UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington,
D.C. 20549
Form
10-K
x ANNUAL REPORT PURSUANT TO
SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the
fiscal year ended December 31, 2007
OR
¨ TRANSITION REPORT PURSUANT TO
SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission
file number 1-12295
GENESIS
ENERGY, L.P.
(Exact name of registrant as specified
in its charter)
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Delaware
(State
or other jurisdiction of incorporation
or organization)
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76-0513049
(I.R.S.
Employer Identification
No.)
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500
Dallas, Suite 2500, Houston, TX
(Address
of principal executive offices)
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77002
(Zip
code)
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Registrant's
telephone number, including area code:
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(713)
860-2500
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Securities
registered pursuant to Section 12(b) of the Act:
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Title
of Each Class
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Name
of Each Exchange on Which Registered
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|||
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Common
Units
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American
Stock Exchange
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Securities
registered pursuant to Section 12(g) of the Act:
NONE
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Exchange Act.
Yes ¨ No
x
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act.
Yes ¨ No
x
Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Act during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and
(2) has been subject to such filing requirements for the past 90
days.
Yes x No
¨
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the best
of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.
x
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of “large accelerated filer”,
”accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act.
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Large
accelerated filer¨
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Accelerated
filer x
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Non-accelerated
filer ¨
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Smaller
reporting company¨
|
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2) of the Act).
Yes ¨ No
x
The
aggregate market value of the common units held by non-affiliates of the
Registrant on June 29, 2007 (the last business day of Registrant’s most recently
completed second fiscal quarter) was approximately $444,166,000 based on $34.88
per unit, the closing price of the common units as reported on the American
Stock Exchange. On February 29, 2008, the Registrant had 38,253,264
common units outstanding.
GENESIS ENERGY, L.P.
2007
FORM 10-K ANNUAL REPORT
Table
of Contents
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Page
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Part
I
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Item
1
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4
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Item
1A.
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19
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Item
1B.
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33
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Item
2.
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33
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Item
3.
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34
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Item
4.
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34
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Part
II
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Item
5.
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34
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Item
6.
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36
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Item
7.
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38
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Item
7A.
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61
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Item
8.
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62
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Item
9.
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62
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Item
9A.
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63
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Item
9B.
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65
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Part
III
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Item
10.
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65
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Item
11.
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67
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Item
12.
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84
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Item
13.
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85
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Item
14.
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88
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Part
IV
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Item
15.
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89
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FORWARD-LOOKING
INFORMATION
The
statements in this Annual Report on Form 10-K that are not historical
information may be “forward looking statements” within the meaning of the
various provisions of the Securities Act of 1933 and the Securities Exchange Act
of 1934. All statements, other than historical facts, included in
this document that address activities, events or developments that we expect or
anticipate will or may occur in the future, including things such as plans for
growth of the business, future capital expenditures, competitive strengths,
goals, references to future goals or intentions and other such references are
forward-looking statements. These forward-looking statements are
identified as any statement that does not relate strictly to historical or
current facts. They use words such as “anticipate,” “believe,”
“continue,” “estimate,” “expect,” “forecast,” “intend,” “may,” “plan,”
“position,” “projection,” “strategy” or “will” or the negative of those terms or
other variations of them or by comparable terminology. In particular,
statements, expressed or implied, concerning future actions, conditions or
events or future operating results or the ability to generate sales, income or
cash flow are forward-looking statements. Forward-looking statements
are not guarantees of performance. They involve risks, uncertainties
and assumptions. Future actions, conditions or events and future
results of operations may differ materially from those expressed in these
forward-looking statements. Many of the factors that will determine
these results are beyond our ability or the ability of our affiliates to control
or predict. Specific factors that could cause actual results to
differ from those in the forward-looking statements include:
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demand for, the supply of,
changes in forecast data for, and price trends related to crude oil,
liquid petroleum, natural gas and natural gas liquids or “NGLs”, sodium
hydrosulfide and caustic soda in the United States, all of which may be
affected by economic activity, capital expenditures by energy producers,
weather, alternative energy sources, international events, conservation
and technological advances;
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throughput levels and
rates;
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changes in, or challenges to,
our tariff rates;
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our ability to successfully
identify and consummate strategic acquisitions, make cost saving changes
in operations and integrate acquired assets or businesses into our
existing operations;
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service interruptions in our
liquids transportation systems, natural gas transportation systems or
natural gas gathering and processing
operations;
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shut-downs or cutbacks at
refineries, petrochemical plants, utilities or other businesses for which
we transport crude oil, natural gas or other products or to whom we sell
such products;
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changes in laws or regulations
to which we are subject;
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our inability to borrow or
otherwise access funds needed for operations, expansions or capital
expenditures as a result of existing debt agreements that contain
restrictive financial
covenants;
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loss of key
personnel;
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the effects of competition, in
particular, by other pipeline
systems;
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hazards and operating risks
that may not be covered fully by
insurance;
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the condition of the capital
markets in the United
States;
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loss of key
customers;
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the political and economic
stability of the oil producing nations of the world;
and
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general economic conditions,
including rates of inflation and interest
rates.
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You
should not put undue reliance on any forward-looking statements. When
considering forward-looking statements, please review the risk factors described
under “Risk Factors” discussed in Item 1A. Except as required by
applicable securities laws, we do not intend to update these forward-looking
statements and information.
PART
I
Item
1. Business
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; “Denbury” means Denbury Resources
Inc. and its subsidiaries; “CO2” means
carbon dioxide; and “NaHS”, which is commonly pronounced as “nash”, means sodium
hydrosulfide. Except to the extent otherwise provided, the
information contained in this form is as of December 31, 2007.
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, and trucks and truck
terminals. We provide services to refinery owners; oil, natural gas
and CO2 producers;
industrial and commercial enterprises that use CO2 and other
industrial gases; and individuals and companies that use our dry-goods 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 and, to a lesser extent, natural gas and CO2 for others
for a fee in the Gulf Coast region of the U.S. through approximately 500 miles
of pipeline. We own and operate three crude oil common carrier
pipelines, a small CO2 pipeline
and several 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.
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 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 approximately 300
trucks, 600 trailers and almost 1.5 million barrels of liquid storage
capacity at eleven different locations. 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
generally involves back-to-back purchases and sales, matching our sale and
purchase volumes on a monthly basis.
Industrial
Gases.
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CO2
— We supply CO2
to industrial customers under seven long-term contracts, with an average
remaining contract life of 8 years. We acquired those
contracts, as well as the CO2
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 CO2
to our industrial customers is the effective difference between the price
at which we sell our CO2
under each contract and the price at which we acquired our CO2
pursuant to our volumetric production payments (also known as VPPs), minus
transportation costs.
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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 syngas
(a combination of carbon monoxide and hydrogen) and high-pressure
steam. 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.
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Sandhill Group LLC –
Through our 50% interest in a joint venture, we process raw CO2 for
sale to other customers for uses ranging from completing oil and natural
gas producing wells to food processing. The Sandhill facility acquires
CO2 from
us under one of the long-term supply contracts described
above.
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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.
We
continue to benefit from our strategic affiliation with Denbury Resources Inc.
(NYSE:DNR), which indirectly owns 100% of our general partner interest, all of
our incentive distribution rights and 7.4% of our outstanding common
units. Denbury, which had an equity market capitalization of
approximately $7.7 billion as of February 29, 2008, operates primarily in
Mississippi, Louisiana and Texas, emphasizing the tertiary recovery of oil using
CO2
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 CO2 tertiary
recovery expertise along with large deposits of CO2 reserves,
approximately 5.6 trillion cubic feet of estimated proved CO2 reserves
as of December 31, 2007. Other than the CO2 reserves
owned by Denbury, we are not aware of any significant natural sources of CO2 from East
Texas to Florida. Denbury is conducting its CO2 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. In addition to the amounts it has already expended on the Free
State and North East Jackson Dome, or NEJD, CO2 pipelines,
Denbury has announced that it expects to spend approximately $775 million
between December 31, 2007 and the end of 2009 to build CO2 pipelines
to support its tertiary oil recovery expansions.
We
believe Denbury’s equity ownership interests in us provide Denbury with economic
and strategic incentives to furnish business opportunities to us in the form of
acquisitions, leases, transportation agreements and other transactions. In fact,
Denbury has indicated that it may use us as a vehicle to provide its midstream
infrastructure needs, particularly with respect to CO2 pipelines.
We believe Denbury may provide us with future growth opportunities due to the
following additional factors, among others:
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Denbury’s
continued need to construct pipelines and gathering systems necessary to
support its operations, which we may have an opportunity to provide for
them;
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Denbury’s
significant economic and strategic interests in
us;
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the
close proximity of certain of Denbury’s assets and operations to certain
of our assets and operations; and
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the
extent of Denbury’s growth capital
requirements.
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Denbury
has announced its intention, which it may change at any time, to drop down
certain midstream assets. We expect to complete a drop down
transaction involving the Free State and NEJD CO2 pipelines
in the first quarter of 2008.
Although
our relationship with Denbury may provide us with a source of acquisition and
other growth opportunities, Denbury is not obligated to enter into any
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 its midstream
infrastructure. 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 significant strength, it also is a source of potential
conflicts.
Our
Objective 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:
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Expanding our asset base
through strategic and accretive acquisitions with
third parties and Denbury. We intend to expand
our asset base through strategic and accretive acquisitions from Denbury
and third parties in new and existing markets. Such
acquisitions could be structured as, among other things, purchases,
leases, tolling or similar agreements or joint
ventures.
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Expanding our asset base
through strategic construction and development projects with third parties
and Denbury. We intend to expand our asset base through
strategic and accretive construction and developments projects, or joint
ventures, in new and existing
markets.
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Optimizing our CO2 and other industrial gases
expertise and infrastructure. We intend to optimize our expertise
regarding CO2 and
other industrial gases to create growth
opportunities.
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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
oil transportation, gathering, blending and marketing services to them and
other producers as production from those properties
increases.
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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 broad array of services, leveraging our strong relationships
with refinery owners and producers, and deploying our proprietary
knowledge.
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Increasing the utilization
rates 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 for a relatively nominal
amount.
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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. While our refinery services
division has some exposure to monthly changes in the prices of caustic
soda and sodium hydrosulfide, also referred to as NaHS (pronounced
“nash”), a natural by-product of those operations, prices for those
commodities are not as volatile as prices for oil, natural gas and their
derivatives.
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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. While we have the capability to provide an ever
increasing array of integrated services to both producers and refineries,
we believe our cash flows will continue to be relatively stable due to the
diversity of our customer base, the nature of our services and the
geographic location of our
operations.
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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 and operation of
joint ventures and strategic
alliances.
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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.
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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:
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Experienced, Knowledgeable and
Motivated Senior Management Team with Proven Track Record. Our
senior management team has over 40 years of combined 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 execute our growth strategy in a
manner that is accretive on a “distribution per unit” basis, our general
partner has undertaken to negotiate agreements relating to an
equity-based incentive compensation arrangement to provide the
members of our senior management team with the opportunity to earn an
interest in our general partner if performance criteria are
met. Those performance criteria are expected to include a
correlation between earning the general partner interest with the
successful completion of non-Denbury acquisitions and/or other organic
growth that earn a reasonable rate of
return.
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Unique Platform, Limited
Competition and Anticipated Growing Demand in 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:
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sulfur
handling and removal is typically not a core business of our refinery
customers, especially when employing our proprietary processes and
expertise that result in the by-product of
NaHS;
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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;
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the
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;
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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;
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other
than the possibility of each individual refinery employing its own sulfur
removal operations, we do not have many competitors in the sulfur removal
business; and
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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.
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Ø
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Supply and Logistics
Division Supports 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:
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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 input into the NaHS sulfur removal
process), as well as our ability to store, transport and market
NaHS;
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our
pipeline transportation division receives throughput related to the
gathering and marketing services our supply and logistics division
provides to producers;
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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 refinery customers;
and
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our
supply and logistics division gives us the opportunity to blend/store and
distribute products made by our refinery
customers.
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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 U.S. 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; CO2
producers; industrial and commercial enterprises that use CO2 and
other industrial gases; and individuals and companies that use our
dry-goods trucking services. Our operations and assets are characterized
by:
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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,) and inland refining operations, that we believe are
contemplating expansion.
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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.
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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.
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Ø
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Financial
Flexibility. We have the
financial flexibility to pursue additional growth projects. As of
December 31, 2007, we had $80 million of loans and
$5.3 million in letters of credit outstanding under our
$500 million credit facility, resulting in $271 million of
remaining credit availability under our borrowing base. Our borrowing base
as of December 31, 2007 was approximately $356 million, and 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.
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Ø
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Relationship with
Denbury. We have a strong relationship with Denbury, the
indirect owner of our general partner. Denbury has indicated that it may
use us as a vehicle to provide its midstream infrastructure needs,
particularly with respect to CO2
pipelines. We believe Denbury has an economic and strategic incentive to
provide business opportunities to us. We also believe that, if we can
become an instrumental component of Denbury’s future development projects,
we can leverage those 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.
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Recent
Developments
Acquisition
of Refinery Services Division and Other Businesses
On
July 25, 2007, we acquired five energy-related businesses, including the
operations that comprise our refinery services division, from several entities
owned and controlled by the Davison family of Ruston, Louisiana. The other
acquired businesses, which transport, store, procure and market petroleum
products and other bulk commodities, are included in our supply and logistics
segment.
Our
acquisition agreement with the Davisons provided that we would deliver to them
$563 million of consideration, half in common units (13,459,209 common
units at an agreed-to value of $20.8036 per unit) and half in cash, subject to
specified purchase price adjustments. Our financial statements at December 31,
2007 reflect a total acquisition price of $631.5 million, which includes
purchase price adjustments, our transaction costs of $8.9 million, working
capital acquired, net of cash acquired, and a valuation of the units at $24.52
per unit, which was the average closing price of our units during the five
trading day period ending two days after we signed the acquisition
agreement.
The
Davison family was our largest unitholder at December 31, 2007, with a 33.0%
interest in us (represented by 12,619,069 of our common units). It
has designated two of the members of the board of directors of our general
partner, and as long as it maintains a specified minimum ownership 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.
For example, prior to July 25, 2008, the Davison family may not sell more
than 20% of its common units.
Denbury
Drop Down Transactions
We have
reached substantial agreement and are in the process of finalizing the business
issues with Denbury and the lenders in our credit facility as to the terms of
the drop-down by Denbury to us of Denbury’s NEJD and Free State CO2 pipelines
and the terms of a long-term transportation service arrangement for the Free
State line and a 20-year financing lease for the NEJD system. We expect to pay
for these pipeline assets with $225 million in cash and $25 million of our
common units based on the average closing price of our units on the thirty days
prior to the closing of the transaction. We expect to receive approximately $30
million per annum, in the aggregate, under the lease and the transportation
services agreement (and a lesser pro-rated amount for 2008), with future
payments for the NEJD pipeline fixed at $20.7 million per year during the term
of the financing lease, and the payments relating to the Free State pipeline
dependant on the volumes of CO2
transported therein. While the business terms of the transactions and associated
documentation have been substantially completed, closing remains subject to
completion of closing documentation, receipt of a fairness opinion and approval
by the audit committee and the board of directors of our general
partner.
Nine
Consecutive Distribution Rate Increases
We have
increased our quarterly distribution rate for nine consecutive
quarters. On February 14, 2008, we paid a cash distribution of $0.285
per unit to unitholders of record as of February 7, 2008, an increase per unit
of $0.015 (or 5.6%) from the distribution in the prior quarter. In
the immediately preceding quarter, we increased our quarterly distribution rate
by $0.04 (or 17.4%), and in each preceding quarter, we increased our
distribution rate by $0.01. 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.
Acquired
Terminal and Dock Facilities
Effective
July 1, 2007, we paid $8.1 million for BP Pipelines (North America)
Inc.’s Port Hudson 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. That acquisition
was funded with borrowings under our credit facility.
Florida
Oil Pipeline System Expansion
We
committed to construct an extension of our existing Florida oil pipeline system
that would extend to producers operating in southern Alabama. That 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. That project also will
include gathering connections to approximately 30 wells and oil storage
capacity of 20,000 barrels in the field. We expect to place those
facilities in service in the fourth quarter of 2008.
Description
of Segments and Related Assets
We
conduct our business through four primary segments: Pipeline Transportation,
Refinery Services, Industrial Gases and Supply and Logistics. Our Supply and
Logistics segment was previously known as Crude Oil Gathering and Marketing.
With the Davison acquisition, we expanded our operations into petroleum products
and other transportation services, and combined these operations due to their
similarities and our approach to managing these operations. 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 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 CO2 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
CO2
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 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
recently committed to construct an extension of our existing Florida oil
pipeline system 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 30 wells and
additional oil storage capacity of 20,000 barrels in the field. The project is
expected to be placed in service in the second half of 2008.
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 pipe. 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.
On a much
smaller scale, we also transport CO2 and gather
natural gas for a fee. However, with the acquisition of the CO2 pipelines
from Denbury expected in the first quarter of 2008, our CO2 pipelines
(including leased lines) will extend approximately 280 miles. See
additional discussion in ‘Denbury Drop Down Transactions”
above.
Customers
Denbury,
a large independent energy company, is the sole shipper (other than us) on our
Mississippi System. 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 crude
oil 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 proprietary 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,
which we sell 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 and the 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 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. We
expect to complete an additional NaHS facility at a refinery in Utah in
2008.
Customers
Refinery
Services: At December 31, 2007, 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 11% of the
revenues of the refinery services segment for the five month period of our
ownership resulted from sales to Kennecott Utah Copper, a subsidiary of Rio
Tinto plc.
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 Denbury is conducting substantial tertiary recovery
operations utilizing CO2 flooding
around our Mississippi System, we became familiar with CO2-related
activities and, ultimately, began our CO2 business
in 2003. Our relationships with industrial customers who use CO2 have
continued to expand, which has introduced us to potential opportunities
associated with other industrial gases. We (i) supply CO2 to
industrial customers, (ii) process raw CO2 and sell
that processed CO2, and (iii)
manufacture and sell syngas, a combination of carbon monoxide and
hydrogen.
CO2 –
Industrial Customers
We supply
CO2 to
industrial customers under seven long-term CO2 sales
contracts. We acquired those contracts, as well as the CO2 necessary
to satisfy substantially all of our expected obligations under those contracts,
in three separate transactions with Denbury. Since 2003, we have
purchased those contracts, along with three VPPs representing 280.0 Bcf of
CO2
(in the aggregate), from Denbury for a total of $43.1 million in
cash. We sell our CO2 to
customers who treat the CO2 and sell
it to end users for use for beverage carbonation and food chilling and
freezing. Our compensation for supplying CO2 to our
industrial customers is the effective difference between the price at which we
sell our CO2 under each
contract and the price at which we acquired our CO2 pursuant
to our VPPs, minus transportation costs. We expect some seasonality
in our sales of CO2. 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, 2007, we have 182.3
Bcf of CO2 remaining
under the VPPs.
Currently,
all of our CO2
supply is from our interests – our VPPs - in fields producing
naturally occurring CO2. The
agreements we executed with Denbury when we acquired the VPPs provide that we
may acquire additional CO2 from
Denbury under terms similar to the original agreements should additional volumes
be needed to meet our obligations under the contracts. Based on the
current volumes being sold to our customers, we believe that we will need to
acquire additional volumes from Denbury in 2014. When our VPPs
expire, we will have to obtain our CO2 supply
from Denbury, from other sources, or discontinue the CO2 supply
business. Denbury will have no obligation to provide us with CO2 once our
VPPs expire, and has the right to compete with us. 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 CO2 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.
CO2 -
Processing
On April
1, 2006, we acquired a 50% partnership interest in Sandhill for $5.0 million in
cash, which we funded with cash on hand. Reliant Processing Ltd. owns
the remaining 50% of Sandhill. Sandhill is a limited liability
company that owns a CO2 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 CO2 from us
under a long-term supply contract that we acquired in 2005 from
Denbury. 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
On April
1, 2005, we acquired from TCHI, Inc., a wholly-owned subsidiary of ChevronTexaco
Global Energy, Inc., a 50% partnership interest in T&P Syngas for $13.4
million in cash, which we funded with proceeds from our credit
facility. 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 also is our partner in
the joint venture and owns the remaining 50% interest.
Customers
Five of
the seven contracts for supplying CO2 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 CO2
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 two of those customers
representing approximately 40% of Sandhill’s total revenues of approximately $11
million in 2007. In addition, in 2007, Sandhill sold approximately
$1.9 million of CO2 to
affiliates of Reliant Processing, Ltd., a 50% owner of 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 CO2
supply is from our interest – our VPPs – in fields producing naturally occurring
sources. We believe we have an adequate access to supply to service
existing contracts through their terms. In the future we may have to
obtain our CO2 supply
from manufactured processes. Naturally-occurring CO2, 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 CO2 customers
have facilities that are connected to Denbury’s CO2 pipeline,
which makes delivery easy and efficient. Once our existing VPPs
expire, we will have to obtain CO2 from
Denbury or other suppliers should we choose to remain in the CO2 supply
business, and the competition and pricing issues we will face at that time are
uncertain.
With
regard to our CO2 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 CO2 is not
taken.
Due to
the long-term contract and location of our syngas facility, as well as the costs
involved in establishing a competing facility, 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 CO2. As
discussed above, the limited amounts of naturally-occurring CO2 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 was previously known as our crude oil gathering and
marketing segment. With the acquisition of the Davison businesses, we
renamed the segment and we included the petroleum products, fuel logistics,
terminaling and truck transportation activities we acquired from the
Davisons.
Our crude
oil gathering and marketing operations are concentrated in Texas, Louisiana,
Alabama, Florida and Mississippi. Those operations, which involve
purchasing, gathering and transporting by trucks and pipelines operated by us
and trucks, pipelines and barges operated by others, and reselling, help to
ensure (among other things) a base supply source for our oil pipeline systems.
