiaries may pay to GEL. Such distributions may
not exceed the sum of the distributable cash generated by GCO and its
subsidiaries for the eight most recent quarters, less the sum of the
distributions made with respect to those quarters. This restriction results in
the restricted net assets (as defined in Rule 4-08 (e)(3) of Regulation S-X) of
GEL’s subsidiary exceeding 25% of the consolidated net assets of GEL and its
subsidiaries.
2. Contingencies
GEL
guarantees the obligations of GCO under our credit facility. See Note
10 of the Notes to the Consolidated Financial Statements of Genesis Energy, L.P.
for a description of GCO’s credit facility
GEL
guarantees the obligations of GCO under our lease with Paccar Leasing
Services. See Note 19 of the Notes to the Consolidated Financial
Statements of Genesis Energy, L.P.
GEL has
guaranteed crude oil and petroleum products purchases of GCO and its
subsidiaries. These guarantees, totaling $40.8 million, were provided
to counterparties. To the extent liabilities exist under the
contracts subject to these guarantees, such liabilities are included in the
consolidated financial statements of Genesis Energy, L.P.
GEL has
guaranteed $7.5 million of the outstanding debt of DG Marine under its credit
facility. This guarantee will expire on May 31, 2009, if DG Marine’s
leverage ratio under its credit facility is less than 4.00 to 1.00.
3. Supplemental
Cash Flow Information
In May
2008, additional limited partner interests in GCO with a value of $25 million
were issued to GEL. GEL issued common units with an equal value as part of the
consideration in acquisition of the Free State Pipeline from
Denbury. In July 2008, additional limited partner interests in GCO
with a value of $16.7 million were issued to GEL. GEL issued common
units with an equal value as part of the consideration in the Grifco
acquisition. These transactions are non-cash transactions and are not
included in the Statements of Cash Flows in investing or financing
activities.
146