Our profit for those services is derived from the difference between the price
at which we re-sell the crude oil less the price at which we purchase that oil,
minus the associated costs of aggregation and any cost of supplying credit. The
most substantial component of our aggregating costs relates to operating our
fleet of leased trucks. 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.
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, we gained approximately 225 trucks, 525 trailers and 1.3
million barrels of existing leased and owned storage and 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 a
service 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. The opportunities to provide this service cannot be
predicted, but the contribution to margin as a percentage of the revenues tends
to be higher than in the same percentage attributable to our recurring
operations.
We also
have access through our terminals on waterways in the southeastern United States
to provide our customers with product by barge. In combination with
our historical focus on crude oil, 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
2007, more than ten percent of our consolidated revenues were generated from
each of two customers, Shell Oil Company and Occidental Energy Marketing,
Inc. 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 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,
mining and other companies which 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.
Employees
To carry
out our business activities, our general partner employed, at February 29, 2008
approximately 655 employees. None of those employees are represented
by labor unions, and we believe that relationships with those employees are
good.
Organizational
Structure
Genesis
Energy, Inc., a Delaware corporation, serves as our sole general partner and as
our general partner of all of our subsidiaries. Our general partner
is owned by Denbury Gathering & Marketing, Inc., a subsidiary of
Denbury. Below is a chart depicting our ownership
structure.
(1)The
incentive compensation arrangement with which our general partner has undertaken
to negotiate definitive agreements with the Senior Executives (see Item 11.
Executive Compensation.) would provide them the opportunity to earn up to 14.4%
of the equity interest in our general partner.
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 CO2 pipeline
are subject to regulation by the state agencies in the states in which they are
located.
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, 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. 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 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.
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 other environmental
laws. We may therefore be subject to liability and regulation under
CERCLA, RCRA and analogous state laws for hydrocarbons or other wastes that may
have been disposed of or released on or under our current or former properties
at other locations where such 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 imposes 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 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.
Safety
and Security Regulations
Our crude
oil, natural gas and CO2 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 require
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. At December 31, 2007,
we had completed assessments and repairs on the major sections of our
pipelines. On the pipeline segments initially tested, we have started
the process of reassessment required every five years.
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 CO2 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 required
operators to develop and submit a written program. The regulations
also required 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.
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.genesiscrudeoil.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.
Item
1A. Risk Factors
Risks
Related to Our Business
We
may not be able to fully execute our growth strategy if we are unable to raise
debt and equity capital at an affordable price.
Our
strategy contemplates substantial growth through the development and acquisition
of a wide range of midstream and other energy infrastructure assets while
maintaining a strong balance sheet. This strategy includes constructing and
acquiring additional assets and businesses to enhance our ability to compete
effectively, diversify our asset portfolio and, thereby, provide more stable
cash flow. We regularly consider and enter into discussions regarding, and are
currently contemplating, additional potential joint ventures, stand-alone
projects and other transactions that we believe will present opportunities to
realize synergies, expand our role in the energy infrastructure business, and
increase our market position and, ultimately, increase distributions to
unitholders.
We will
need new capital to finance the future development and acquisition of assets and
businesses. Limitations on our access to capital will impair our ability to
execute this strategy. Expensive capital will limit our ability to develop or
acquire accretive assets. Although we intend to continue to expand our business,
this strategy may require substantial capital, and we may not be able to raise
the necessary funds on satisfactory terms, if at all.
In
addition, we are experiencing increased competition for the assets we purchase
or contemplate purchasing. Increased competition for a limited pool of assets
could result in our not being the successful bidder more often or our acquiring
assets at a higher relative price than that which we have paid historically.
Either occurrence would limit our ability to fully execute our growth strategy.
Our ability to execute our growth strategy may impact the market price of our
securities.
We
may 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:
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the
volumes and prices at which we purchase and sell crude oil, refined
products, and caustic soda;
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the
volumes of sodium hydrosulfide, or NaHS, that we receive for our refinery
services and the prices at which we sell
NaHS;
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the
demand for our trucking and pipeline transportation
services;
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the
volumes of CO2 we
sell and the prices at which we sell
it;
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the
demand for our terminal storage
services;
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the
level of our operating costs;
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the
level of our general and administrative costs;
and
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prevailing
economic conditions.
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In
addition, the actual amount of cash we will have available for distribution will
depend on other factors that include:
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the
level of capital expenditures we make, including the cost of acquisitions
(if any);
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our
debt service requirements;
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fluctuations
in our working capital;
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restrictions
on distributions contained in our debt
instruments;
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our
ability to borrow under our working capital facility to pay distributions;
and
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the
amount of cash reserves established by our general partner in its sole
discretion in the conduct of our
business.
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Our
ability to pay distributions each quarter depends primarily on our cash flow,
including cash flow from financial reserves and working capital borrowings, and
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, 2007, we
had approximately $80 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:
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incur
additional indebtedness or liens;
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make
payments in respect of or redeem or acquire any debt or equity issued by
us;
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sell
assets;
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make
loans or investments;
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make
guarantees;
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enter
into any hedging agreement for speculative
purposes;
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acquire
or be acquired by other companies;
and
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amend
some of our contracts.
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The
restrictions under our indebtedness may prevent us from engaging in certain
transactions which might otherwise be considered beneficial to us and could have
other important consequences to unitholders. For example, they
could:
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increase
our vulnerability to general adverse economic and industry
conditions;
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limit
our ability to make distributions; to fund future working capital, capital
expenditures and other general partnership requirements; to engage in
future acquisitions, construction or development activities; or to
otherwise fully realize the value of our assets and opportunities because
of the need to dedicate a substantial portion of our cash flow from
operations to payments on our indebtedness or to comply with any
restrictive terms of our
indebtedness;
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limit
our flexibility in planning for, or reacting to, changes in our businesses
and the industries in which we operate;
and
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place
us at a competitive
disadvantage as compared to our competitors that have less
debt.
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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, natural
gas and CO2
- 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, natural
gas and CO2— 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 CO2
operations).
Our
source of volumes depends on successful exploration and development of
additional oil and natural gas reserves by others and other matters beyond our
control.
The oil,
natural gas 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:
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geographic
proximity to the production;
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costs
of connection;
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available
capacity;
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rates;
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logistical
efficiency in all of our
operations;
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operational
efficiency in our refinery services
business;
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customer
relationships; and
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access
to markets.
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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 CO2 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 acquired from the Davison
family.
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
crude oil gathering and marketing 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. Even if our credit review and analysis mechanisms work properly, we
could still experience losses in dealings with other parties.
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:
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rate
structures;
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rates
of return on equity;
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recovery
of costs;
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the
services that our regulated assets are permitted to
perform;
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the
acquisition, construction and disposition of assets;
and
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to
an extent, the level of competition in that regulated
industry.
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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 CO2 operations
involves us supplying CO2
to industrial customers using reserves attributable to our volumetric production
payment interests, which are a finite resource and projected to terminate around
2016.
The cash
flow from our CO2 operations
involves us supplying CO2 to
industrial customers using reserves attributable to our volumetric production
payments, which are projected to terminate around 2016. Unless we are able to
obtain a replacement supply of CO2 and enter
into sales arrangements that generate substantially similar economics, our cash
flow could decline significantly around 2016.
Fluctuations
in demand for CO2 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 CO2.
Our
wholesale CO2 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
CO2
operations are exposed to risks related to Denbury’s operation of its CO2 fields,
equipment and pipeline as well as any of our facilities that Denbury
operates.
Because
Denbury produces the CO2 and
transports the CO2 to our
customers (including Denbury), any major failure of its operations could have an
impact on our ability to meet our obligations to our CO2 customers
(including Denbury). We have no other supply of CO2 or method
to transport it to our customers. Sandhill relies on us for its
supply of CO2 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 the last five months of 2007, approximately
65% 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:
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difficulties
in the assimilation of the operations, technologies, services and products
of the acquired companies or business
segments;
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inefficiencies
and complexities that can arise because of unfamiliarity with new assets
and the businesses associated with them, including unfamiliarity with
their markets; and
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diversion
of the attention of management and other personnel from day-to-day
business to the development or acquisition of new businesses and other
business opportunities.
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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:
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using
cash from operations;
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delaying
other planned projects;
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incurring
additional indebtedness; or
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issuing
additional debt or equity.
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Any or
all of these methods may not be available when needed or may adversely affect
our future results of operations.
Fluctuations
in interest rates could adversely affect our business.
In
addition to our exposure to commodity prices, we also have exposure to movements
in interest rates. The interest rates on our credit facility are variable. Our
results of operations and our cash flow, as well as our access to future capital
and our ability to fund our growth strategy, could be adversely affected by
significant increases or decreases in interest rates.
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. In addition, the other 50% owner in each of our joint ventures
operates the joint venture facilities. 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.
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 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:
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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;
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Denbury
may compete with us. Denbury owns the largest reserves of CO2 used
for tertiary oil recovery east of the Mississippi River and may manage
these reserves in a manner that could adversely affect our CO2
business;
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our
general partner is allowed to take into account the interest of parties
other than us, such as Denbury, in resolving conflicts of
interest;
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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;
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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;
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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;
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our
general partner controls the enforcement of obligations owed to us by our
general partner and its affiliates;
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our
general partner decides whether to retain separate counsel, accountants or
others to perform services for us;
and
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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.
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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.
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:
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transportation
services
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pipeline
monitoring services; and
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CO2
volumetric production payment.
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In
addition, we have announced that Denbury and we are negotiating several
significant transactions. See “Our General Partner and Our
Relationship with Denbury Resources Inc.” under Item 1 – Business.
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.
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 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, 2007 our general partner and its affiliates own 2,829,055
(approximately 7.4%) of our common units. In the future, they 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.
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 owns 100 percent of 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, and we plan to enter into additional agreements, for example Denbury is
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:
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our
unitholders’ proportionate ownership interest in us will
decrease;
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the
amount of cash available for distribution on each unit may
decrease;
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the
relative voting strength of each previously outstanding unit may be
diminished; and
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the
market price of our common units may
decline.
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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, 2007, our balance sheet reflected $320.7 million of
goodwill and $211.1 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. 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.
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. For example, in response to certain recent
developments, members of Congress are considering substantive changes to the
definition of qualifying income under Internal Revenue Code section
7704(d). It is possible that these efforts could result in changes to
the existing U.S. tax laws that affect publicly-traded partnerships, including
us. We are unable to predict whether any of these changes or other
proposals will ultimately be enacted. Any such changes 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 conclusions of our counsel
expressed in this prospectus or from the positions we take. It may be necessary
to resort to administrative or court proceedings to sustain some or all of our
counsel’s conclusions or the positions we take. A court may not agree with some
or all of our counsel’s conclusions or 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 currently impose a
personal income tax. It is unitholders’ responsibility to file all United States
federal, foreign, state and local tax returns. Our counsel has not rendered an
opinion on the state or local tax consequences of an investment in our common
units.
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. Unresolved Staff Comments
None.
Item
2. Properties
See Item
1. Business. We also have various operating leases for
rental of office space, office and field equipment, and vehicles. See
“Commitments and Off-Balance Sheet Arrangements” in Management’s Discussion and
Analysis of Financial Condition and Results of Operations, and Note 18 of the
Notes to Consolidated Financial Statements for the future minimum rental
payments. Such information is incorporated herein by
reference.
Item
3. Legal Proceedings
We are
involved from time to time in various claims, lawsuits and administrative
proceedings incidental to our business. In our opinion, the ultimate
outcome, if any, of such proceedings is not expected to have a material adverse
effect on our financial condition, results of operations or cash
flows. (See Note 18 of the Notes to Consolidated Financial
Statements.)
Item
4. Submission of Matters to a Vote of Security
Holders
The board
of directors of our general partner (which we refer to as our board of
directors), called a special meeting for December 18, 2007. At that
meeting, unitholders were asked to consider and vote upon:
|
|
·
|
a
proposal to amend certain provisions of our partnership agreement which we
refer to as the “Amendment Proposal,” to allow any affiliated persons or
group who hold more than 20% of our outstanding voting units to vote on
all matters on which holders of our voting units have the right to vote,
other than matters relating to the succession, election, removal,
withdrawal, replacement or substitution of our general partner and to
clarify and expand the concept of “group”;
and
|
|
|
·
|
a
proposal to approve the terms of the Genesis Energy, Inc. 2007 Long Term
Incentive Plan, which provides for awards of our units and other rights to
our employees and, possibly, our directors (the “Incentive Plan
Proposal”).
|
Of the
unitholders entitled to vote at this special meeting, over 60% voted in favor of
these proposals. The voting results were as follows:
|
Votes
Cast
|
Broker
|
|||||||||||||||
|
Matter
|
For
|
Against
|
Abstain
|
Non-Votes
|
||||||||||||
|
Approve
Amendment Proposal
|
8,121,986 | 889,239 | 100,104 | n/a | ||||||||||||
|
Approve
Incentive Plan Proposal
|
8,607,575 | 438,332 | 65,419 | n/a | ||||||||||||
PART
II
Item
5. Market for Registrant’s Common Equity, Related
Stockholder Matters and Issuer Purchases of Equity Securities
Our
common units are listed on the American Stock Exchange under the symbol
“GEL”. The following table sets forth, for the periods indicated, the
high and low sale prices per common unit and the amount of cash distributions
paid per common unit.
|
Price
Range
|
Cash
|
|||||||||||
|
High
|
Low
|
Distributions
(1)
|
||||||||||
|
2008
|
||||||||||||
|
First
Quarter (through February 29, 2008)
|
$ | 25.00 | $ | 15.07 | $ | 0.285 | ||||||
|
2007
|
||||||||||||
|
Fourth
Quarter
|
$ | 28.62 | $ | 20.01 | $ | 0.270 | ||||||
|
Third
Quarter
|
$ | 37.50 | $ | 27.07 | $ | 0.230 | ||||||
|
Second
Quarter
|
$ | 35.98 | $ | 20.01 | $ | 0.220 | ||||||
|
First
Quarter
|
$ | 22.01 | $ | 18.76 | $ | 0.210 | ||||||
|
2006
|
||||||||||||
|
Fourth
Quarter
|
$ | 20.65 | $ | 14.48 | $ | 0.200 | ||||||
|
Third
Quarter
|
$ | 19.18 | $ | 11.20 | $ | 0.190 | ||||||
|
Second
Quarter
|
$ | 14.14 | $ | 10.25 | $ | 0.180 | ||||||
|
First
Quarter
|
$ | 12.85 | $ | 11.25 | $ | 0.170 | ||||||
_____________________
(1) Cash
distributions are shown in the quarter paid and are based on the prior quarter’s
activities.
At
February 29, 2008, we had 38,253,264 common units outstanding, including
2,829,055 common units held by our general partner. As of December
31, 2007, we had approximately 10,200 record holders of our common units, which
include holders who own units through their brokers “in street
name.”
We
distribute all of our available cash, as defined in our partnership agreement,
within 45 days after the end of each quarter to Unitholders of record and to our
general partner. Available cash consists generally of all of our cash
receipts less cash disbursements, adjusted for net changes to cash
reserves. Cash reserves are the amounts deemed necessary or
appropriate, in the reasonable discretion of our general partner, to provide for
the proper conduct of our business or to comply with applicable law, any of our
debt instruments or other agreements. The full definition of
available cash is set forth in our partnership agreement and amendments thereto,
which is filed as an exhibit to this Form 10-K.
In
addition to its 2% general partner interest, 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. See
“Item 7. Management’s Discussion and Analysis of Financial Condition and Results
of Operations – Liquidity and Capital Resources – Distributions” and Note 10 of
the Notes to our Consolidated Financial Statements for further information
regarding restrictions on our distributions.
EQUITY
COMPENSATION PLAN INFORMATION
The
following table summarizes information about our equity compensation plans as of
December 31, 2007.
|
Plan
Category
|
Number
of
securities
to be
issued
upon
exercise
of
outstanding
options,
warrants
and
rights
(a)
|
Weighted-
average
exercise
price
of
outstanding
options,
warrants
and
rights
(b)
|
Number
of securities
remaining
available for
future
issuance under
equity
compensation
plans
(excluding
securities
reflected in
column
(a)
(c)
|
|||||||||
|
Equity
Compensation plans approved by security holders:
|
||||||||||||
|
2007
Long-term Incentive Plan (2007 LTIP)
|
39,362 | (1 | ) | 960,638 | ||||||||
(1) Awards
issued under our 2007 LTIP are phantom units for which the grantee will receive
one common unit for each phantom unit. There is no exercise
price. For additional discussion of our 2007 LTIP, see Note 15 of the
Notes to the Consolidated Financial Statements.
Recent
Sales of Unregistered Securities
On
December 10, 2007, we sold 734,732 common units to our general partner for $15.5
million in a private transaction that was exempt from the registration
requirements of the Securities Act of 1933, pursuant to Section 4(2) thereof.
This sale, made concurrently with a public offering, was made pursuant to our
general partner's preemptive rights to maintain its pro rata interest in our
common units under Section 5.6 of our partnership agreement.
Item
6. Selected Financial Data
The table
below includes selected financial and other data for the Partnership for the
years ended December 31, 2007, 2006, 2005, 2004, and 2003 (in thousands, except per unit and
volume data).
|
Year
Ended December 31,
|
||||||||||||||||||||
|
2007
(1)
|
2006
|
2005
|
2004
|
2003
|
||||||||||||||||
|
Income
Statement Data:
|
||||||||||||||||||||
|
Revenues:
|
||||||||||||||||||||
|
Supply
and logistics (2)
|
$ | 1,094,189 | $ | 873,268 | $ | 1,038,549 | $ | 901,902 | $ | 641,684 | ||||||||||
|
Refinery
services
|
62,095 | - | - | - | - | |||||||||||||||
|
Pipeline
transportation, including natural gas sales
|
27,211 | 29,947 | 28,888 | 16,680 | 15,134 | |||||||||||||||
|
CO2
marketing
|
16,158 | 15,154 | 11,302 | 8,561 | 1,079 | |||||||||||||||
|
Total
revenues
|
1,199,653 | 918,369 | 1,078,739 | 927,143 | 657,897 | |||||||||||||||
|
Costs
and expenses:
|
||||||||||||||||||||
|
Supply
and logistics costs (2)
|
1,078,859 | 865,902 | 1,034,888 | 897,868 | 633,776 | |||||||||||||||
|
Refinery
services operating costs
|
40,197 | - | - | - | - | |||||||||||||||
|
Pipeline
transportation, including natural gas purchases
|
14,176 | 17,521 | 19,084 | 8,137 | 10,026 | |||||||||||||||
|
CO2
marketing transportation costs
|
5,365 | 4,842 | 3,649 | 2,799 | 355 | |||||||||||||||
|
General
and administrative expenses
|
25,920 | 13,573 | 9,656 | 11,031 | 8,768 | |||||||||||||||
|
Depreciation
and amortization
|
38,747 | 7,963 | 6,721 | 7,298 | 4,641 | |||||||||||||||
|
Loss
(gain) from sales of surplus assets
|
266 | (16 | ) | (479 | ) | 33 | (236 | ) | ||||||||||||
|
Impairment
Expense (3)
|
1,498 | - | - | - | - | |||||||||||||||
|
Total
costs and expenses
|
1,205,028 | 909,785 | 1,073,519 | 927,166 | 657,330 | |||||||||||||||
|
Operating
(loss) income from continuing operations
|
(5,375 | ) | 8,584 | 5,220 | (23 | ) | 567 | |||||||||||||
|
Earnings
from equity in joint ventures
|
1,270 | 1,131 | 501 | - | - | |||||||||||||||
|
Interest
expense, net
|
(10,100 | ) | (1,374 | ) | (2,032 | ) | (926 | ) | (986 | ) | ||||||||||
|
(Loss)
income from continuing operations before cumulative effect of change in
accounting principle, income taxes and minority interest
|
(14,205 | ) | 8,341 | 3,689 | (949 | ) | (419 | ) | ||||||||||||
|
Income
tax benefit
|
654 | 11 | - | - | - | |||||||||||||||
|
Minority
interest
|
1 | (1 | ) | - | - | - | ||||||||||||||
|
(Loss)
income from continuing operations before cumulative effect of change in
accounting principle
|
(13,550 | ) | 8,351 | 3,689 | (949 | ) | (419 | ) | ||||||||||||
|
(Loss)
income from discontinued operations
|
- | - | 312 | (463 | ) | 13,741 | ||||||||||||||
|
Cumulative
effect of changes in accounting principle
|
- | 30 | (586 | ) | - | - | ||||||||||||||
|
Net
(loss) income
|
$ | (13,550 | ) | $ | 8,381 | $ | 3,415 | $ | (1,412 | ) | $ | 13,322 | ||||||||
|
Net
(loss) income per common unit - basic and diluted:
|
||||||||||||||||||||
|
Continuing
operations
|
$ | (0.64 | ) | $ | 0.59 | $ | 0.38 | $ | (0.10 | ) | $ | (0.05 | ) | |||||||
|
Discontinued
operations
|
- | - | 0.03 | (0.05 | ) | 1.55 | ||||||||||||||
|
Cumulative
effect of change in accounting principle
|
- | - | (0.06 | ) | - | - | ||||||||||||||
|
Net
(loss) income
|
$ | (0.64 | ) | $ | 0.59 | $ | 0.35 | $ | (0.15 | ) | $ | 1.50 | ||||||||
|
Cash
distributions per common unit
|
$ | 0.93 | $ | 0.74 | $ | 0.61 | $ | 0.60 | $ | 0.15 | ||||||||||
|
Year
Ended December 31,
|
||||||||||||||||||||
|
2007
(1)
|
2006
|
2005
|
2004
|
2003
|
||||||||||||||||
|
Balance
Sheet Data (at end of period):
|
||||||||||||||||||||
|
Current
assets
|
$ | 214,240 | $ | 99,992 | $ | 90,449 | $ | 77,396 | $ | 88,211 | ||||||||||
|
Total
assets
|
908,523 | 191,087 | 181,777 | 143,154 | 147,115 | |||||||||||||||
|
Long-term
liabilities
|
101,351 | 8,991 | 955 | 15,460 | 7,000 | |||||||||||||||
|
Minority
interests
|
570 | 522 | 522 | 517 | 517 | |||||||||||||||
|
Partners'
capital
|
631,804 | 85,662 | 87,689 | 45,239 | 52,354 | |||||||||||||||
|
Other
Data:
|
||||||||||||||||||||
|
Maintenance
capital expenditures (4)
|
3,840 | 967 | 1,543 | 939 | 4,178 | |||||||||||||||
|
Volumes
- continuing operations:
|
||||||||||||||||||||
|
Crude
oil pipeline (bpd)
|
59,335 | 61,585 | 61,296 | 63,441 | 66,959 | |||||||||||||||
|
Crude
oil wellhead (bpd)
|
30,363 | 33,853 | 39,194 | 45,919 | 45,015 | |||||||||||||||
|
CO2
sales (Mcf per day)
|
77,309 | 72,841 | 56,823 | 45,312 | 36,332 | |||||||||||||||
|
(1)
|
Our operating
results and financial position have been affected by acquisitions in 2007,
most notably the Davison acquisition, which was completed on July 25,
2007. The aggregate value of the total consideration we paid or issued to
complete the Davison acquisition was approximately
$623 million. The operating results of the acquired
Davison entities are included in our financial results prospectively from
the acquisition date. For additional information regarding the Davison
acquisition, see Note 3 of the Notes to Consolidated Financial Statements
included under Item 8 of this annual
report.
|
|
(2)
|
Supply
and logistics revenues, costs and crude oil wellhead volumes are reflected
net of buy/sell arrangements since April 1,
2006.
|
|
(3)
|
In
2007, we recorded an impairment charge of $1.5 million related to our
natural gas pipeline assets.
|
|
(4)
|
Maintenance
capital expenditures are capital expenditures to replace or enhance
partially or fully depreciated assets to sustain the existing operating
capacity or efficiency of our assets and extend their useful
lives.
|
|
(5)
|
Represents
average daily volume for the two month period in 2003 that we owned the
assets.
|
The table
below summarizes our unaudited quarterly financial data for 2007 and 2006 (in
thousands, except per unit data).
|
2007
Quarters
|
||||||||||||||||
|
First
|
Second
|
Third
|
Fourth
|
|||||||||||||
|
Revenues
|
$ | 183,564 | $ | 201,016 | $ | 354,270 | $ | 460,803 | ||||||||
|
Operating
income (loss)
|
$ | 1,580 | $ | (1,319 | ) | $ | 7,043 | $ | (12,679 | ) | ||||||
|
Income
(loss) from continuing operations
|
$ | 1,585 | $ | (1,372 | ) | $ | 1,699 | $ | (15,462 | ) | ||||||
|
Net
income (loss)
|
$ | 1,585 | $ | (1,372 | ) | $ | 1,699 | $ | (15,462 | ) | ||||||
|
Income
(loss) from continuing operations per common unit - basic and
diluted
|
$ | 0.11 | $ | (0.09 | ) | $ | 0.07 | $ | (0.49 | ) | ||||||
|
Net
income (loss) per common unit - basic and diluted
|
$ | 0.11 | $ | (0.09 | ) | $ | 0.07 | $ | (0.49 | ) | ||||||
|
2006
Quarters
|
||||||||||||||||
|
First
|
Second
|
Third
|
Fourth
|
|||||||||||||
|
Revenues
|
$ | 263,602 | $ | 233,343 | $ | 229,551 | $ | 191,873 | ||||||||
|
Operating
income
|
$ | 2,370 | $ | 3,357 | $ | 1,688 | $ | 1,169 | ||||||||
|
Income
from continuing operations
|
$ | 2,561 | $ | 3,444 | $ | 1,695 | $ | 651 | ||||||||
|
Cumulative
effect adjustment
|
$ | 30 | $ | - | $ | - | $ | - | ||||||||
|
Net
income
|
$ | 2,591 | $ | 3,444 | $ | 1,695 | $ | 651 | ||||||||
|
Income
from continuing operations per common unit - basic and
diluted
|
$ | 0.18 | $ | 0.24 | $ | 0.12 | $ | 0.05 | ||||||||
Item
7. Management’s Discussion and Analysis of Financial
Condition and Results of Operation
Included
in Management’s Discussion and Analysis are the following sections:
|
|
·
|
Overview
of 2007
|
|
|
·
|
Significant
Events
|
|
|
·
|
Capital
Resources and Liquidity
|
|
|
·
|
Commitments
and Off-Balance Sheet Arrangements
|
|
|
·
|
Results
of Operations
|
|
|
·
|
Critical
Accounting Policies and Estimates
|
|
|
·
|
Recent
Accounting Pronouncements
|
In the
discussions that follow, we will focus on two measures that we use to manage the
business and to review the results of our operations. Those two
measures are segment margin and Available Cash before Reserves. Our
profitability depends to a significant extent upon our ability to maximize
segment margin. Segment margin is revenues less cost of sales and
operating expenses (excluding depreciation and amortization) plus our equity in
the operating income of joint ventures. 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. A reconciliation of segment
margin to income from continuing operations is included in our segment
disclosures in Note 12 to the consolidated financial statements.
Available
Cash before Reserves is a non-GAAP measure is net income as adjusted for
specific items, the most significant of which are the elimination of gains and
losses on asset sales (except those from the sale of surplus assets) the
addition of non-cash expenses (such as depreciation), the substitution of cash
generated by our joint ventures in lieu of our equity income attributable to our
joint ventures, and the subtraction of maintenance capital expenditures, which
are expenditures that are necessary to sustain existing (but not to provide new
sources of) cash flows. For additional information on Available
Cash before Reserves and a reconciliation of this measure to cash flows from
operations, see “Liquidity and Capital Resources - Non-GAAP Financial Measure”
below.
Overview
of 2007
The
year 2007 was a significant year for us. We acquired five
energy-related businesses from the Davison family of Ruston, Louisiana and a
crude oil terminal on the Mississippi River from BP Pipelines North America
Inc. To finance our acquisitions and other activities, we increased
the size of our revolving credit facility to $500 million (from $125 million)
and issued 24,468,823 common units, including 13,459,209 units to the Davisons
and 9,200,000 units in a public offering. We used the proceeds from
our public offering to temporarily reduce the balance on our revolving credit
facility, which had $80 million outstanding as of December 31,
2007.
We also
are negotiating with Denbury several potential “drop-down” transactions
involving midstream assets with an aggregate value of approximately $250
million.
Increases
in cash flow generally result in increases in Available Cash before Reserves,
which we distribute quarterly to holders of our common units and our general
partner. During 2007, we generated $28.2 million of Available Cash
before Reserves, and we distributed $17.2 million to holders of our common units
and general partner. Cash provided by operating activities in 2007
was $33.9 million.
In 2007,
we reported a net loss of $13.6 million, or $0.64 per common unit, resulting
primarily from non-cash depreciation and amortization of the assets acquired in
the Davison transaction totaling $30.1 million. See additional
discussion of our depreciation and amortization expense in “Results of
Operations – Other Costs and Interest” below.
Additionally,
on January 28, 2008, we declared that our distribution to our common unitholders
relative to the fourth quarter of 2007 would be $0.285 per unit (paid in
February 2008), which is an increase of 5.6% relative to the distribution for
the third quarter of 2007. That distribution amount represents
a 36% increase from our distribution of $0.21 per unit for the fourth quarter of
2006. During the fourth quarter of 2007 we paid a distribution of
$0.27 per unit related to the third quarter of 2007. Our total
distributions attributable to 2007 increased 29% over the total distributions
attributable to 2006.
We manage
our business through four divisions, which constitute our reportable segments –
pipeline transportation (primarily of crude oil), refinery services, industrial
gases and supply and logistics (crude oil, petroleum products, terminaling, and
truck transportation).
Significant
Events
Davison
Businesses Acquisition
On July
25, 2007, we acquired substantially all of the operating assets of five energy-
related businesses from entities owned and controlled by the Davison family of
Ruston, Louisiana. The businesses that we acquired from the Davison
family include refinery services, petroleum products marketing, terminaling,
trucking, and fuel procurement. Additional information on those
operations is included in “Item 1. Business” above.
For
financial reporting purposes, the total consideration for the transaction was
$623 million, comprised of common units and cash. In that
transaction, we issued 13,459,209 of our common units, which were contractually
valued at $20.8036 per unit. The units issued are reflected in our
consolidated balance sheet at a total value of $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 terms of the acquisition were agreed to and
announced. The remainder of the net purchase price of $293 million (adjusted for
purchase price adjustments), along with working capital of an additional $32.5
million (excluding cash acquired), was paid with cash borrowed under our credit
facility.
Additionally,
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 a result of that
purchase, our general partner continued to hold 7.4% of our outstanding common
units. As required under our partnership agreement, our general
partner also contributed approximately $6.2 million to maintain its two percent
general partner capital account balance.
Pursuant
to a unitholder agreement 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, 2007, the Davison unitholders held
approximately 33% 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.
Our
operational results for the year ended December 31, 2007, include five months of
activity from the Davison acquisition. We have included pro forma
information in Note 3 of the Notes to the Consolidated Financial Statements for
the year ended December 31, 2007 as if this transaction had occurred January 1,
2007.
Credit
Agreement Amendment
In
connection with our acquisition from the Davison family, we also amended our
credit facility. That amendment increased the committed amount under
our facility from $125 million to $500 million, of which a maximum of $100
million may be used for letters of credit. The committed amount
represents the amount the banks have committed to fund pursuant to the terms of
the credit agreement.
December
2007 Equity Offering
On
December 10, 2007, we received $194 million in proceeds (net to us after
expenses) from a public offering of 9,200,000 common units. We also
received $15.5 million from our general partner for its purchase of 734,732
common units to maintain its 7.4% proportionate share of our outstanding common
units and $4.4 million to maintain its two percent general partner capital
account balance. We used the net proceeds from the offering to repay
outstanding borrowings under our credit facility.
Port
Hudson Assets Acquisition
Effective
July 1, 2007, we acquired the Port Hudson Crude Oil truck terminal, marine
terminal, and marine dock of BP Pipelines (North America) Inc. for $8.1
million. The assets acquired in that transaction include docking
facilities on the Mississippi River, 215,000 barrels of tankage, a pipeline and
other related assets in East Baton Rouge Parish,
Louisiana. That acquisition was funded with borrowings under
our credit facility. We allocated $4.1 million of the purchase price
to the tangible assets we acquired and $4.0 million to goodwill. The
assets we acquired in that transaction should provide us with the increased
ability to gather, blend and store crude oil from south Louisiana for delivery
to markets that can be reached by barge from the Mississippi
River.
Drop-down
Transactions
As a
result of our acquisition from the Davisons, we anticipate that during the first
quarter of 2008, Denbury will enter into “drop-down” transactions with us
involving two of their existing CO2 pipelines
- the NEJD and Free State CO2
pipelines. We have reached substantial agreement and are in the process of
finalizing the business issues with Denbury and the lenders in our credit
facility as to the terms of such drop-downs by Denbury and the terms of a
long-term transportation service arrangement for the Free State line and a
20-year financing lease for the NEJD system. We expect to pay for these pipeline
assets with $225 million in cash and $25 million of our common units based on
the average closing price of our units for the thirty trading days prior to the
closing of the transaction. We expect to receive approximately $30 million per
annum, in the aggregate, under the lease and the transportation services
agreement (and a lesser pro-rated amount for 2008), with future payments for the
NEJD pipeline fixed at $20.7 million per year during the term of the financing
lease, and the payments relating to the Free State pipeline dependant on the
volumes of CO2
transported therein. While the business terms of the transactions and associated
documentation have been substantially completed, closing remains subject to
completion of closing documentation, receipt of a fairness opinion and approval
by the audit committee and the board of directors of our general
partner.
Liquidity
and Capital Resources
Capital
Resources/Sources of Cash
In the
last eighteen months, we have adopted a growth strategy that has dramatically
increased our cash requirements. We now expect our capital resources
to include equity and debt offerings (public and private) and other financing
transactions, in addition to cash generated from our operations. Accordingly, we
expect to access the capital markets (equity and debt) from time to time to
partially refinance our capital structure and to fund other needs including
acquisitions and ongoing working capital needs. Our ability to
satisfy future capital needs will depend on our ability to raise substantial
amounts of additional capital, to utilize our current credit facility and to
implement our growth strategy successfully. No assurance can be made that we
will be able to raise the necessary funds on satisfactory terms. If
we are unable to raise the necessary funds, we may be required to defer our
growth plans until such time as funds become available.
In
November 2006, we entered into a credit facility with a maximum facility amount
of $500 million (replacing our $100 million facility). A maximum of $100 million
may be used for letters of credit. The borrowing base under the
facility at December 31, 2007 was approximately $356 million, and is
recalculated quarterly and at the time of acquisitions. The borrowing
base represents the amount that can be borrowed or utilized for letters of
credit based on our EBITDA, computed in accordance with the provisions of our
credit facility.
The terms
of our credit facility also effectively limit the amount of distributions that
we may pay to our general partner and holders of common units. Such
distributions may not exceed the sum of the distributable cash generated for the
eight most recent quarters, less the sum of the distributions made with respect
to those quarters. See Note 10 of the Notes to the Consolidated Financial
Statements for additional information on our credit facility.
Uses
of Cash
Our cash
requirements include funding day-to-day operations, maintenance and expansion
capital projects, debt service, refinancings and distributions on our common
units and other equity interests. We expect to use cash flows from
operating activities to fund cash distributions and maintenance capital
expenditures needed to sustain existing operations. Future expansion
capital – acquisitions or capital projects – will require funding through
various financing arrangements, as more particularly described under “Liquidity
and Capital Resources – Capital Resources/Sources of Cash” above.
Operating. Our
operating cash flows are affected significantly by changes in items of working
capital. We have had situations where other parties have prepaid for
purchases or paid more than was due, resulting in fluctuations in one period as
compared to the next until the party recovers the excess payment. The
timing of capital expenditures and the related effect on our recorded
liabilities also affects operating cash flows.
The
majority of the accounts receivable amount on our consolidated balance sheets
relate to our crude oil operations. These accounts receivable settle
monthly and collection delays generally relate only to discrepancies or disputes
as to the appropriate price, volume or quality of crude oil
delivered. Accounts receivable in our fuel procurement business also
settle within 30 days of delivery. Over 75% of our $180.1 million
aggregate receivables on our consolidated balance sheet at December 31, 2007
relate to our crude oil and fuel procurement businesses.
Investing. We
utilized cash flows to make acquisitions and for capital
expenditures. The most significant investing activities in 2007 have
been the Davison acquisition for which we expended $301.6 million in cash as
consideration and for related acquisition costs. We also paid $8.1
million for our acquisition of the Port Hudson assets. We paid $8.2
million for capital expenditures. We received distributions from our
T&P Syngas joint venture that exceeded our share of the earnings of T&P
Syngas of $0.4 million during 2007.
During
2006, we utilized cash flows in investing activities by acquiring a 50% interest
in Sandhill for $5.0 million. We expended $2.3 million for other
investments and capital improvements. Offsetting those expenditures
was the receipt of returns of our investment in T&P Syngas in the form of
distributions totaling $0.5 million.
We
utilized cash flows in investing activities in 2005 by making a $13.4 million
investment in T&P Syngas, acquiring a CO2 contract
for $14.4 million and making investments in property and equipment of $6.1
million, including $3.1 million for the natural gas gathering assets acquired
from Multifuels. Offsetting these expenditures was the receipt of
$1.6 million for the sale of idle assets. We also received returns of
our investment in T&P Syngas in the form of distributions totaling $0.4
million.
Financing. Our
financing activities provided net cash of $297.0 million. Our net
borrowings under our credit facility were $72.0 million. In an offering in
December 2007, we sold 9,200,000 common units to the public and received $193.6
million, net of offering costs. We received $37.9 million from our
general partner for 1,809,614 common units it acquired as part of the Davison
acquisition and the common unit offering in December 2007 in order to maintain
its 7.4% limited partner interest. Our general partner also
contributed $10.6 million during 2007 as required under our partnership
agreement to maintain its two percent general partner capital account balance
and $1.4 million to offset the costs of a portion of the severance payment to an
executive. In connection with the increase in the committed amount of
our credit facility, we incurred credit facility fees of $2.3
million. We paid distributions totaling $17.2 million to our limited
partners and our general partner during 2007, and received $0.9 million on other
financing activities.
In 2006,
we utilized net cash of $5.2 million in financing activities. We paid
distributions totaling $10.4 million to our limited partners and our general
partner during the year. We borrowed $8.0 million under our credit
facility, and paid $2.7 million in legal and bank fees in November 2006 to
obtain our new credit facility.
In 2005,
financing activities provided net cash of $23.3 million. We issued
4,140,000 new limited partner units to the public and 330,630 new limited
partner units to our general partner. Additionally, our general
partner contributed funds to maintain its 2% general partner
interest. In total these activities provided $44.8 million to
us. A portion of these funds were utilized to eliminate our bank
debt, and we also paid distributions totaling $5.8 million to our
partners.
Capital
Expenditures and Business Acquisitions
A summary
of our expenditures for fixed assets and businesses in the three years ended
December 31, 2007, 2006, and 2005 is as follows:
|
Years
Ended December 31,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Capital
expenditures for business combinations and asset
purchases:
|
||||||||||||
|
Davison
acquisition:
|
||||||||||||
|
Cash
payments to Davison
|
$ | 314,227 | - | - | ||||||||
|
Transaction
fees and other direct costs
|
8,915 | - | - | |||||||||
|
Cash
received from Davison
|
(21,686 | ) | - | - | ||||||||
|
Net
cash payments
|
301,456 | - | - | |||||||||
|
Value
of non-cash consideration issued or granted
|
330,020 | - | - | |||||||||
|
Total
Davison acquisition consideration
|
631,476 | - | - | |||||||||
|
Port
Hudson acquisition
|
8,103 | - | - | |||||||||
|
CO2
contracts
|
- | - | 14,446 | |||||||||
|
Natural
gas gathering assets
|
- | - | 3,110 | |||||||||
|
Total
|
639,579 | - | 17,556 | |||||||||
|
Capital
expenditures for property, plant and equipment:
|
||||||||||||
|
Maintenance
capital expenditures:
|
||||||||||||
|
Pipeline
transportation assets
|
2,880 | 611 | 1,256 | |||||||||
|
Supply
and logistics assets
|
440 | 175 | 34 | |||||||||
|
Refinery
services assets
|
469 | - | - | |||||||||
|
Administrative
and other assets
|
51 | 181 | 253 | |||||||||
|
Total
maintenance capital expenditures
|
3,840 | 967 | 1,543 | |||||||||
|
Growth
capital expenditures:
|
||||||||||||
|
Pipeline
transportation assets
|
3,712 | 360 | 1,059 | |||||||||
|
Supply
and logistics assets
|
650 | - | 260 | |||||||||
|
Refinery
services assets
|
979 | - | - | |||||||||
|
Total
growth capital expenditures
|
5,341 | 360 | 1,319 | |||||||||
|
Total
|
9,181 | 1,327 | 2,862 | |||||||||
|
Capital
expenditures attributable to unconsolidated affiliates:
|
||||||||||||
|
T&P
Syngas investment
|
- | - | 13,418 | |||||||||
|
Sandhill
investment
|
- | 5,042 | - | |||||||||
|
Faustina
project
|
1,104 | 1,016 | - | |||||||||
|
Total
|
1,104 | 6,058 | 13,418 | |||||||||
|
Total
capital expenditures
|
$ | 649,864 | $ | 7,385 | $ | 33,836 | ||||||
During
2008, we expect to expend approximately $6.1 million for maintenance capital
projects in progress or planned. Those expenditures are expected to
include approximately $3.3 million of improvements in our refinery services
business, $0.6 million in our crude oil pipeline operations, $1.5 million
related to the relocation of our headquarters office when our existing lease
ends in October 2008 and the remainder on projects related to our truck
transportation and information technology areas. Most of our truck
fleet is less than two years old, so we do not anticipate making any significant
expenditures for vehicles in 2008; however, in future years we expect to spend
$4 million to $5 million per year on vehicle replacements. Based on
the information available to us at this time, we do not anticipate that future
capital expenditures for compliance with regulatory requirements will be
material.
We have
started construction of an expansion of our existing Jay System that will extend
the pipeline to producers operating in southern Alabama. That
expansion will consist of approximately 33 miles of pipeline and gathering
connections to approximately 30 wells and will include storage capacity of
20,000 barrels. We expect to spend a total of approximately $9.9
million on this project in 2008. Our refinery services segment
expects to expend approximately $3.9 million on projects currently in progress
to expand its operations in 2008 to two additional refineries.
As
discussed above in “Significant Events”, we are currently in the process of
finalizing drop down transactions with Denbury related to two of its CO2 pipelines
that are expected to occur in the first quarter of 2008.
Expenditures
for capital assets to grow the partnership distribution will depend on our
access to debt and equity capital discussed above in “Capital Resources -- Sources of
Cash.” We will look for opportunities to acquire assets from
other parties that meet our criteria for stable cash flows. The
arrangement that Denbury has made with our new senior executive management team
provide incentives to them to make such acquisitions. See “Item 11.
Executive Compensation” for a description of these arrangements.
Distributions
Our
partnership agreement requires us to distribute 100% of our available cash (as
defined therein) within 45 days after the end of each quarter to unitholders of
record and to our general partner. Available cash consists generally
of all of our cash receipts less cash disbursements adjusted for net changes to
reserves. We have increased our distribution for each of the last
nine quarters, including the distribution paid for the fourth quarter of 2007,
as shown in the table below (in thousands, except per unit amounts)
|
General
|
||||||||||||||||||||||
|
Limited
|
General
|
Partner
|
||||||||||||||||||||
|
Partner
|
Partner
|
Incentive
|
||||||||||||||||||||
|
Per
Unit
|
Interests
|
Interest
|
Distribution
|
Total
|
||||||||||||||||||
|
Distribution
For
|
Date
Paid
|
Amount
|
Amount
|
Amount
|
Amount
|
Amount
|
||||||||||||||||
|
Fourth
quarter 2005
|
February
2006
|
$ | 0.170 | $ | 2,343 | $ | 48 | $ | - | $ | 2,391 | |||||||||||
|
First
quarter 2006
|
May
2006
|
$ | 0.180 | $ | 2,481 | $ | 51 | $ | - | $ | 2,532 | |||||||||||
|
Second
quarter 2006
|
August
2006
|
$ | 0.190 | $ | 2,619 | $ | 53 | $ | - | $ | 2,672 | |||||||||||
|
Third
quarter 2006
|
November
2006
|
$ | 0.200 | $ | 2,757 | $ | 56 | $ | - | $ | 2,813 | |||||||||||
|
Fourth
quarter 2006
|
February
2007
|
$ | 0.210 | $ | 2,895 | $ | 59 | $ | - | $ | 2,954 | |||||||||||
|
First
quarter 2007
|
May
2007
|
$ | 0.220 | $ | 3,032 | $ | 62 | $ | - | $ | 3,094 | |||||||||||
|
Second
quarter 2007
|
August
2007
|
$ | 0.230 | $ | 3,170 | (1) | $ | 65 | $ | - | $ | 3,235 | (1) | |||||||||
|
Third
quarter 2007
|
November
2007
|
$ | 0.270 | $ | 7,646 | $ | 156 | $ | 90 | $ | 7,892 | (2) | ||||||||||
|
Fourth
quarter 2007
|
February
2008
|
$ | 0.285 | $ | 10,902 | $ | 222 | $ | 245 | $ | 11,369 | (3) | ||||||||||
(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.
(2) The
increased amount of distributions that were paid is primarily a result of the
additional units issued in connection with the Davison acquisition in July 2007
and the offering of common units in December 2007 as discussed
above.
(3) This
distribution was paid on February 14, 2008 to our general partner and
unitholders of record as of February 7, 2008.
Our
credit facility also includes a restriction on the amount of distributions we
can pay in any quarter. At December 31, 2007, our restricted net
assets (as defined in Rule 4-03 (e)(3) of Regulation S-X) were $593.7
million.
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, our general partner is entitled to receive 13.3% of any
distributions to our common unitholders in excess of $0.25 per unit, 23.5% of
any distributions to our common unitholders in excess of $0.28 per unit, and 49%
of any distributions to our common unitholders in excess of $0.33 per unit,
without duplication. The likelihood and timing of the payment of any
incentive distributions will depend on our ability to increase the cash flow
from our existing operations and to make accretive acquisitions. In
addition, our partnership agreement authorizes us to issue additional equity
interests in our partnership with such rights, powers and preferences (which may
be senior to our common units) as our general partner may determine in its sole
discretion, including with respect to the right to share in distributions and
profits and losses of the partnership.
Available
Cash before Reserves for the year ended December 31, 2007 is as follows (in
thousands):
|
Net
loss
|
$ | (13,550 | ) | |
|
Depreciation,
amortization, and impairment expense
|
40,245 | |||
|
Cash
received from direct financing leases not included in
income
|
568 | |||
|
Cash
effects of sales of certain assets
|
195 | |||
|
Effects
of available cash generated by investments in joint ventures not included
in income
|
975 | |||
|
Denbury
contribution toward executive severance
|
1,412 | |||
|
Cash
effects of stock appreciation rights plan
|
(1,614 | ) | ||
|
Non-cash
charges
|
3,788 | |||
|
Maintenance
capital expenditures
|
(3,840 | ) | ||
|
Available
Cash before Reserves
|
$ | 28,179 |
We have
reconciled Available Cash before Reserves (a non-GAAP measure) to cash flow from
operating activities (the GAAP measure) for the year ended December 31, 2007
below. For the year ended December 31, 2007, cash flow provided by
operating activities was $33.9 million.
Non-GAAP
Financial Measure
This
annual report includes the financial measure of Available Cash before Reserves,
which is a “non-GAAP” measure because it is not contemplated by or referenced in
accounting principles generally accepted in the U.S., also referred to as
GAAP. The accompanying schedule provides a reconciliation of this
non-GAAP financial measure to its most directly comparable GAAP financial
measure. Our non-GAAP financial measure should not be considered as
an alternative to GAAP measures such as net income, operating income, cash flow
from operating activities or any other GAAP measure of liquidity or financial
performance. We believe that investors benefit from having access to
the same financial measures being utilized by management, lenders, analysts and
other market participants.
Available
Cash before Reserves, also referred to as distributable cash flow, is commonly
used as a supplemental financial measure by management and by external users of
financial statements, such as investors, commercial banks, research analysts and
rating agencies, to assess: (1) the financial performance of our assets without
regard to financing methods, capital structures or historical cost basis; (2)
the ability of our assets to generate cash sufficient to pay interest cost and
support our indebtedness; (3) our operating performance and return on capital as
compared to those of other companies in the midstream energy industry, without
regard to financing and capital structure; and (4) the viability of projects and
the overall rates of return on alternative investment
opportunities. Because Available Cash before Reserves excludes some,
but not all, items that affect net income or loss and because these measures may
vary among other companies, the Available Cash before Reserves data presented in
this Annual Report on Form 10-K may not be comparable to similarly titled
measures of other companies. The GAAP measure most directly
comparable to Available Cash before Reserves is net cash provided by operating
activities.
Available
Cash before Reserves is a liquidity measure used by our management to compare
cash flows generated by us to the cash distribution paid to our limited partners
and general partner. This is an important financial measure to our
public unitholders since it is an indicator of our ability to provide a cash
return on their investment. Specifically, this financial measure aids
investors in determining whether or not we are generating cash flows at a level
that can support a quarterly cash distribution to the
partners. Lastly, Available Cash before Reserves (also referred to as
distributable cash flow) is the quantitative standard used throughout the
investment community with respect to publicly-traded
partnerships.
The
reconciliation of Available Cash before Reserves (a non-GAAP measure) to cash
flow from operating activities (the GAAP measure) for the year ended December
31, 2007, is as follows (in thousands):
|
Cash
flows from operating activities
|
$ | 33,929 | ||
|
Adjustments
to reconcile operating cash flows to Available Cash:
|
||||
|
Maintenance
capital expenditures
|
(3,840 | ) | ||
|
Proceeds
from sales of certain assets
|
195 | |||
|
Amortization
and write-off of credit facility issuance fees
|
(779 | ) | ||
|
Effects
of available cash generated by investments in joint ventures not included
in cash flows from operating activities
|
400 | |||
|
Denbury
contribution toward executive severance
|
1,412 | |||
|
Other
items affecting Available Cash
|
142 | |||
|
Net
effect of changes in operating accounts not included in calculation of
Available Cash
|
(3,280 | ) | ||
|
Available
Cash before Reserves
|
$ | 28,179 |
Commitments
and Off-Balance Sheet Arrangements
Contractual
Obligation and Commercial Commitments
In
addition to our credit facility discussed above, we have contractual obligations
under operating leases as well as commitments to purchase crude
oil. The table below summarizes our obligations and commitments at
December 31, 2007.
|
Payments
Due by Period
|
||||||||||||||||||||
|
Commercial
Cash Obligations and Commitments
|
Less
than one year
|
1 -
3 years
|
3 -
5 Years
|
More
than 5 years
|
Total
|
|||||||||||||||
|
Contractual
Obligations:
|
||||||||||||||||||||
|
Long-term
debt (1)
|
$ | - | $ | - | $ | 80,000 | $ | - | $ | 80,000 | ||||||||||
|
Estimated
interest payable on long-term debt (2)
|
6,819 | 13,600 | 5,924 | - | 26,343 | |||||||||||||||
|
Operating
lease obligations
|
6,885 | 7,166 | 3,563 | 10,779 | 28,393 | |||||||||||||||
|
Capital
expansion projects (3)
|
6,751 | - | - | - | 6,751 | |||||||||||||||
|
Additional
investment in the Faustina Project (4)
|
763 | - | - | - | 763 | |||||||||||||||
|
Unconditional
purchase obligations (5)
|
183,927 | 29,072 | 4,097 | - | 217,096 | |||||||||||||||
|
Other
Cash Commitments:
|
||||||||||||||||||||
|
Asset
retirement obligations (6)
|
100 | 3,771 | 3,871 | |||||||||||||||||
|
FIN
48 tax liabilities (7)
|
1,168 | 1,168 | ||||||||||||||||||
|
Total
|
$ | 205,245 | $ | 49,838 | $ | 93,584 | $ | 15,718 | $ | 364,385 | ||||||||||
|
(1)
|
Our
credit facility allows us to repay and re-borrow funds at any time through
the maturity date of November 15,
2011.
|
|
(2)
|
Interest
on our long-term debt is at market-based rates. The amount shown for
interest payments represents the amount that would be paid if the debt
outstanding at December 31, 2007 remained outstanding through the final
maturity date of November 15, 2011 and interest rates remained at the
December 31, 2007 market levels through November 15,
2011.
|
|
(3)
|
We
have signed commitments to expand our Jay System and to construct sour gas
processing facilities at an additional refinery in Utah. See
“Capital Expenditures and Business Acquisitions” under “Liquidity and
Capital Resources – Uses of Cash”
above.
|
|
(4)
|
We
made an additional investment in the Faustina Project in January 2008 in
the amount of $0.8 million.
|
|
(5)
|
Unconditional
purchase obligations includes agreements to purchase goods and services
that are enforceable and legally binding and specify all significant
terms. Contracts to purchase crude oil and petroleum products
are generally at market-based prices. For purposes of this
table, estimated volumes and market prices at December 31, 2007, were used
to value those obligations. The actual physical volumes and
settlement prices may vary from the assumptions used in the
table. Uncertainties involved in these estimates include levels
of production at the wellhead, changes in market prices and other
conditions beyond our control.
|
|
(6)
|
Represents
the estimated future asset retirement obligations on an undiscounted
basis. The present discounted asset retirement obligation is
$1.2 million, as determined under FIN 47 and SFAS 143, and is further
discussed in Note 5 to the Consolidated Financial
Statements.
|
|
(7)
|
The
estimated FIN 48 tax liabilities will be settled as a result of expiring
statutes or audit activity. The timing of any particular settlement will
depend on the length of the tax audit and related appeals process, if any,
or an expiration of statute. If a liability is settled due to a statute
expiring or a favorable audit result, the settlement of the FIN 48 tax
liability would not result in a cash
payment.
|
In
additional to the contractual cash obligations included above, we also have a
contingent obligation related to our acquisition of a 50% interest in Sandhill,
which could require us to pay an additional $2 million for our
interest. See additional discussion in the section on Sandhill in
Note 8 to the consolidated financial statements.
We have
guaranteed 50% of the $3.9 million debt obligation to a bank of Sandhill;
however, we believe we are not likely to be required to perform under this
guarantee as Sandhill is expected to make all required payments under the debt
obligation. See additional discussion in the section on Sandhill in
Note 8 to the consolidated financial statements.
Off-Balance
Sheet Arrangements
We have
no off-balance sheet arrangements, special purpose entities, or financing
partnerships, other than as disclosed under Contractual Obligation and
Commercial Commitments above, nor do we have any debt or equity triggers
based upon our unit or commodity prices.
Results
of Operations
The
contribution of each of our segments to total segment margin in each of the last
three years was as follows:
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Pipeline
transportation
|
$ | 13,035 | $ | 12,426 | $ | 9,804 | ||||||
|
Refinery
services
|
21,898 | - | - | |||||||||
|
Industrial
gases
|
12,063 | 11,443 | 8,154 | |||||||||
|
Supply
and logistics
|
15,330 | 7,366 | 3,661 | |||||||||
|
Total
segment margin
|
$ | 62,326 | $ | 31,235 | $ | 21,619 | ||||||
Pipeline
Transportation Segment
We
operate three common carrier crude oil pipeline systems in a four state
area. We refer to these pipelines as our Mississippi System, Jay
System and Texas System. Volumes shipped on these systems for the
last three years are as follows (barrels per day):
|
Pipeline
System
|
2007
|
2006
|
2005
|
|||||||||
|
Mississippi
|
21,680 | 16,931 | 16,021 | |||||||||
|
Jay
|
13,309 | 13,351 | 13,725 | |||||||||
|
Texas
|
24,346 | 31,303 | 31,550 | |||||||||
The
Mississippi System begins in Soso, Mississippi and extends to Liberty,
Mississippi. At Liberty, shippers can transfer the crude oil to a
connection to Capline, a pipeline system that moves crude oil from the Gulf
Coast to refineries in the Midwest. The system has been improved to
handle the increased volumes produced by Denbury and transported on the
pipeline. In order to handle future increases in production volumes
in the area that are expected, we have made capital expenditures for tank,
station and pipeline improvements and we intend to make further improvements.
See “Capital Expenditures and
Business Acquisitions” under “Liquidity and Capital Resources – Uses of
Cash” above.
Denbury
is the largest producer (based on average barrels produced per day) of crude oil
in the State of Mississippi. Our Mississippi System is adjacent to several of
Denbury’s existing and prospective oil fields. As Denbury continues
to acquire and develop old oil fields using CO2 based
tertiary recovery operations, Denbury expects to add crude oil gathering and
CO2
supply infrastructure to those fields, which could create some
opportunities for us.
Beginning
in September 2004, Denbury became a shipper on the Mississippi System, under an
incentive tariff designed to encourage shippers to increase volumes shipped on
the pipeline. Prior to this point, Denbury sold its production to us
before it entered the pipeline.
In the
fourth quarter of 2004, we constructed two segments of crude oil pipeline to
connect producing fields operated by Denbury to our Mississippi
System. One of these segments was placed in service in 2004 and the
other began operations in the first quarter of 2005. Denbury pays us
a minimum payment each month for the right to use these pipeline
segments. We account for these arrangements as direct financing
leases.
The Jay
Pipeline system in Florida and Alabama ships crude oil from fields with
relatively short remaining production lives. Recent changes in the
ownership of the more mature producing fields in the area surrounding our Jay
System have led to interest in further development of these fields which may
lead to increases in production. Additionally, new wells have been
drilled in the area. This new production produces greater tariff
revenue for us due to the greater distance that the crude oil is transported on
the pipeline. This increased revenue, increases in tariff rates each
year on the remaining segments of the pipeline, sales of pipeline loss allowance
volumes, and operating efficiencies that have decreased operating costs have
contributed to increase our cash flows from the Jay System.
Volumes
on our Texas System averaged 24,346 barrels per day during 2007. The
crude oil that enters our system comes to us at West Columbia where we have a
connection to TEPPCO’s South Texas System and at Webster where we have
connections to two other pipelines. One of these connections at
Webster is with ExxonMobil Pipeline and is used to receive volumes that
originate from TEPPCO’s pipelines. We have a joint tariff with TEPPCO
under which we earn $0.31 per barrel on the majority of the barrels we deliver
to the shipper’s facilities. Substantially all of the volume being
shipped on our Texas System goes to two refineries on the Texas gulf
coast.
Our Texas
System is dependent on the connecting carriers for supply, and on the two
refineries for demand for our services. In 2003, we sold a portion of
our Texas System to TEPPCO. Since such sale, volumes on the Texas
System have declined as a result of changes in the supply available for the two
refineries to acquire and ship on our pipeline and changes TEPPCO made to the
operations of the pipeline segments. As we have consistently been
able to increase our pipeline tariffs as needed and due to the insignificance of
the Texas Systems’ net book value at December 31, 2007, we do not believe that
the decline in volumes will affect the recoverability of the net investment that
remains on the Texas System. We lease tankage in Webster on the Texas
System of approximately 165,000 barrels. We have a tank rental
reimbursement agreement effective January 1, 2005 with the primary shipper on
our Texas System to reimburse us for the expense of leasing of that storage
capacity. Volumes on the Texas System may continue to fluctuate as
refiners on the Texas Gulf Coast compete for crude oil with other markets
connected to TEPPCO’s pipeline systems.
We
operate a CO2 pipeline
in Mississippi to transport CO2 from
Denbury’s main CO2 pipeline
to Brookhaven oil field. Denbury has the exclusive right to use this
CO2
pipeline. This arrangement has been accounted for as a direct
financing lease.
Historically,
the largest operating costs in our crude oil pipeline segment have consisted of
personnel costs, power costs, maintenance costs and costs of compliance with
regulations. Some of these costs are not predictable, such as
failures of equipment, or are not within our control, like power cost
increases. We perform regular maintenance on our assets to keep them
in good operational condition and to minimize cost increases.
Operating
results from operations for our pipeline transportation segment were as
follows.
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Crude
oil tariffs and revenues from direct financing leases of crude oil
pipelines
|
$ | 14,906 | $ | 14,309 | $ | 13,490 | ||||||
|
Sales
of crude oil pipeline loss allowance volumes
|
6,875 | 6,472 | 4,672 | |||||||||
|
Revenues
from direct financing leases of CO2
pipelines
|
319 | 340 | 359 | |||||||||
|
Tank
rental reimbursements and other miscellaneous revenues
|
655 | 621 | 566 | |||||||||
|
Total
revenues from crude oil and CO2
tariffs, including revenues from direct financing leases
|
22,755 | 21,742 | 19,087 | |||||||||
|
Revenues
from natural gas tariffs and sales
|
4,456 | 8,205 | 9,801 | |||||||||
|
Natural
gas purchases
|
(4,122 | ) | (7,593 | ) | (9,343 | ) | ||||||
|
Pipeline
operating costs
|
(10,054 | ) | (9,928 | ) | (9,741 | ) | ||||||
|
Segment
margin
|
$ | 13,035 | $ | 12,426 | $ | 9,804 | ||||||
|
Volumes
per day:
|
||||||||||||
|
Crude
oil pipeline - barrels
|
59,335 | 61,585 | 61,296 | |||||||||
Year
Ended December 31, 2007 Compared with Year Ended December 31, 2006
Pipeline
segment margin increased $0.6 million, or 5%, for 2007, as compared to
2006. Revenues from crude oil and CO2 tariffs
and related sources were responsible for the increase for the
period. Net profit from natural gas transportation and sales
decreased slightly and pipeline operating costs increased, slightly offsetting
the increase from tariffs and other sources.
Tariff
revenues from transportation of crude oil and CO2 increased
$0.6 million in 2007 compared to the prior year period due primarily to
increased volumes on the Mississippi System of 4,749 barrels per day and tariff
increases on the Jay System. The tariff on the Mississippi System is
an incentive tariff, such that the average tariff per barrel decreases as the
volumes increase. However, because of the overall impact of an annual tariff
increase on July 1, 2007 and increased volume, our revenues improved. The
volumes on the Jay System were almost identical to the prior year period. As a
result of the annual tariff increase on July 1, 2007, average tariffs on the Jay
System increased by approximately $0.04 per barrel between the two periods.
Although volumes on the Texas System declined by 6,957 barrels per day, the
impact on revenues was not significant due to the relatively low tariffs on that
system. Approximately 74% of the volume on that system is shipped on a tariff of
$0.31 per barrel.
Higher
market prices for crude oil added $0.4 million to pipeline loss allowance
revenues. During 2007, average crude oil market prices, as referenced
by the prices posted by Shell Trading (US) Company for West Texas/New Mexico
Intermediate grade crude oil, were $6.2 higher than in
2006. Fluctuations in the future in crude oil market prices will
affect our revenues from sales of crude oil pipeline loss allowance
volumes. Tank rental reimbursements and other miscellaneous revenues
increased by $0.1 million.
Net
profit from natural gas pipeline activities decreased in total $0.3 million from
2006 amounts. The natural gas pipeline activities were negatively
impacted by production difficulties of a producer attached to the
system. Due to the declines we have experienced in the results from
our natural gas pipelines, we reviewed these assets to determine if the fair
market value of the assets exceeded the net book value of the
assets. As a result of this review, we recorded an impairment loss
related to these assets. See “Other Costs and Interest –
Depreciation, Amortization and Impairment” below.
Operating
costs increased $0.1 million. The increase in 2007 was due to higher
compensation costs of $0.2 million and an increase in costs related to our stock
appreciation right plan expense that relates to our pipeline operations
personnel of $0.1 million. These increases in costs were offset by a
decrease of $0.2 million related to pipeline lease fees and insurance related to
our pipeline operations.
Year
Ended December 31, 2006 Compared with Year Ended December 31, 2005
Pipeline
segment margin increased $2.6 million, or 27%, for 2006, as compared to
2005. Revenues from crude oil and CO2 tariffs
and related sources were responsible for the increase for the
period. Net profit from natural gas transportation and sales
increased slightly, with that increase offset by an increase in pipeline
operating costs.
Tariff
revenues from transportation of crude oil and CO2 increased
$0.8 million in 2006 compared to the prior year period due primarily to
increased tariffs on all systems. Additionally the receipt and
delivery points for the crude oil varied in 2006, with proportionately more
volume at locations with higher per barrel tariffs. Total volumes on
all three systems were consistent with 2005 volumes.
Higher
market prices for crude oil added $1.8 million to pipeline loss allowance
revenues. During 2006, average crude oil market prices, as referenced
by the prices posted by Shell Trading (US) Company for West Texas/New Mexico
Intermediate grade crude oil, were $9.71 higher than in
2005. Fluctuations in the future in crude oil market prices will
affect our revenues from sales of crude oil pipeline loss allowance
volumes. Tank rental reimbursements and other miscellaneous revenues
increased by $0.1 million.
Net
profit from natural gas pipeline activities increased in total $0.1 million from
2005 amounts. Fluctuations in natural gas market prices created
variances between the annual periods in revenues from natural gas sales and
costs of natural gas purchases.
Operating
costs increased $0.2 million. A decrease in 2006 in costs for
regulatory testing and repairs of $0.6 million was offset by increased power
costs of $0.2 million, increases in safety and insurance costs totaling $0.3
million and expense related to our stock appreciation rights (“SAR”) plan of
$0.3 million.
Refinery
Services Segment
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 proprietary 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. Some of the largest
customers for the NaHS are copper mining companies in the United States and
South America and paper mills.
Typically,
we receive 100% of the NaHS, as compensation for providing the sour gas
processing services. The largest cost component of providing the
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 involves 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. We estimate that approximately 65% of our NaHS
sales are indexed, in one form or another, to our cost of caustic
soda. 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.
Segment
margin from our refinery services for the five months we owned this business in
2007 was $21.9 million. On a pro forma basis, refinery services
segment margin would have been $50.8 million for 2007 and $44.7 million for
2006.
We
believe the most meaningful measure of our success in this segment is the
revenue generated from sales of NaHS after deducting delivery expenses, from
both the volumes received as payment for rendering service as well as volumes
obtained from third party producers.
|
Five
Months Ended
|
Pro
Forma Year
|
|||||||||||
|
December
31,
|
Ended
December 31,
|
|||||||||||
|
2007
|
2007
|
2006
|
||||||||||
|
NaHS
Sales
|
||||||||||||
|
Dry
Short Tons (DST)
|
69,853 | 164,059 | 159,952 | |||||||||
|
Net
Sales per DST
|
$ | 620 | $ | 591 | $ | 561 | ||||||
|
Contribution
Margin per DST
|
$ | 257 | $ | 260 | $ | 237 | ||||||
During
the five months that we owned this operation, sales of NaHS, measured in dry
short tons (DST) were 69,853 DST, or an average of 456 DST per
day. The average sales price of the NaHS, net of delivery expenses,
for the period was $620 per DST. Combining the historical results of
this operation for January through July 2007 with our results and comparing it
to the historical results of the predecessor for 2006 indicates that the average
sales price per DST of NaHS, net of delivery expenses, increased between 2006
and 2007 by 5%. The total DST sold between the periods, including the
sales of the predecessor for the first seven months of 2007, was 4,107 DST more
in 2007 than in 2006. As we expand our sour gas processing services
to additional refineries, we expect these NaHS sales volumes to continue to
increase. The increased worldwide demand for copper has contributed
to the increased demand for NaHS.
The
largest input to processing of the sour gas streams that result in NaHS is
NaOH. We also market NaOH and sulfidic NaOH not used for our
processing. During 2007, the average market price for NaOH was $425
per DST, an increase of 12% over the 2006 market price. We have
generally been successful in increasing the sales price for NaHS to compensate
for increases in NaOH prices and maintaining or expanding the contribution of
NaHS sales to our segment margin.
Industrial
Gases Segment
Our
industrial gases segment includes the results of our CO2 sales to
industrial customers and our share of the operating income of our 50% joint
venture interests in T&P Syngas and Sandhill.
CO2 –
Industrial Customers
We supply
CO2 to
industrial customers under seven long-term CO2 sales
contracts. We acquired those contracts, as well as the CO2 necessary
to satisfy substantially all of our expected obligations under those contracts,
in three separate transactions with Denbury. Since 2003, we have
purchased those contracts, along with three VPPs representing 280.0 Bcf of
CO2
(in the aggregate), from Denbury for a total of $43.1 million in
cash. We sell our CO2 to
customers who treat the CO2 and sell
it to end users for use for beverage carbonation and food chilling and freezing
or for uses in tertiary crude oil recovery or chemical processes. Our
compensation for supplying CO2 to our
industrial customers is the effective difference between the price at which we
sell our CO2 under each
contract and the price at which we acquired our CO2 pursuant
to our VPPs, minus transportation costs. We expect some seasonality
in our sales of CO2. The
dominant months for beverage carbonation and freezing food from April to
October, when warm weather increases demand for beverages and the approaching
holidays increase demand for frozen foods. At December 31, 2007, we
have 182.3 Bcf of CO2 remaining
under the VPPs.
The terms
of our contracts with the industrial CO2 customers
include minimum take-or-pay and maximum delivery volumes. The maximum daily
contract quantity per year in the contracts totals 97,625 Mcf. Under
the minimum take-or-pay volumes, the customers must purchase a total of 51,048
Mcf per day whether received or not. Any volume purchased under the
take-or-pay provision in any year can then be recovered in a future year as long
as the minimum requirement is met in that year. In the three years
ended December 31, 2007, all of our customers purchased more than their minimum
take-or-pay quantities.
Our seven
industrial contracts expire at various dates beginning in 2010 and extending
through 2023. The sales contracts contain provisions for adjustments
for inflation to sales prices based on the Producer Price Index, with a minimum
price.
Based on
historical data for 2004 through 2007, we expect some seasonality in our sales
of CO2. 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. The table below depicts
these seasonal fluctuations. The average daily sales (in Mcfs) of
CO2
for each quarter in 2007 and 2006 under these contracts were as
follows:
|
Quarter
|
2007
|
2006
|
||||||
|
First
|
67,158 | 66,565 | ||||||
|
Second
|
75,039 | 73,980 | ||||||
|
Third
|
85,705 | 82,244 | ||||||
|
Fourth
|
80,667 | 68,452 | ||||||
Syngas
We
recognize our share of the earnings of T&P Syngas in each
period. We are amortizing the excess of the price we paid for our
interest in T&P Syngas over our share of the equity of T&P Syngas over
the remaining useful life of the assets of T&P Syngas. This
excess of $4.0 million is being amortized over eleven years. We
receive cash distributions from T&P Syngas quarterly.
Sandhill
We
recognize our share of the earnings of Sandhill in each period. We
paid $3.8 million more for our interest in Sandhill than our share of the equity
on the balance sheet of Sandhill at the date of acquisition. This
excess of the purchase price over our share of the equity of Sandhill has been
allocated to the property and equipment and intangible assets based on the fair
value of those assets, with the remaining $0.7 million allocated to
goodwill. We are amortizing the amount allocated to property,
equipment and intangibles over the remaining useful lives of those
assets. The amount allocated to goodwill will be reviewed for
impairment periodically. We receive cash distributions from Sandhill
quarterly.
Operating
Results
Operating
results for our industrial gases segment were as follows.
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Revenues
from CO2
marketing
|
$ | 16,158 | $ | 15,154 | $ | 11,302 | ||||||
|
CO2
transportation and other costs
|
(5,365 | ) | (4,842 | ) | (3,649 | ) | ||||||
|
Equity
in earnings of joint ventures
|
1,270 | 1,131 | 501 | |||||||||
|
Segment
margin
|
$ | 12,063 | $ | 11,443 | $ | 8,154 | ||||||
|
Volumes
per day:
|
||||||||||||
|
CO2
marketing - Mcf (1)
|
77,309 | 72,841 | 56,823 | |||||||||
|
(1) 2005
volumes only include volumes sold by us.
|
||||||||||||
The
increasing margins from the industrial gases segment between 2007 and 2006 were
the result of an increase in volumes of 4,468 Mcf per day and an increase of 1%
in the average revenue per Mcf sold. Our margins from 2005 to 2006
increased primarily due to the acquisitions we made in 2005 and 2006 in this
segment. The average revenue per Mcf sold increased by 5% from 2005
to 2006, due to inflation adjustments in the contracts and variations in the
volumes sold under each contract.
Transportation
costs for the CO2 on
Denbury’s pipeline have increased due to the increased volume and the effect of
the annual inflation factor in the rate paid to Denbury. The average
rate per Mcf in 2007 increased 6% over the 2006 rate. The average
rate in 2006 increased 3% over the 2005 rate.
Our share
of the operating income of T&P Syngas for 2007, 2006 and for the nine month
period we owned it in 2005 was $1.6 million, $1.5 million and $0.8 million,
respectively. We reduced the amount we recorded as our equity in
T&P Syngas by $0.4 million in 2007 and 2006 and $0.3 million in 2005 as
amortization of the excess purchase price of T&P Syngas. During
2007, T&P Syngas paid us distributions totaling $2.0 million, and we
received a distribution of $0.6 million in 2008 attributable to the fourth
quarter of 2007. During 2006 and 2005 we received distributions
totaling $2.0 million and $0.8 million, respectively. Financial
statements for T&P Syngas are included as a Schedule to this Annual
Report.
Our share
of the operating income of Sandhill for 2007 and the nine month period we owned
it in 2006 was $0.3 million and $0.1 million, respectively. We
reduced these amounts by $0.3 million and $0.2 million for the amortization of
the excess of the purchase price of Sandhill, respectively. During
2007 and 2006, we received distributions from Sandhill totaling $0.3 million and
$0.1 million, respectively.
Supply
and Logistics Segment
Our
supply and logistics segment was previously known as our crude oil gathering and
marketing segment. With the acquisition of the Davison businesses, we
renamed the segment and included in it the petroleum products, fuel logistics,
terminaling and truck transportation activities we acquired from the
Davisons.
Our crude
oil gathering and marketing operations are concentrated in Texas, Louisiana,
Alabama, Florida, and Mississippi. Those operations, which involve purchasing,
gathering and transporting by trucks and pipelines operated by us and trucks,
pipelines and barges operated by others, and reselling, help to ensure (among
other things) a base supply source for our crude oil pipeline systems. Our
profit for those services is derived from the difference between the price at
which we re-sell oil less the price at which we purchase that crude oil, minus
the associated costs of aggregation and any cost of supplying credit. The most
substantial component of our aggregating costs relates to operating our fleet of
leased trucks. Our crude 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.
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
for a higher price, either with a counterparty or in the crude oil futures
market. The maximum storage capacity available to us for use in this strategy is
approximately 120,000 barrels, although maintenance activities on our pipelines
impact the availability of this storage capacity. 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, we gained approximately 225 trucks, 525 trailers and 1.3
million barrels of existing leased and owned storage and 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 a
service 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. The opportunities to provide this service cannot be
predicted, but their contribution to margin as a percentage of their revenues
tends to be higher than in the same percentage attributable to our recurring
operations.
Most of
our contracts for the purchase and sale of crude oil have components in the
pricing provisions such that the price paid or received is adjusted for changes
in the market price for crude oil. The pricing in the majority of our
purchase contracts contain the market price component, an unfixed bonus that is
based on another market factor and a deduction to cover the cost of transporting
the crude oil and to provide us with a margin. Contracts will sometimes also
contain a grade differential which considers the chemical composition of the
crude oil and its appeal to different customers. Typically the
pricing in a contract to sell crude oil will consist of the market price
components and the grade differentials. The margin on individual
transactions is then dependent on our ability to manage our transportation costs
and to capitalize on grade differentials.
In our
petroleum products marketing operations, we primarily supply fuel oil, asphalt,
diesel and gasoline to wholesale markets and some end-users such as paper mills
and utilities. We also provide a service to refineries by purchasing
their products that do not meet the specifications they desire, transporting it
to one of our terminals and blending it to a quality that meets the requirements
of our customers. The opportunities to provide this service
cannot be predicted, but the contribution to margin tends to be higher than in
our recurring operations
Operating
results from continuing operations for our supply and logistics segment were as
follows.
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Supply
and logistics revenue
|
$ | 1,094,189 | $ | 873,268 | $ | 1,038,549 | ||||||
|
Crude
oil and products costs
|
(1,041,738 | ) | (851,671 | ) | (1,018,896 | ) | ||||||
|
Operating
costs
|
(37,121 | ) | (14,231 | ) | (15,992 | ) | ||||||
|
Segment
margin
|
$ | 15,330 | $ | 7,366 | $ | 3,661 | ||||||
Year
Ended December 31, 2007 Compared with Year Ended December 31, 2006
The
portions of our supply and logistics operations acquired in the Davison
transaction added approximately $8.6 million to our supply and logistics segment
margin for the five months we owned these operations in 2007. Our
existing crude oil gathering and marketing operations contribution for 2007 was
$0.6 million less than the contribution for 2006, however the contribution was
actually the result of offsetting fluctuations as discussed below. Contribution
by our crude oil operations is derived from sales of crude oil and from the
transportation of crude oil volumes that we did not purchase by truck for a fee,
with costs for this part of the operation relating to the purchase of the crude
oil and the related aggregation and transportation costs.
An
increase in the operating costs related to our crude oil activities of $4.0
million was the largest contributor to the decrease in segment margin from crude
oil operations. Compensation and related costs accounted for
$1.8 million of the increased costs, including an increase of $0.2 million for
our stock appreciation rights plan. In order to remain competitive in
retaining drivers for our crude oil trucking, we increased compensation
rates. We also had increased costs for fuel and repairs to our trucks
and related equipment that combined to increase our operating costs in the crude
oil area by $1.2 million. We increased the accrual for the
remediation of a former trucking station by $0.3 million. (See Note
18 of the Notes to the Consolidated Financial
Statements). Additionally we incurred costs of $0.7 million related
to the operation of the Port Hudson facility which we acquired in
2007.
Partially
offsetting these increased operating costs was an increase of 1,429 barrels per
day in crude oil volumes that we transported for a fee. Most of this
increase in volume was attributable to transportation of Denbury’s production
from its wellheads to our pipeline. The increase in the fees for
these services was $2.7 million between 2006 and 2007. On a like-kind
basis, volumes purchased and sold decreased by 2,531 barrels per
day. We focused on volumes in 2007 that met our targets for
profitability, and we were impacted by significant volatility between crude
quality differentials between the periods, with the overall impact on margin of
a decrease of $0.6 million. The margins generated from the storage of
crude oil inventory in the contango market were $0.2 million greater in 2007
than 2006.
If we had
owned our Supply and Logistics segment for all of 2007, our estimated pro forma
segment margin would have been $25.5 million. For the comparable
period in 2006, the estimated pro forma margin from this segment would have been
approximately $24.8 million.
Year
Ended December 31, 2006 Compared with Year Ended December 31, 2005
Our crude
oil gathering and marketing segment margin increased by slightly more than
double in 2006 over the prior year period. A decrease in field costs
of $1.8 million combined with $1.9 million of increased segment margin from the
two other factors resulted in a total increase of $3.7 million.
The
majority of the decrease in field costs from the 2005 level related to a
reduction in the size of our fleet. When we leased new trucks late in
2005, we reduced the size of the fleet to better match the volumes being
purchased. This reduction in fleet size reduced personnel and truck
lease costs. The new trucks also required less repair costs in the
first year of the lease. During 2005 we also recorded a reserve of
$0.5 million for 40% of the expected costs to remediate Jay Trucking Station,
which made costs in that period higher than 2006. (See additional
discussion at Note 18 to the Consolidated Financial
Statements.) Higher fuel costs offset part of the reduction. Average
fuel costs during 2006 increased more than $0.30 per gallon, or 13 percent, over
the 2005 level. We also recorded expense in field operating costs in
the 2006 period of $0.3 million related to our SAR plan.
A $0.3
million increase in revenues from volumes that we transported for a fee but did
not purchase increased segment margin. Approximately 52% of the total
transportation fee revenue related to volumes transported for Denbury from its
wellhead locations to our pipeline using our trucks. We also provide
these transportation services for third parties to move crude oil from wellhead
locations to destinations designated by those third parties.
Approximately
$0.7 million of the remaining increase in segment margin resulted again from a
focus on eliminating less profitable volumes, and increasing profitability on
the volumes retained by maximizing the benefits to us of fluctuations in prices
in the regions in which we operate. Additionally, while we were in a
contango crude oil price market for most of 2005 and 2006, the contribution to
segment margin from our inventory hedges was approximately $0.9 million greater
in the 2006 period.
Other
Costs and Interest
General and administrative
expenses were as follows.
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Expenses
excluding effect of stock appreciation rights plan, bonus plan, Davison
locations, management compensation and management team
transition
|
$ | 12,125 | $ | 9,007 | $ | 8,903 | ||||||
|
Expenses
of Davison locations
|
4,652 | - | - | |||||||||
|
Bonus
plan expense
|
2,033 | 1,747 | 1,235 | |||||||||
|
Stock
appreciation rights plan expense (credit)
|
1,576 | 1,279 | (482 | ) | ||||||||
|
Compensation
expense related to management team
|
3,434 | - | - | |||||||||
|
Management
team transition costs and write-off of deferred charges from prior credit
facility
|
2,100 | 1,540 | - | |||||||||
|
Total
general and administrative expenses
|
$ | 25,920 | $ | 13,573 | $ | 9,656 | ||||||
Year
Ended December 31, 2007 Compared with Year Ended December 31, 2006
Total
general and administrative (G&A) expenses, increased by $12.3 million,
however expenses related to the operations we acquired, the effects of our SAR
and bonus plans, and costs related to changes in our management team caused most
of the increase. Excluding these items, G&A expenses were $3.1
million greater in 2007 than in 2006.
Increases
in G&A expenses in 2007 are attributable to personnel added in our
headquarters office late in 2006, increased legal, audit, tax and other
consulting fees, additional director fees and expenses and costs related to our
airplane. In the latter half of 2006 we added a new management team
and additional support personnel. In 2007 G&A expenses included a
full year of the compensation costs and associated expenses related to these
personnel as well as wage increases, altogether increasing G&A expense by
$0.9 million. The addition of the Davison businesses increased our
costs for professional services by approximately $1.3 million. The
increase in the size of our board of directors and related costs increased by
$0.1 million and costs associated with our company aircraft increased G&A
expenses by $0.5 million. The remaining increase in costs of $0.3
million is attributable to general G&A expenses.
As a
result of the improvement in our Available Cash before Reserves in 2007, our
accrual under our bonus plan increased by $0.3 million. The
bonus plan for employees is described in Item 11, “Executive Compensation”
below. The plan provides for a bonus pool based on the amount of
Available Cash before Reserves generated. In 2007, we generated more
available cash than in 2006, resulting in a larger bonus expense.
In 2006,
we adopted a new accounting pronouncement that changed the method by which we
record expense related to our SAR plan. (See additional discussion in
“Cumulative Effect Adjustments” below and in Note 15 to the Consolidated
Financial Statements.) The SAR plan for employees and directors is a
long-term incentive plan whereby rights are granted for the grantee to receive
cash equal to the difference between the grant price and common unit price at
date of exercise. The rights vest over several
years. Under this new method of accounting for the outstanding SARs,
we determine the fair value of the SARs at the end of each period and the fair
value is charged to expense over the period during which the employee vests in
the SARs. Changes in our common unit market price affect the
computation of the fair value of the outstanding SARs. The
change in fair value combined with the elapse of time and its effect on the
vesting of SARs create the expense we record. Additionally any
difference between the expected value for accounting purposes that an employee
will receive upon exercise of his rights and the actual value received when the
employee exercise the SARs creates additional expense. During a part
of 2007, our unit price increased to over $25 per unit and 37,328 SARs were
exercised by plan participants that are included in G&A expense, resulting
in additional expense in 2007 of more than $0.6 million.
Denbury
has been negotiating with our management team that was hired in August 2006 to
finalize a compensation package for that team which is ultimately expected to
include equity-based compensation from an ownership interest in our general
partner. When the terms of those arrangements are finalized and the
agreements and necessary structure are in place, we expect that the remaining
members of the management team hired in August 2006 will have the opportunity to
earn up to 14.4% of a General Partner Incentive Interest. Although
the terms of this arrangement have not been agreed to and completed (see
additional discussion in Item 11. Executive Compensation - Senior Executives),
we recorded expense of $3.4 million in 2007, representing an estimated
value of compensation attributable to our Chief Executive Officer and Chief
Operating Officer for services performed during 2007 and completion of the
Davison transaction. Although this compensation is to ultimately come
from our general partner, we have recorded the expense in our Consolidated
Statements of Operations in G&A expense due to the “push-down” rules for
accounting for transactions where the beneficiary of a transaction is not the
same as the parties to the transaction. This estimated expense may be
different from what may be recorded as compensation once such arrangements
are finalized.
Additionally,
we recorded transition costs primarily in the form of severance costs in each
period when members of our management team changed in December 2007 and August
2006. Our general partner made a cash contribution to us of $1.4
million in 2007 to partially offset the $2.1 million cash cost of the severance
payment to a former member of our management team.
Year
Ended December 31, 2006 Compared with Year Ended December 31, 2005
Total
G&A expenses, increased by $3.9 million, however the effects of our SAR and
bonus plans, transition costs related to the change in our management team and
the write-off of deferred charges related to our prior credit facility caused
that increase. Excluding these items, G&A expenses in 2006 and
2005 were approximately $9.0 million.
As a
result of the improvement in our financial results in 2006, our accrual under
our bonus plan increased by $0.5 million. The bonus plan for
employees is described in Item 11, “Executive Compensation”
below. The plan provides for a bonus pool based on the amount of
Available Cash before Reserves generated. In 2006, we generated more
available cash than in 2005, resulting in a larger bonus expense.
The
change in the method of accounting for our SAR plan in 2006, increased G&A
expense by $1.7 million from a credit to expense in 2005 to a charge to expense
in 2006 of $1.3 million. In periods prior to 2006, the charge or
credit to our earnings related to our SAR plan was primarily a function of the
change in the market price for our common units from the prior period
end.
As
indicated above, we recorded transition costs of $1.4 million, primarily in the
form of severance costs, when our management team changed in August
2006. When we replaced our credit facility in November 2006, we
wrote-off $0.1 million of unamortized deferred legal costs related to our prior
facility.
Depreciation, amortization
and impairment expense was as follows:
|
December
31,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
Depreciation
on Genesis assets excluding acquired Davison assets
|
$ | 3,997 | $ | 3,719 | $ | 3,579 | ||||||
|
Depreciation
on acquired Davison property, plant and equipment
|
4,912 | - | - | |||||||||
|
Impairment
expense on natural gas pipeline assets
|
1,498 | - | - | |||||||||
|
Amortization
on acquired Davison intangible assets
|
25,350 | |||||||||||
|
Amortization
of CO2 volumetric production payments
|
4,488 | 4,244 | 3,142 | |||||||||
|
Total
depreciation, amortization and impairment expense
|
$ | 40,245 | $ | 7,963 | $ | 6,721 | ||||||
Depreciation,
amortization and impairment increased $32.3 million between 2006 and
2007. The majority of this increase is related to the depreciation
and amortization expense recognized on the fixed assets and intangible assets
acquired from the Davison family. The depreciation and amortization
expense on the acquired assets reflects our ownership of these assets for the
last five months of 2007.
The
intangibles acquired in the Davison acquisition are being amortized over the
period during which the intangible asset is expected to contribute to our future
cash flows. As intangible assets such as customer relationships and
trade names are generally most valuable in the first years after an acquisition,
the amortization we will record on these assets will be greater in the initial
years after the acquisition. As a result, we expect to record
significantly more amortization expense related to our intangible assets in 2008
through 2010 than in years subsequent to that time. See Note 9 to the
Consolidated Financial Statements for information on the amount of amortization
we expect to record in each of the next five years.
As
discussed above in “Pipeline Transportation Segment”, our natural gas pipeline
activities were impacted by production difficulties of a producer attached to
the system. Due to declines we have experienced in the results from
our natural gas pipelines, we reviewed these assets to determine if the fair
market value of the assets exceeded the net book value of the
assets. As a result of this review, we recorded an impairment loss of
$1.5 million related to these assets.
Amortization
of our CO2 volumetric
payments is based on the units-of-production method. We acquired
three volumetric production payments totaling 280 Mcf of CO2 from
Denbury between 2003 and 2005. Amortization is based on volumes sold
in relation to the volumes acquired. In each annual period, the
volume of CO2 sold has
increased.
Depreciation,
amortization and impairment increased $1.2 million between 2005 and 2006. The
majority of this increase related to amortization of our CO2
assets. Amortization of the CO2 assets
increased due to the additional CO2 volumes
sold in the 2006 period as compared to 2005. These additional sales
related primarily to the CO2 contracts
acquired in the fourth quarter of 2005.
Interest expense, net
was as follows:
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Interest
expense, including commitment fees
|
$ | 10,103 | $ | 781 | $ | 1,831 | ||||||
|
Capitalized
interest
|
(59 | ) | (9 | ) | (35 | ) | ||||||
|
Amortization
of facility fees
|
441 | 300 | 307 | |||||||||
|
Write-off
of facility fees and other fees
|
- | 500 | - | |||||||||
|
Interest
income
|
(385 | ) | (198 | ) | (71 | ) | ||||||
|
Net
interest expense
|
$ | 10,100 | $ | 1,374 | $ | 2,032 | ||||||
As a
result of the Davison acquisition which was partially financed with borrowings
under our credit facility made on July 25, 2007, our interest expense,
including commitment fees increased $9.3 million in 2007. Our average
outstanding balance of debt was $118.5 million during 2007, an increase of
$115.1 million over 2006. Our average interest rate during 2007 was 7.78%, a
decrease of 0.64% from 2006. Our equity offering in December 2007 was
used to partially repay our outstanding debt, reducing the balance to $80.0
million at December 31, 2007.
Total net
interest expense in 2006 was $0.7 million less than in 2005. Interest
expense including commitment fees was $1.1 million lower due to average
outstanding bank debt that was $15.8 million lower and an interest rate that was
1.3% higher. Our equity offering in December 2005 was used to repay
outstanding debt from acquisitions in 2005 and prior years, resulting in the
lower average debt balance in 2006. Market interest rates rose in
2006 from 2005 levels, however the impact to us was minor because of our lower
debt balances. During 2006, our average daily debt outstanding was
$3.4 million.
As a
result of the termination of our prior credit facility to enter into the new
facility we obtained in November 2006, we wrote-off $0.5 million of deferred
facility fees related to the prior credit facility in 2006.
Interest
income has fluctuated as a result of fluctuations in excess cash available to be
invested on a daily basis.
Net gain/loss on disposal of
surplus assets. In 2007, 2006 and 2005 we sold surplus assets
no longer used in our operations, recognizing small gains in each
period. In addition, we retired 6.0 miles of pipeline on our Jay
System resulting in an approximate $0.3 million loss. The 6.0 miles
of pipeline was replaced through one of our capital projects completed in
2007.
Cumulative
Effect Adjustments of Adoption of New Accounting Principles
2006
On
January 1, 2006, we adopted the provisions of SFAS No. 123(R). In
December 2004, the FASB issued SFAS No. 123 (revised December 2004),
“Share-Based Payments”. The adoption of 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.
At
December 31, 2005, we had a recorded liability of $0.8 million, computed under
the provisions of FASB Interpretation No. 28. We calculated the
effect of adoption of SFAS 123(R) at January 1, 2006, and determined that our
recorded liability at December 31, 2005 should be reduced by
$30,000. This reduction is reflected as income from the cumulative
effect of the adoption of a new accounting principle on our statement of
operations. We do not believe the effect of adoption of this
accounting principle at January 1, 2005 would have been material.
2005
On
December 31, 2005, we adopted FASB Interpretation No. 47, “Accounting for
Conditional Asset Retirement Obligations, an interpretation of FASB Statement
No. 143”, or FIN 47. FIN 47 clarified that the term “conditional
asset retirement obligation”, as used in SFAS No. 143, “Accounting for Asset
Retirement Obligations”, refers to a legal obligation to perform an asset
retirement activity in which the timing and/or method of settlement are
conditioned upon a future event that may or may not be within our
control. Although uncertainty about the timing and/or method of
settlement may exist and may be conditioned upon a future event, the obligation
to perform the asset retirement activity is
unconditional. Accordingly, we are required to recognize a liability
for the fair value of a conditional asset retirement obligation if the fair
value of the liability can be reasonably estimated.
Some of
our assets, primarily related to our pipeline operations segment, have
obligations regarding removal activities when the asset is abandoned or
retired. Additionally, we generally have obligations to remove crude
oil injection stations located on leased sites. These assets are
actively in use in our operations and the timing of the abandonment of these
assets cannot be determined. Accordingly, under the provisions of FIN
47, we have made an estimate of the fair value of our obligations.
Upon
adoption of FIN 47, we recorded a fixed asset and a liability for the estimated
fair value of the asset retirement obligations at the time we acquired the
related assets. This $0.3 million fixed asset is being depreciated
over the life of the related assets. The accretion of the discount on
the liability and the depreciation through December 31, 2005 were recorded in
the statement of operations as a cumulative effect adjustment totaling $0.5
million. Additionally, we reflected our share of the asset retirement
obligation recorded in accordance with FIN 47 of our equity method joint venture
as a cumulative affect adjustment of $0.1 million.
See Note
5 to the Consolidated Financial Statements for the pro forma impact for the
periods ended December 31, 2005 of the adoption of FIN 47 if it had been adopted
at the beginning of that period.
Critical
Accounting Policies and Estimates
The
preparation of consolidated financial statements in conformity with accounting
principles generally accepted in the United States requires us to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities, if any, at the date of the
consolidated financial statements and the reported amounts of revenues and
expenses during the reporting period. We base these estimates and assumptions on
historical experience and other information that are believed to be reasonable
under the circumstances. Estimates and assumptions about future
events and their effects cannot be perceived with certainty, and, accordingly,
these estimates may changes as new events occur, as more experience is acquired,
as additional information is obtained and as the business environment in which
we operate changes. Significant accounting policies that we employ
are presented in the notes to the consolidated financial statements (See Note 2
Summary of Significant Accounting Policies.)
We have
defined critical accounting policies and estimates as those that are most
important to the portrayal of our financial results and
positions. These policies require management’s judgment and often
employ the use of information that is inherently uncertain. Our most
critical accounting policies pertain to measurement of the fair value of assets
and liabilities in business acquisitions, depreciation, amortization and
impairment of long-lived assets, asset retirement obligations, our stock
appreciation rights plan and contingent and environmental
liabilities. We discuss these policies below.
Fair
Value of Assets and Liabilities Acquired and Identification of Associated
Goodwill and Intangible Assets.
In
conjunction with each acquisition we make, we must allocate the cost of the
acquired entity to the assets and liabilities assumed based on their estimated
fair values at the date of acquisition. We also estimate the amount of
transaction costs that will be incurred in connection with each acquisition. As
additional information becomes available, we may adjust the original estimates
within a short time period subsequent to the acquisition. In addition, we are
required to recognize intangible assets separately from goodwill. Determining
the fair value of assets and liabilities acquired, as well as intangible assets
that relate to such items as customer relationships, contracts, trade names, and
non-competes involves professional judgment and is ultimately based on
acquisition models and management’s assessment of the value of the assets
acquired. Uncertainties associated with these estimates include fluctuations in
economic obsolescence factors in the area and potential future sources of cash
flow. We cannot provide assurance that actual amounts will not vary
significantly from estimated amounts. In connection with the
Davison and Port Hudson acquisitions, we performed allocations of the purchase
price. See Note 3 of the Notes to the Consolidated Financial
Statements.
Depreciation
and Amortization of Long-Lived Asset and Intangibles
In order
to calculate depreciation and amortization we must estimate the useful lives of
our fixed assets at the time the assets are placed in service. We
compute depreciation using the straight-line method based on these estimated
useful lives. The actual period over which we will use the asset may differ from
the assumptions we have made about the estimated useful life. We
adjust the remaining useful life as we become aware of such
circumstances.
Intangible
assets with finite useful lives are required to be amortized over their
respective estimated useful lives. If an intangible asset has a
finite useful life, but the precise length of that life is not known, that
intangible asset shall be amortized over the best estimate of its useful
life. At a minimum, we will assess the useful lives and residual
values of all intangible assets on an annual basis to determine if adjustments
are required. We are recording amortization of our customer and
supplier relationships, licensing agreements and trade 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 over
their expected useful lives.
Impairment
of Long-Lived Assets including Intangibles and Goodwill
When
events or changes in circumstances indicate that the carrying amount of a fixed
asset or intangible assets may not be recoverable, we review our assets for
impairment in accordance with SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets. We compare the carrying value of the
fixed asset to the estimated undiscounted future cash flows expected to be
generated from that asset. Estimates of future net cash flows
include estimating future volumes, future margins or tariff rates, future
operating costs and other estimates and assumptions consistent with our business
plans. If we determine that an asset’s unamortized cost may not be
recoverable due to impairment; we may be required to reduce the carrying value
and the subsequent useful life of the asset. Any such write-down of the value
and unfavorable change in the useful life of an intangible asset would increase
costs and expenses at that time. During the fourth quarter of 2007,
we reviewed the carrying value of our natural gas pipelines due to changes in
the source of supply to the pipelines. As a result of this review we
recorded an impairment charge of $1.5 million. See Note 4 of the
Notes to the Consolidated Financial Statements.
Goodwill
represents the excess of the purchase prices we paid for certain businesses over
their respective fair values and is primarily comprised of $316.7 million
associated with the Davison acquisition. We do not amortize goodwill; however,
we test our goodwill (at the reporting unit level) for impairment during the
fourth quarter of each fiscal year, and more frequently, if circumstances
indicate it is more likely than not that the fair value of goodwill is below its
carrying amount. Our goodwill testing involves the determination of a reporting
unit’s fair value, which is predicated on our assumptions regarding the future
economic prospects of the reporting unit. Such assumptions include
(i) discrete financial forecasts for the assets contained within the
reporting unit, which rely on management’s estimates of operating margins,
(ii) long-term growth rates for cash flows beyond the discrete forecast
period, and (iii) appropriate discount rates. If the fair value of the reporting
unit (including its inherent goodwill) is less than its carrying value, a charge
to earnings is required to reduce the carrying value of goodwill to its implied
fair value. At December 31, 2007, the carrying value of our goodwill was
$320.7 million. We did not record any goodwill impairment charges during
2007. At December 31, 2007, the estimated fair value of our
refinery services reporting unit was $9 million more than the carrying value of
our net assets of that reporting unit. The estimated fair value of
our supply and logistics reporting unit was $45 million more than the carrying
value of that reporting unit.
For
additional information regarding our goodwill, see Notes 3 and 9 of the Notes to
Consolidated Financial Statements.
Asset
Retirement Obligations
Some of
our assets, primarily related to our pipeline operations segment, have
obligations regarding removal and restoration activities when the asset is
abandoned. Additionally, we generally have obligations to remove
crude oil injection stations located on leased sites. We estimate the
future costs of these obligations, discount those costs to their present values,
and record a corresponding asset and liability in our Consolidated Balance
Sheets. The values ultimately derived are based on many significant
estimates, including the ultimate expected cost of the obligation, the expected
future date of the required cash payment, and interest and inflation rates.
Revisions to these estimates may be required based on changes to cost estimates,
the timing of settlement, and changes in legal requirements. Any such changes
that result in upward or downward revisions in the estimated obligation will
result in an adjustment to the related capitalized asset and corresponding
liability on a prospective basis and an adjustment in our depreciation expense
in future periods. See Note 5 to our Consolidated Financial Statements for
further discussion regarding our asset retirement obligations.
Stock
Appreciation Rights Plan
We accrue
for the fair value of our liability for the stock appreciation rights (“SAR”)
awards we have issued to our employees and directors under the provisions of
SFAS No. 123(R), Share-Based
Payments, as amended and interpreted. Under our SAR plan,
grantees receive cash for the difference between the market value of our common
units and the strike price of the award. We estimate the fair value
of SAR awards at each balance sheet date using the Black-Scholes option pricing
model. The Black-Scholes valuation model requires the input of somewhat
subjective assumptions, including expected stock price volatility and expected
term. Other assumptions required for estimating fair value with the
Black-Scholes model are the expected risk-free interest rate and our expected
distribution yield . The risk-free interest rates used are the U.S. Treasury
yield for bonds matching the expected term of the option on the date of grant.
At December 31, 2007 and 2006, we used an expected distribution yield of
6%. Our SAR plan was instituted December 31, 2003, so we have very
limited experience from which to determine the expected term of the
awards. As a result, we use the simplified method allowed by the
Securities and Exchange Commission to determine the expected life, which results
in an expected life of 6 to 7 years at the time an award it
granted.
We
recognize the stock-based compensation expense on a straight-line basis over the
requisite service period for the awards. The expense we recognize is net of
estimated forfeitures. We estimate our forfeiture rate at each balance sheet
date based on prior experience. As of December 31, 2007, there was
$1.2 million of total compensation cost to be recognized in future periods
related to non-vested SARs. The cost is expected to be recognized over a
weighted-average period of one year. See Note 15 to our
Consolidated Financial Statements for further discussion regarding our SAR
plan.
Liability
and Contingency Accruals
We accrue
reserves for contingent liabilities including environmental remediation and
potential legal claims. When our assessment indicates that it is
probable that a liability has occurred and the amount of the liability can be
reasonably estimated, we make accruals. We base our estimates on all
known facts at the time and our assessment of the ultimate outcome, including
consultation with external experts and counsel. We revise these
estimates as additional information is obtained or resolution is
achieved.
We also
make estimates related to future payments for environmental costs to remediate
existing conditions attributable to past operations. Environmental
costs include costs for studies and testing as well as remediation and
restoration. We sometimes make these estimates with the assistance of
third parties involved in monitoring the remediation effort.
We are
currently conducting remediation of subsurface soil and groundwater hydrocarbon
contamination at the former Jay Trucking Facility. The total
estimated remediation and related costs are $2.0 million, which we share with
other responsible parties. In 2005, we recorded a liability of $0.5
million as our estimated share of this liability. Based on additional
information, we increased this accrual by $0.3 million in 2007. We
currently have no reason to believe that this remediation will have a material
financial effect on our financial position, results of operation, or cash
flows.
Recent
Accounting Pronouncements
SFAS
157
In
September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements”, or SFAS
157. SFAS 157 defines fair value, establishes a framework for
measuring fair value in accordance with accounting principles generally accepted
in the United States, and expands disclosures about fair value
measurements. SFAS 157 emphasizes that fair value is a market-based
measurement that should be determined based on the assumptions that market
participants would use in pricing an asset or liability. In February
2008, the FASB issued SFAS No. 157-2, “Effective Date of FASB Statement No.
157”, or SFAS 157-2, which delays the effective date of SFAS 157 for
non-financial assets and non-financial liabilities. In accordance
with SFAS 157-2, SFAS 157 is effective for fiscal years beginning after November
15, 2007 for financial assets and liabilities as well as for any other assets
and liabilities that are carried at fair value on a recurring basis in financial
statements. We adopted SFAS 157 on January 1, 2008 for such assets
and liabilties with no material impact on our consolidated financial
statements. We will begin the new disclosure requirements in the
first quarter of 2008. We do not currently know what the effects of
the deferred provisions of SFAS 157 will be on our financial position and
results of operations when adopted in 2009.
SFAS
159
In
February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for
Financial Assets and Financial Liabilities”, or SFAS 159. SFAS 159
permits entities to choose to measure many financial assets and financial
liabilities at fair value. Unrealized gains and losses on items for
which the fair value option has been elected are reported in
earnings. SFAS 159 is effective for us beginning on January 1,
2008. We are currently assessing the impact of SFAS 159 on our
consolidated financial statements.
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 will
adopt SFAS 141(R) on January 1, 2009 for acquisitions on or after that
date.
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 the noncontrolling
interest in a subsidiary and for the deconsolidation of a subsidiary in an
effort to improve the relevance, comparability and transparency of the financial
information that a reporting entity provides in its consolidated financial
statements. SFAS 160 is effective for fiscal years beginning after
December 15, 2008. We will adopt SFAS 160 on January 1,
2009. We are assessing the impact of this statement on our financial
statements, but expect it to impact the presentation of the non-controlling
interest in our operating partnership.
EITF
07-4
In May
2007, 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.” This EITF considers the question of whether
the incentive distribution rights (“IDRs”) of a master limited partnership
represent a participating security and should be considered in the calculation
of earnings per unit. Under the “two class” method of computing
earnings per unit, earnings are allocated to participating securities as if all
of the earnings for the period had been distributed. The EITF also
presents alternative methods for inclusion of IDRs in the computation of
earnings per unit, depending on whether cash distributions exceed earnings for
the period. The EITF has issued a draft abstract on this topic and
will address comments it receives before issuing a final
consensus. Once a final consensus is issued it is expected to be
effective for fiscal years beginning after December 15, 2008, and interim
periods within those fiscal years. We will assess the impact of EITF
07-4 once a final consensus is issued; however we would expect it to have an
impact on our presentation of earnings per unit in the future. For
additional information on our incentive distribution rights, see Note
11.
Item
7a. Quantitative and Qualitative Disclosures About
Market Risk
We are
exposed to various market risks, primarily related to volatility in crude oil
and petroleum products prices, NaOH prices and interest rates. Our policy is to
purchase only commodity products for which we have a market, and to structure
our sales contracts so that price fluctuations for those products do not
materially affect the segment margin we receive. We do not acquire
and hold futures contracts or other derivative products for the purpose of
speculating on price changes, as these activities could expose us to significant
losses.
Our
primary price risk relates to the effect of crude oil and petroleum products
price fluctuations on our inventories and the fluctuations each month in grade
and location differentials and their effect on future contractual
commitments. Our risk management policies are designed to monitor our
physical volumes, grades and delivery schedules to ensure our hedging activities
address the market risks that are inherent in our gathering and marketing
activities.
We
utilize NYMEX commodity based futures contracts and option contracts to hedge
our exposure to these market price fluctuations as needed. All of our
open commodity price risk derivatives at December 31, 2007 were categorized as
non-trading. On December 31, 2007, we had entered into NYMEX future contracts
that will settle during February 2008 and NYMEX options contracts that will
settle during March 2008. Although the intent of our risk-management
activities is to hedge our margin, none of our derivative positions at December
31, 2007 qualified for hedge accounting. This accounting treatment is
discussed further under Note 17 to our Consolidated Financial
Statements.
The table
below presents information about our open derivative contracts at December 31,
2007. Notional amounts in barrels, the weighted average contract
price, total contract amount and total fair value amount in U.S. dollars of our
open positions are presented below. Fair values were determined by
using the notional amount in barrels multiplied by the December 31, 2007 quoted
market prices on the NYMEX. All of the hedge positions offset
physical exposures to the cash market; none of these offsetting physical
exposures are included in the table below.
|
Sell
(Short)
|
Buy
(Long)
|
|||||||
|
Contracts
|
Contracts
|
|||||||
|
Futures
Contracts:
|
||||||||
|
Crude
Oil:
|
||||||||
|
Contract
volumes (1,000 bbls)
|
74 | 14 | ||||||
|
Weighted
average price per bbl
|
$ | 90.87 | $ | 92.27 | ||||
|
Contract
value (in thousands)
|
$ | 6,724 | $ | 1,292 | ||||
|
Mark-to-market
change (in thousands)
|
378 | 52 | ||||||
|
Market
settlement value (in thousands)
|
$ | 7,102 | $ | 1,344 | ||||
|
Heating
Oil:
|
||||||||
|
Contract
volumes (1,000 bbls)
|
50 | 10 | ||||||
|
Weighted
average price per bbl
|
$ | 107.43 | $ | 110.84 | ||||
|
Contract
value (in thousands)
|
$ | 5,372 | $ | 1,108 | ||||
|
Mark-to-market
change (in thousands)
|
192 | 4 | ||||||
|
Market
settlement value (in thousands)
|
$ | 5,564 | $ | 1,112 | ||||
|
NYMEX
Option Contracts:
|
||||||||
|
Crude
Oil-Written Calls:
|
||||||||
|
Contract
volumes (1,000 bbls)
|
47 | |||||||
|
Weighted
average premium received
|
$ | 2.75 | ||||||
|
Contract
value (in thousands)
|
$ | 129 | ||||||
|
Mark-to-market
change (in thousands)
|
87 | |||||||
|
Market
settlement value (in thousands)
|
$ | 216 | ||||||
|
Natural
Gas-Written Calls
|
||||||||
|
Contract
volumes (10,000 mmBtus)
|
5 | |||||||
|
Weighted
average premium received
|
$ | 2.50 | ||||||
|
Contract
value (in thousands)
|
$ | 13 | ||||||
|
Mark-to-market
change (in thousands)
|
1 | |||||||
|
Market
settlement value (in thousands)
|
$ | 14 | ||||||
.We
manage our risks of volatility in NaOH prices by indexing prices for the sale of
NaHS to the market price for NaOH in most of our contracts.
We are
also exposed to market risks due to the floating interest rates on our credit
facility. Our debt bears interest at the LIBOR Rate or Prime Rate
plus the applicable margin at our option. We do not hedge our
interest rates. The carrying values of our debt approximate fair
value primarily because interest rates fluctuate with prevailing market rats,
and the credit spread on outstanding borrowings reflect market. On
December 31, 2007, we had $80.0 million of debt outstanding under our credit
facility.
Item
8. Financial Statements and Supplementary
Data
The
information required hereunder is included in this report as set forth in the
“Index to Consolidated Financial Statements” on page 93.
Item
9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure
None.
Item
9A. Controls and Procedures
We
maintain disclosure controls and procedures and internal controls designed to
ensure that information required to be disclosed in our filings under the
Securities Exchange Act of 1934 is recorded, processed, summarized and reported
within the time periods specified in the Securities and Exchange Commission’s
rules and forms. Our chief executive officer and chief financial
officer, with the participation of our management, have evaluated our
disclosure controls and procedures as of the end of the period covered by this
Annual Report on Form 10-K and have determined that such disclosure controls and
procedures are effective in providing reasonable assurance of the timely
recording, processing, summarizing and reporting of information, and in
accumulation and communication to management in all material respects on a
timely basis material information relating to us (including our consolidated
subsidiaries) required to be disclosed in this annual report.
There
were no changes during our last fiscal quarter that materially affected, or are
reasonably likely to materially affect, our internal control over financial
reporting.
Management’s
Report on Internal Control over Financial Reporting
Management
of the Partnership is responsible for establishing and maintaining effective
internal control over financial reporting as defined in Rules 13a-15(f) under
the Securities Exchange Act of 1934. The Partnership’s internal
control over financial reporting is designed to provide reasonable assurance to
the Partnership’s management and board of directors regarding the preparation
and fair presentation of published financial statements.
Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation
of effectiveness to future periods are subject to the risk that controls may
become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
Davison
Acquisition
On
July 25, 2007, we completed the Davison Acquisition, which met the criteria
of being a significant acquisition for us. For additional information regarding
the acquisition, please read Note 3 to the Consolidated Financial
Statements and “Management’s Discussion and Analysis of Financial Condition and
Results of Operations – Acquisitions and Related Activities in 2007” included in
Item 7 in this Annual Report.
On
June 22, 2004, the Office of the Chief Accountant of the SEC issued
guidance regarding the reporting of internal control over financial reporting in
connection with a major acquisition. On October 6, 2004, the SEC revised
its guidance to include expectations of quarterly reporting updates of new
internal control and the status of the control regarding any exempted
businesses. This guidance was reiterated in September 2007 to affirm that
management may omit an assessment of an acquired business’s internal control
over financial reporting from its assessment of internal control over financial
reporting for a period not to exceed one year.
We are in
the process of implementing our internal control structure over the operations
we acquired from the Davisons. Due to the magnitude of the businesses, we expect
that this effort will be completed in 2008. The assessment and documentation of
internal controls requires a complete review of controls operating in a stable
and effective environment.
Management assessed the effectiveness
of the Partnership’s internal control over financial reporting as of December
31, 2007. This assessment excluded the Davison
Acquisition. In making this assessment, management used the criteria
established in Internal Control – Integrated Framework issued by the Committee
of Sponsoring Organizations of the Treadway Commission. Based on our
assessment, we believe that, as of December 31, 2007, the Partnership’s internal
control over financial reporting is effective based on those
criteria.
Pursuant to Section 404 of the
Sarbanes-Oxley Act of 2002, our management included a report of their assessment
of the design and effectiveness of our internal controls over financial
reporting as part of this Annual Report on Form 10-K for the fiscal year ended
December 31, 2007. Deloitte & Touche LLP, the Company’s independent
registered public accounting firm, has issued an attestation report on the
effectiveness of the Company’s internal control over financial reporting.
Deloitte & Touche’s attestation report on the Partnership’s internal control
over financial reporting appears below.
Report
of Independent Registered Public Accounting Firm on Internal Control over
Financial Reporting
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Board of Directors of Genesis Energy, Inc. and Unitholders of
Genesis
Energy, L.P.
Houston,
Texas
We have
audited the internal control over financial reporting of Genesis Energy, L.P.
and subsidiaries (the "Partnership") as of December 31, 2007, based on criteria
established in Internal
Control — Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. As described in Management’s
Report on Internal Control Over Financial Reporting, Management excluded from
its assessment the internal control over financial reporting for the businesses
acquired on July 25, 2007 (the “Davison Acquisition” as defined in Note 3) whose
financial statements constitute 73% of total assets, 26% of total revenues, and
34% of net loss of the consolidated financial statement amounts as of and for
the year ended December 31, 2007. Accordingly, our audit did not include
the internal control over financial reporting for the Davison
Acquisition. The Partnership's management is responsible for
maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting,
included in the accompanying Management’s Report on Internal Control over
Financial Reporting. Our responsibility is to express an opinion on
the Partnership's internal control over financial reporting based on our
audit.
We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether
effective internal control over financial reporting was maintained in all
material respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk that a material
weakness exists, testing and evaluating the design and operating effectiveness
of internal control based on the assessed risk, and performing such other
procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A
company's internal control over financial reporting is a process designed by, or
under the supervision of, the company's principal executive and principal
financial officers, or persons performing similar functions, and effected by the
company's board of directors, management, and other personnel to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A company's internal control
over financial reporting includes those policies and procedures that (1) pertain
to the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial
statements.
Because
of the inherent limitations of internal control over financial reporting,
including the possibility of collusion or improper management override of
controls, material misstatements due to error or fraud may not be prevented or
detected on a timely basis. Also, projections of any evaluation of the
effectiveness of the internal control over financial reporting to future periods
are subject to the risk that the controls may become inadequate because of
changes in conditions, or that the degree of compliance with the policies or
procedures may deteriorate.
In our
opinion, the Partnership maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2007, based on the
criteria established in Internal Control — Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission.
We have
also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated financial statements and
financial statement schedule as of and for the year ended December 31, 2007 of
the Partnership and our report dated March 14, 2008 expressed an unqualified
opinion on those financial statements and financial statement schedule and
included an explanatory paragraph regarding the Partnership's adoption of new
accounting standards.
DELOITTE
& TOUCHE LLP
Houston,
Texas
March 14,
2008
Item
9B. Other Information
Item
3.02. Unregistered Sales of Equity Securities.
On
December 10, 2007, we sold 734,732 common units to our general partner for $15.5
million in a private transaction that was exempt from the registration
requirements of the Securities Act of 1933, pursuant to Section 4(2) thereof.
This sale, made concurrently with a public offering, was made pursuant to our
general partner's preemptive rights under Section 5.6 of our partnership
agreement. We used the proceeds from this sale to pay down our credit
facility.
Part
III
Item
10. Directors, Executive Officers 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 one director so long as
it holds 10% of our common units and two directors so long as it holds 35% 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 29, 2008
our general partner has nine directors. Denbury, indirectly, elects all members
to the board of directors of our general partner other than any Davison
appointees. The independence standards established by the American
Stock Exchange, or AMEX, require us to have at least three independent directors
on the board of directors. As we previously disclosed and have
reported to AMEX, in December, 2007, one of our
independent directors resigned. We expect to replace that director
during the first quarter of 2008. (See Item 13. Certain Relationships
and Related Transactions, and Director Independence below.) AMEX does
not require a listed limited partnership like us to have a majority of
independent directors on the board of directors 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 AMEX, 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. We expect to add another non-employee director
to the Compensation Committee in the first quarter of 2008. 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 AMEX and the
Securities Exchange Act of 1934, as amended. Susan O. Rheney and
J Conley Stone serve as the members of the audit committee. We expect
to add another independent director to the Audit Committee in the first quarter
of 2008. 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:
|
|
·
|
oversees
our anonymous complaint procedure established for our
employees;
|
|
|
·
|
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
|
Our independent registered public
accounting firm is given unrestricted access to the audit committee. The
Board of Directors 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 AMEX 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
|
55
|
Director
and Chairman of the Board
|
||
|
Grant
E. Sims
|
52
|
Director
and Chief Executive Officer
|
||
|
Mark
C. Allen
|
40
|
Director
|
||
|
James
E. Davison
|
70
|
Director
|
||
|
James
E. Davison, Jr.
|
41
|
Director
|
||
|
Ronald
T. Evans
|
45
|
Director
|
||
|
Susan
O. Rheney
|
48
|
Director
|
||
|
Phil
Rykhoek
|
51
|
Director
|
||
|
J.
Conley Stone
|
76
|
Director
|
||
|
Joseph
A. Blount, Jr.
|
47
|
President
and Chief Operating Officer
|
||
|
Ross
A. Benavides
|
54
|
Chief
Financial Officer, 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 of our general
partner 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.
James E.
Davison has served
as a director of our general partner since July 2007. Mr. Davison has
served as chairman of the board of Davison Transport, Inc. for over
30 years. He also serves as President of Sunshine Oil and 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
committee.
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.
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.
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. In such capacity, Mr. Blount oversaw the worldwide
marketing of Unocal’s natural gas, crude oil and condensate resources, the
development and management of its pipeline, terminal and storage assets, and its
commodity risk management activities. Upon the acquisition of Unocal
by Chevron in September of 2005, Mr. Blount left to pursue personal interests,
including investments.
Ross A.
Benavides has served as Chief Financial Officer of our general partner since
October 1998. He has served as General Counsel and Secretary since
December 1999.
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 American Stock Exchange. Based solely
on our review of the copies of such reports received by us, or written
representations from certain reporting persons that no Forms 5 was required for
those persons, we believe that during 2007 our officers and directors complied
with all applicable filing requirements in a timely manner.
Item
11. Executive Compensation
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. See "Certain Relationships and Related
Transactions."
Compensation
Discussion and Analysis
The
Compensation Committee of our board of directors, or the Committee, currently
consists of the Chairman of the Board 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 chief executive
officer and other executive officers. 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.
We have
two classes of executive officers for which we have applied distinct
compensation strategies. The Senior Executives are Grant E. Sims, our
chief executive officer and Joseph A. Blount, Jr., our president and chief
operating officer. The Other Executives are Ross A. Benavides, our
chief financial officer and general counsel and Karen N. Pape, our vice
president and controller. The treatment of the two classes of
executive officers are addressed separately below.
Objectives
of the Compensation Program. 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. We reward employees primarily for the effort and results
of the team or Partnership as a whole, rather than compensating only for
individual performance.
The
elements of the compensation program for our Senior Executives consist
of:
|
|
·
|
base
salaries,
|
|
|
·
|
an
ability to earn an interest in our general partnership interest and our
incentive distribution rights, referred to as the General Partner
Incentive Interest below, and
|
|
|
·
|
other
compensation (including contributions to the 401(k) plan and annual term
life insurance premiums).
|
The
elements of our Company-wide compensation program that applies to the Other
Executives and to certain other employees except the Senior
Executives consist of:
|
|
·
|
base
salaries,
|
|
|
·
|
cash
bonuses (performance-based cash incentive compensation including a Bonus
Plan, discretionary bonus awards, and a Retention
Plan),
|
|
|
·
|
Stock
Appreciation Rights Plan,
|
|
|
·
|
Long
Term Incentive Plans (phantom units and distibution equivalent
rights),
|
|
|
·
|
a
Severance Protection Plan, and
|
|
|
·
|
other
compensation (including contributions to the 401(k) plan and annual term
life insurance premiums).
|
As
described in more detail below, we believe that the combination of base
salaries, cash bonuses, Long-Term Incentive Plans and the General Partner
Incentive Interest Plan 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 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. Our Stock
Appreciation Rights Plan and 2007 Long Term Incentive Plan are linked primarily
to the appreciation in our common unit price. The General Partner
Incentive Interest Plan that has the potential to provide ownership interests in
our general partnership interest and our incentive distribution rights to our
Senior Executives is based on the completion of accretive third-party
acquisitions.
In the
event of a financial statement restatement, we do not currently have a specific
policy or penalty in most of our compensation programs. However, such
an event would likely affect the Bonus Plan and awards under our Stock
Appreciation Rights and 2007 Long-Term Incentive Plan by the Committee each year
because these plans include consideration of overall company
performance.
Senior Executives
During
2006, we determined that it was in the best interest of our general partner and
our unitholders for our executives to focus increased attention on growing our
business through transactions with parties other than Denbury. We
believe that the value created for our general partner and for the common
unitholders would be enhanced if we were to grow our business by making
significant third-party investments (i.e. acquisitions, investments in joint
ventures, subsequent organic growth projects, etc.) For MLPs, value
is created for the unitholders by generating sustainable, long-term, growing
distributions. To generate distribution growth, we believe we will
need to deploy significant capital, as we currently do not have sufficient
organic growth opportunities to generate the distribution growth we want to
achieve.
In order
to implement this strategy, the Senior Executives were hired on August 8,
2006. As of November 26, 2007, Brad N. Graves, our former Executive
Vice President of Business Development and one of our initial Senior Executives,
was no longer employed by us. The compensation program for those
executives, in the form of base salaries and the General Partner Incentive
Interest (described below), is designed to reward them for growing our business
by making accretive third-party acquisitions. A significant
portion of the compensation awarded to the Senior Executives is expected to
ultimately come from this equity based General Partner Incentive
Interest.
When the
Senior Executives were hired, the Senior Executives and Denbury agreed to
negotiate contracts that would provide an opportunity for the Senior Executives
to earn up to 20% of the general partner interests based on the conceptual terms
described below under “General Partner Incentive Interests”. However,
the parties have not completed such negotiations and entered into such
agreements for a myriad of factors, including time and resource constraints, the
parties’ inability to agree to mechanics relating to certain terms, and the
parties’ willingness to consider terms that were not originally contemplated,
which terms might have the effect of simplifying the arrangement and achieving
the intended objectives with more efficient and effective methods. It is likely
that the general partner interest plan will contain a correlation between
earning the general partner interest with the successful completion of
non-Denbury acquisitions and/or other organic growth that earn a reasonable rate
of return (i.e. growth of the Partnership unrelated to Denbury), but that the
vesting, measurement, and other ways that such Partnership performance is
measured could be significantly different than as described
below. Although the parties expect to negotiate and complete a
mutually acceptable compensation arrangement, there is no guarantee that they
will. Further, with the departure of Mr. Graves, the aggregate
general partner incentive interest that will available to the remaining two
Senior Executives will be reduced accordingly to approximately
14.4%.
Although
the agreements related to the General Partner Interest have not been agreed to
and completed as described above and therefore the amount of compensation earned
to date by the Senior Executives is uncertain and difficult to measure, we have
accrued $3.4 million of compensation in 2007 for the Senior
Executives. This amount could change significantly in the future
depending on the final terms of the arrangement.
The terms
described below are summaries of the conceptual terms included in the initial
employment offer when the Senior Executives were employed in August
2006.
Base
Salaries. Our General Partner agreed to negotiate employment
agreements with the Senior Executives for a four-year term with provisions
customary for the industry (including at least the same fringe benefits, other
than participation in the cash bonus plan and SAR plan, as are provided to other
executive officers of our general partner). The base salaries for the
Senior Executives were determined as an aggregate amount of $810,000, to be
allocated among the three executives at the discretion of the chief executive
officer. The aggregate salary for calendar 2007 was allocated
to Messrs. Sims, Blount, and Graves in the amounts of $310,000, $270,000, and
$230,000 per year, respectively. The aggregate salaries will
increase, if our market capitalization increases for consecutive 90 day periods,
to: $600 million market capitalization ($900,000 annual aggregate salaries); to
$1.0 billion ($990,000 annual aggregate salaries); and above $1.0 billion
(annual aggregate salary increases of 10 percent for each $300 million market
capitalization increase), with the aggregate amounts to be adjusted for the
departure of Mr. Graves. The base salary was based on several
factors. These factors include our objectives to make third-party
acquisitions, the nature and responsibility of the positions (including our size
and complexity), the expertise of the three executives, the track record of the
Senior Executives in creating value at other MLPs or midstream businesses, and
the competitiveness of the marketplace. We believe we were competing
to hire Mr. Sims with private equity firms seeking to develop midstream energy
MLPs. We believe that the aggregate compensation payable to our
Senior Executives is comparable to what they potentially would have been offered
by private equity firms for similar positions. The formula for salary
increases was designed to reward the Senior Executives if they are successful in
growing our business and to increase their compensation to be commensurate with
the scope of their responsibilities in leading a larger enterprise.
General
Partner Incentive Interests. Our General Partner agreed to negotiate
other contracts with the Senior Executives that would include the following
conceptual terms relating to the ability of the Senior Executives to earn up to
14.4% (originally 20% before the departure of Mr. Graves) of the General
Partner’s incentive distribution rights and general partner interest (which
currently are owned by a wholly-owned subsidiary of Denbury) if the Senior
Executives completed acquisition transactions from parties other than affiliates
of our general partner that earn (using a look-back provision) a minimum
un-levered internal rate of return of at least 8 percent. In our judgment, the
ability to earn up to a 14.4 percent equity position in the General Partner
Incentive Interest was intended to be comparable to the earn-in provision that
potentially would be offered by private equity firms under similar
circumstances. Earning and vesting of the General Partner
Incentive Interest was based on the following schedule (which has been adjusted
to reflect the departure of Mr. Graves):
|
Cumulative
|
Percentage
|
|
|
Amount
of
|
Vested
in
|
|
|
Acquisitions
|
General
|
|
|
from
|
Partner
|
|
|
Third
Parties
|
Interest
|
|
|
$150
million
|
1.44%
|
|
|
$300
million
|
2.88%
|
|
|
$450
million
|
4.32%
|
|
|
$600
million
|
5.76%
|
|
|
$750
million
|
7.20%
|
|
|
$900
million
|
8.64%
|
|
|
$1,050
million
|
10.08%
|
|
|
$1,200
million
|
11.52%
|
|
|
$1,350
million
|
12.96%
|
|
|
$1,500
million
|
14.40%
|
Additionally,
if approved by Denbury’s board of directors, our audit committee (including
receipt of required fairness opinions for both parties), and Denbury’s lenders,
Denbury agreed to sell to Genesis midstream CO2 assets
owned by Denbury (expected at that time to be two existing and one planned
CO2
pipeline with an estimated aggregate transaction value of approximately $300
million), and contract for exclusive use of those assets on commercially
acceptable terms (including preserving Denbury’s uninterrupted exclusive use of
those assets in the event of Genesis’ sale or bankruptcy) at an expected rate of
return of 12 percent to Genesis over 12 years or longer, but only if, at the
time of each sale by Denbury, the sale will not make the ratio of gross value of
(1) consummated transactions, that at the time of sale are expected to earn a
minimum un-levered internal rate of return of 8 percent to (2) assets sold by
Denbury to be less than 1.5 to 1.
The
General Partner Incentive Interests was intended to create a long-term non-cash
equity-based compensation plan for the Senior Executives. As the
Senior Executives earn a portion of the general partner interest, they also will
earn correlative incentive distribution rights. Consequently, on a
long-term basis, the Senior Executives will be incentivized to grow the
distributions for our common unitholders. Further, the compensation
from our General Partner Incentive Interest would effectively come from Denbury
rather than from us, and therefore it will not affect Available Cash before
Reserves or cash flow of the Partnership..
While the
Senior Executives would be incentivized to make accretive third-party
acquisitions, the earning of interests in our General Partner Incentive Interest
by the Senior Executives is not contemplated to be dependent upon increasing our
distributions. Our distribution policy will continue to be made by
our Board of Directors based upon the determination that we are generating
sustainable cash flow after adjustments for appropriate reserves. No
assurance can be made that our distributions will be increased following the
completion of significant third-party acquisitions or drop-down transactions
with Denbury.
The
conceptual terms also contemplates that the Senior Executives would have change
of control protection on 11.5% (originally 16% before the departure of Mr.
Graves) of the equity interest in our general partner (if not already vested,
but capped at 11.5%) , triggered by a change of control of Denbury or our
general partner.
We have
reimbursed the Senior Executives for out-of-pocket transaction costs incurred in
connection with the consummation of the employment agreements and general
partner interest agreement up to an aggregate amount of $75,000.
The
Other Executives
The Other
Executives participate in compensation programs that are available to our entire
employee population. The elements of the Company-wide compensation
program consist of competitive base salaries, a Bonus Plan, a Stock Appreciation
Rights plan, a Severance Protection plan, and other benefits. Additionally the
Other Executives participated in a Retention plan with a group of senior
management personnel during 2006 and the first eight months of
2007. The Other Executives also participate in our 2007 Long-Term
Incentive Plan.
Base
Salaries. 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 chief
executive officer. 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
components of their compensation plan are consistent among employee groups and
generally are proportional to base salary and bonuses. During 2007,
the Compensation Committee approved salary increases effective as of the close
of the Davison transaction in the amounts of $27,500 or 13.75%, and $25,000 or
14.29%, for Ross Benavides and Karen Pape, respectively. The salary
increases were based on the recommendation of the CEO due in significant part to
the Other Executives performance prior to and increased responsibility resulting
from the Davison acquisition. The Other Executives did not receive
salary increases for 2008. For 2008, all other employees received
average salary increases of approximately 4 percent.
Bonus
Plan. In May 2003, the Compensation Committee of the Board of
our general partner approved a Bonus Plan for all employees of our general
partner. The Senior Executives are excluded from participation in the
Bonus Plan. The Bonus Plan is paid at the discretion of our Board of
Directors based on the recommendation of Compensation 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
Compensation Committee on a company-wide basis, the Other Executives receive
bonuses only if all employees receive bonuses.
The Bonus
Plan is based on the amount of money we generate for distributions to our
unitholders, and is measured on a calendar-year basis. We will make a
contribution to the Bonus Pool every time we have earned $2,042,288 of Available
Cash (as defined in our partnership agreement) before Reserves excluding the
effects of the bonus accrual made so far during the year for bonuses and such
other adjustments as are made from time to time in the sole discretion of the
Compensation Committee. Each $2,042,288 earned is referred to as a
“Bucket”. We expect the primary reason for adjusting the size of the
Bucket will be for issuance of additional equity, as discussed
below.
If we
issue additional common units, the Bucket size will be increased proportionally
based on the number of additional common units issued. Whenever we
earn a Bucket, we will contribute a portion of that Bucket to the Bonus
Pool. For each additional Bucket, a larger percentage of the Bucket
will be contributed to the Bonus Pool. Contributions will be deducted
from the Bonus Pool if Available Cash before Reserves earned for the year
decreases. A maximum of nine Buckets are available under the Bonus
Plan. There will be no contribution for partial Buckets.
Contributions
to the Bonus Pool will be made in accordance with the following
schedule:
|
Year-to-Date
|
|||||||||||||||
|
Available
|
Year-to-Date
|
||||||||||||||
|
Contribution
|
Cash
before
|
Contributions
|
|||||||||||||
|
Bucket
|
Bucket
|
to
Bonus
|
Reserves
and
|
to
Bonus
|
|||||||||||
|
Number
|
Size
|
Pool
|
Bonus
Accrual
|
Pool
|
|||||||||||
|
1
|
$ | 2,042,288 | $ | 60,000 | $ | 2,042,288 | $ | 60,000 | |||||||
|
2
|
$ | 2,042,288 | $ | 120,000 | $ | 4,084,576 | $ | 180,000 | |||||||
|
3
|
$ | 2,042,288 | $ | 120,000 | $ | 6,126,864 | $ | 300,000 | |||||||
|
4
|
$ | 2,042,288 | $ | 240,000 | $ | 8,169,152 | $ | 540,000 | |||||||
|
5
|
$ | 2,042,288 | $ | 300,000 | $ | 10,211,440 | $ | 840,000 | |||||||
|
6
|
$ | 2,042,288 | $ | 360,000 | $ | 12,253,728 | $ | 1,200,000 | |||||||
|
7
|
$ | 2,042,288 | $ | 360,000 | $ | 14,296,016 | $ | 1,560,000 | |||||||
|
8
|
$ | 2,042,288 | $ | 360,000 | $ | 16,338,304 | $ | 1,920,000 | |||||||
|
9
|
$ | 2,042,288 | $ | 360,000 | $ | 18,380,592 | $ | 2,280,000 | |||||||
The Bonus Pool will be distributed as
follows:
|
|
·
|
Each
eligible employee will receive a bonus after the end of the year equal to
a specified percentage of their year-to-date gross
wages. Certain compensation, such as 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
receive a bonus. The date of payment of the bonuses is at the
discretion of management, but bonuses will not be paid until after annual
earnings have been released to the
public.
|
|
|
·
|
There
are four 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 Compensation Committee based on the
recommendation of the chief executive officer. The Other
Executives are included in Level
Four.
|
|
|
·
|
The
percentage of adjusted year-to-date gross wages paid as a bonus will be a
function of the number of Buckets earned during the year and the
employee’s Participation Level in the Bonus Plan. The bonus
amount each employee is entitled to receive will be determined in
accordance with the table shown below. The bonus may be
adjusted up or down to reflect individual
performance.
|
|
|
·
|
The
total of all bonuses paid may not exceed the total Bonus
Pool. Should the amount of bonuses calculated in accordance
with the table below exceed the total Bonus Pool available, all calculated
bonuses will be reduced proportionately. Should the adjusted
amount of bonuses calculated in accordance with the table below be less
than the Bonus Pool, the Bonus Pool shall be reduced to the calculated
amount.
|
The bonus
percentage that each employee group will receive based on the number of Buckets
earned is as follows:
|
Cumulative Percentage
|
||||||||||||||||||||||||||||||||||||
|
Participation
|
1
|
2
|
3
|
4
|
5
|
6
|
7
|
8
|
9
|
|||||||||||||||||||||||||||
|
Level
|
Bucket
|
Buckets
|
Buckets
|
Buckets
|
Buckets
|
Buckets
|
Buckets
|
Buckets
|
Buckets
|
|||||||||||||||||||||||||||
|
One
|
0.495 | % | 1.480 | % | 2.470 | % | 4.460 | % | 6.000 | % | 7.000 | % | 8.000 | % | 9.000 | % | 10.000 | % | ||||||||||||||||||
|
Two
|
0.495 | % | 1.480 | % | 2.470 | % | 4.460 | % | 8.000 | % | 11.000 | % | 14.000 | % | 17.000 | % | 20.000 | % | ||||||||||||||||||
|
Three
|
0.495 | % | 1.480 | % | 2.470 | % | 4.460 | % | 8.000 | % | 15.000 | % | 20.000 | % | 25.000 | % | 30.000 | % | ||||||||||||||||||
|
Four
|
0.495 | % | 1.480 | % | 2.470 | % | 4.460 | % | 8.000 | % | 16.000 | % | 24.000 | % | 32.000 | % | 40.000 | % | ||||||||||||||||||
For 2007,
the Compensation Committee decided that the calculation of the number of Buckets
under the Bonus Plan would include only the Available Cash before Reserves
generated by the businesses owned and operated by the Partnership prior to the
acquisition of the Davison businesses and would not be adjusted for the equity
issued in the Davison transaction or in December 2007. Additionally,
the participants would include only the employees of the general partner in the
operations we owned prior to the Davison transaction. For 2007, we
achieved nine Buckets under the plan and paid total bonuses under the Bonus Plan
of $2.1 million or approximately 19 percent of total eligible
compensation. These bonuses were paid in March 2008.
The Bonus
Plan is designed to enhance our financial performance by rewarding employees for
achieving financial performance objectives that are aligned with the interests
of our unitholders. 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. The plan
is designed so that six buckets generate a bonus equal to 10 percent of total
base compensation if we generate sufficient Available Cash before Reserves and
after bonus compensation to meet our targeted minimum quarterly distribution of
$0.80 per unit on total units outstanding. The maximum of nine
buckets is designed to limit the bonus to approximately 20 percent of total
compensation and to limit the bonus to 40 percent of the compensation for the
highest compensated Group Four, to which the Other Executives are
assigned. 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.
The
Compensation Committee is reviewing the Bonus Plan and expects to make changes
to the plan that will affect the Other Executives. See additional
discussion in “Compensation Changes in 2008” below.
Retention
Plan. On August 29, 2006, the Board of Directors of our
general partner also approved retention bonuses for the Other Executives and
seven other management employees our general partner. Under this
plan, those individuals in the plan received retention bonuses in amounts
ranging from 20% to 35% of their base compensation levels as of August 29, 2006,
if they were still employed on September 1, 2007. Additionally, the
retention bonus paid in 2007 was included in the calculation of the bonus they
received for 2007, under the terms of our Bonus Plan. These retention bonuses
were designed to reward these individuals for their support in the transition of
the new Senior Executive Management Team. Retention bonuses under
this plan were paid to Mr. Benavides and Ms. Pape in the amounts of $68,250 and
$52,500, respectively. The Retention Plan ceased to exist after
payment of these retention bonuses in 2007.
Stock Appreciation Rights
Plan. In December 2003, the Board approved a Stock
Appreciation Rights plan or SAR plan. Under the terms of this plan,
all 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 Compensation Committee of the Board, 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.
Generally,
each participant will receive an allocation of a number of rights equal to the
authorized number of rights multiplied by a fraction, the numerator of which is
such participant’s maximum annual bonus under the Bonus Plan and the denominator
of which is the total of the maximum annual bonuses for all such participants
under the Bonus Plan. The Committee has discretion to adjust
individual allocations.
In 2003,
for the initial grant, we issued SARs equal to approximately 4.5 percent of our
outstanding units. Since that time awards have been equal to
approximately 1.125 percent of outstanding units (reduced by the number of units
that would have been granted to the Senior Executives had they participated in
the Plan). 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 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 very small, such that one small trade can occur and 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. This methodology is subject
to change for any grant in the future
Historically,
our new employees receive SAR grants at the end of the quarter following their
date of hire, with additional Awards to be granted each year as part of the
annual review of compensation by our Compensation
Committee. Beginning in 2008, employees involved in our
trucking-related operations will no longer receive SAR grants. An
employee’s initial Award generally vests 25% per year over a period of four
years, while annual Awards generally cliff vest 100% at four years from the
grant date. The goal of our long-term incentive program for all
employees is to provide each employee with awards that cliff vest each
year. Additional details describing the operation of the SAR
plan are included below.
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, 2007 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 and Other Executives.
Our
entire long-term incentive compensation plan for the Other Executives and
employees is made in the form of cash-based rather than equity-based
compensation. All of our employees and directors other than the
Senior Executives participate in the SAR plan. We are a
partnership. We believe that the administration of issuing small
numbers of partnership units to the entire employee population and the tax
reporting by the employees of taxable income from a partnership make it
excessively complex to administer an equity-based long-term incentive
plan. Consequently, we currently do not have any equity based
compensation plans for our Other Executives.
The 2007 Long-Term Incentive
Compensation Plan (2007 LTIP). 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 Compensation 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
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
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 Compensation
Committee.
The 2007
LTIP provides a means to assist our general partner and its affiliates in
retaining the services of employees and, possibly, our directors providing
services to us, our general partner and its affiliates and provide incentives
for them to devote their best efforts to our general partner and
us;
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. Although the general partner has no current intent to make award of
grants to our directors, the 2007 LTIP allows such grants to be made, which
would become available if in the future our general partner determines that
making such awards to directors is appropriate and in our best
interests.
For 2007,
the Compensation Committee approved awards granting phantom units with a total
value as of December 18, 2007 of $965,250 to seven employees of our general
partner. Grants were made to Mr. Benavides and Ms. Pape with values
in amounts of $225,000 (9,176 phantom units) and $200,000 (8,156 phantom units)
respectively, or approximately 100 percent of their base
salaries. The amounts awarded were entirely discretionary and were
based on the recommendation of the CEO due in significant part to their
performance prior to and increased responsibility resulting from the Davison
acquisition.
Severance
Benefits. We believe that companies should provide reasonable
severance benefits to employees. With respect to 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.
As
of November 26, 2007, Brad N. Graves, our former Executive Vice
President of Business Development was no longer employed by us. The
severance compensation paid to Mr. Graves consisted of a lump-sum payment of
$2.1 million. Our general partner made a cash contribution of $1.4
million to us to be used to offset the cost of a portion of the severance
payment to Mr. Graves.
Change of
Control. 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. Our Senior Executives are not covered under the
Severance Protection Plan, the 2007 LTIP or the Stock Appreciation Rights
Plan. Change in control protection will be provided for them in their
employment agreements and our general partner interest agreement when
completed. See the Senior Executive section above.
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
their annual salary and bonus, other members of management will receive two
times their annual salary and bonus, and all other employees will receive
between one-third to one and one-half times their annual salary and bonus
depending upon their salary level and length of service with us. All
employees will also receive medical and dental 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 plan also provides that if our Other Executive Officers are subject to
the “parachute payment” excise tax, 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.
Based
upon a hypothetical termination date of December 31, 2007, the change of control
termination benefits for our named executive officers (excluding Mr. Graves who
is no longer employed by us, and the Senior Executives for whom the terms of
their change in control benefits have not been completed) would have been as
follows (based on the closing price for our units of $23.50 at that
time):
|
Ross
A.
|
Karen
N.
|
|||||||
|
Benavides
|
Pape
|
|||||||
|
|
||||||||
|
If
termination date is between January 1, 2008 and December 30,
2008
|
||||||||
|
Severance
plan payment
|
$ | 966,177 | $ | 831,669 | ||||
|
Healthcare
and other insurance benefits
|
12,650 | 12,193 | ||||||
|
Fair
market value of stock appreciation rights
|
344,668 | 264,503 | ||||||
|
Fair
market value of phantom units
|
215,636 | 191,666 | ||||||
|
Total
|
$ | 1,539,131 | $ | 1,300,031 | ||||
|
If
termination date is between December 31, 2008 and December 31,
2009
|
||||||||
|
Severance
plan payment
|
$ | 966,177 | $ | 831,669 | ||||
|
Healthcare
and other insurance benefits
|
12,650 | 12,193 | ||||||
|
Fair
market value of stock appreciation rights
|
267,882 | 204,896 | ||||||
|
Fair
market value of phantom units
|
215,636 | 191,666 | ||||||
|
Total
|
$ | 1,462,345 | $ | 1,240,424 | ||||
Other Benefits. 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. 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 $66,792 in 2007 for our Senior
Executives and Other Executives.
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.
Board Process. During the fourth
quarter of each year, management reviews the entire company’s compensation,
based on recommendations from their subordinates, and makes a proposal to the
Committee. Final review of this recommendation is made by the
Committee at our normally-recurring December committee and board meetings,
although depending on the magnitude of the anticipated changes, there may be
several Committee meetings and discussions with management in advance of the
December meeting. The Committee approves all compensation and
long-term awards for all executive officers, considering the recommendation of
the Chief Executive Officer with regard to compensation for the Other
Executives. Our Committee also reviews and approves our overall
compensation programs for all employees or any significant changes to these
programs. This Committee is the administrator of all of our
compensation plans (other than our 401(k) plan, health and other fringe benefit
plans), including our Bonus Plan and Stock Appreciation Rights Plan under which
all of our long-term equity awards are granted. The Board of
Directors reviews and ratifies the compensation package based on a
recommendation from the Committee. Following approval of the entire
compensation program, salary increases have been made during the first quarter
of the following year, and bonuses are paid in early March of the following
year, and the annual recurring SAR awards are made effective on the last
business day of December.
Compensation Changes for
2008. For 2008, the Compensation Committee and our Board of
Directors may make significant changes to the compensation plans for
us. After the Davison transaction, the Compensation Committee feels
that we have a management team and an employee base that are much larger and are
more diversified in terms of skill sets and opportunities to contribute to
meeting our objectives. Based on this diversified work force, the
Compensation Committee intends to address the overall compensation plans during
2008 to determine the extent to which the plans should be tailored to the
different employee bases in each business segment or components of each business
segment.
In
December 2007, the Compensation Committee discussed making changes to the Bonus
Plan that will give the Other Executives the opportunity to earn bonuses up to
100% of their individual base salaries. The focus in the new bonus
plan is expected to be more on individual contribution and performance than the
current bonus plan. Further discussion of the restructuring of the
plan will occur in 2008.
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 recommended to the Board, and
the Board has 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
Summary
Compensation Table
The
following table summarizes certain information regarding the compensation paid
or accrued by Genesis during 2007 to those persons who served as chief executive
officer and chief financial officer, and the other two executive officers at the
end of 2007, and a former executive officer whose compensation exceeded the
compensation of the other two executive officers in 2007 (the “Named Executive
Officers”).
|
2007
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
|
2007
|
$ | 310,000 | - | - | - | - | 1,838,476 | $ | 2,148,476 | ||||||||||||||||||||
|
Chief
Executive Officer (Principal Executive Officer)
|
2006
|
$ | 112,077 | - | - | - | - | 56 | $ | 112,133 | ||||||||||||||||||||
|
Ross
A. Benavides
|
2007
|
$ | 211,000 | $ | 68,250 | $ | 2,511 | $ | 100,448 | $ | 111,581 | $ | 16,680 | $ | 510,470 | |||||||||||||||
|
Chief
Financial Officer and General Counsel (Principal Financial
Officer)
|
2006
|
$ | 195,000 | - | - | $ | 101,231 | $ | 78,000 | $ | 16,668 | $ | 390,899 | |||||||||||||||||
|
Joseph
A., Blount, Jr.
|
2007
|
$ | 270,000 | - | - | - | - | $ | 1,618,984 | $ | 1,888,984 | |||||||||||||||||||
|
President
& Chief Operating Officer
|
2006
|
$ | 97,615 | - | - | - | - | $ | 4,449 | $ | 102,064 | |||||||||||||||||||
|
Karen
N. Pape
|
2007
|
$ | 184,000 | $ | 52,500 | $ | 2,232 | $ | 77,139 | $ | 94,577 | $ | 16,680 | $ | 427,128 | |||||||||||||||
|
Senior
Vice President & Controller (Principal Accounting
Officer)
|
2006
|
$ | 150,000 | - | - | $ | 77,430 | $ | 60,000 | $ | 15,032 | $ | 302,462 | |||||||||||||||||
|
Brad
N. Graves
|
2007
|
$ | 218,000 | - | - | - | - | $ | 2,109,972 | $ | 2,327,972 | |||||||||||||||||||
|
Former
Executive Vice President, Business Development
|
2006
|
$ | 83,154 | - | - | - | - | $ | 1,871 | $ | 85,025 | |||||||||||||||||||
|
|
(1)
|
Amounts
in this column 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
2007 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, 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 at December 31, 2007 and 2006 was
10%.
|
|
|
(4)
|
Amounts
in this column represent the amount that will be paid to the Named
Executive Officer as an award under our Bonus Plan. In each
case with an amount shown, the amount is equal to 40% of the sum of the
Named Executive Officer’s annual salary and the retention bonus paid to
that officer in September 2007. Mr. Sims and Mr. Blount do not
participate in the Bonus Plan.
|
|
|
(5)
|
Information
on the amounts included in this column is included in the table
below.
|
|
Year
|
401(k)
Matching Contributions (a)
|
401(k)
Profit-Sharing Contributions (b)
|
Insurance
Premiums (c)
|
Severance
Payment (d)
|
Other
Compensation (e)
|
||||||||||||||||
|
Grant
E. Sims
|
2007
|
$ | - | $ | 6,600 | $ | 180 | $ | - | $ | 1,831,696 | ||||||||||
|
2006
|
$ | - | $ | - | $ | 56 | $ | - | $ | - | |||||||||||
|
Ross
A. Benavides
|
2007
|
$ | 9,900 | $ | 6,600 | $ | 180 | $ | - | $ | - | ||||||||||
|
2006
|
$ | 9,900 | $ | 6,600 | $ | 168 | $ | - | $ | - | |||||||||||
|
Joseph
A. Blount, Jr.
|
2007
|
$ | 9,900 | $ | 6,600 | $ | 180 | $ | - | $ | 1,602,304 | ||||||||||
|
2006
|
$ | 4,393 | $ | - | $ | 56 | $ | - | $ | - | |||||||||||
|
Karen
N. Pape
|
2007
|
$ | 9,900 | $ | 6,600 | $ | 180 | $ | - | $ | - | ||||||||||
|
2006
|
$ | 8,264 | $ | 6,600 | $ | 168 | $ | - | $ | - | |||||||||||
|
Brad
N. Graves
|
2007
|
$ | 9,792 | $ | - | $ | 180 | $ | 2,100,000 | $ | - | ||||||||||
|
2006
|
$ | 1,815 | $ | - | $ | 56 | $ | - | $ | - | |||||||||||
Amounts
in this table represent:
|
(a)
|
Matching
contributions by Genesis to our 401(k) plan on each Named Executive
Officer’s behalf.
|
|
(b)
|
Profit-sharing
contributions by Genesis to our 401(k) plan on each Named Executive
Officer’s behalf.
|
|
(c)
|
Term
life insurance premiums paid by Genesis on each Named Executive Officer’s
behalf.
|
|
(d)
|
Severance
paid to Mr. Graves when he ceased to be employed by
us. While the expense for this severance was recognized
by us, Denbury contributed $1.4 million to its general partner capital
account for a portion of the cash
cost.
|
|
(e)
|
Represents
an amount for the estimated value of the compensation earned in 2007 under
the proposed arrangements in the General Partner Incentive Interests
discussion above. While the General Partner Incentive
Interests may ultimately qualify as an equity award under SFAS 123(R),
there is no mutual understanding of the terms of the award at December 31,
2007; therefore an amount could not be calculated in accordance with the
provisions of SFAS 123(R). The expense recorded for this
arrangement was an amount agreed to by the parties as a fair
representation of the value provided and earned in 2007. As the
purpose of the General Partner Incentive Interests 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.
|
Long
Term Incentive Plan
As
discussed in the Compensation Discussion and Analysis, our unitholders approved
the Genesis Energy, Inc. 2007 Long Term Incentive Plan on December 18, 2007
which provides for awards of Phantom Units and Distribution Equivalent Rights to
non-employee directors and employees of Genesis Energy, Inc., 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 Compensation 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
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
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 Compensation
Committee.
Stock
Appreciation Rights Plan
As
discussed in the Compensation Discussion and Analysis, we have a Stock
Appreciation Rights plan or SAR for all employees, with the exception of our new
senior management team. Under the terms of this plan, all regular,
full-time active employees and the members of the Board are eligible to
participate in the plan. The plan is administered by the Compensation
Committee, who shall determine, in its full discretion, 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. The initial award to a participant will vest
one-fourth each year beginning with the first anniversary of the grant date of
the award. Subsequent awards to participants will vest on the fourth
anniversary of the grant date. 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
Plan
As
discussed in the Compensation Disclosure and Analysis, we have a Bonus Plan for
all employees of our general partner, with the exception of our new senior
management team. This non-equity incentive plan provides for our
Other Executives to receive bonuses ranging from zero to forty percent based on
our achieving certain levels of Available Cash before Reserves and bonus
expense. The table below shows the minimum and maximum amounts that each of the
Executive Officers named in the table could have achieved for
2007. The maximum amounts were achieved and paid to the individuals
in March 2008.
The
following tables show the phantom units and non-equity incentive plan awards
granted to the other Executive Officers for 2007 and the outstanding SARs and
phantom units awards at December 31, 2007 that were issued to
our other Executive Officers. Information on rights granted
to non-employee directors is included in the section entitled Director
Compensation. These tables do not include the awards made to Mr.
Benavides and Ms. Pape in February 2008 of 5,448 and 4,790 stock appreciation
rights, respectively, at a strike price of $20.92 per unit.
|
Grants
of Plan-Based Awards in Fiscal Year 2007
|
||||||||||||||||||||
|
Estimated
Possible Payouts
Under
Non-Equity Incentive
Plan
Awards
(1)
|
All
Other Stock
Awards:
|
Grant
Date Fair
|
||||||||||||||||||
|
Name
|
Grant
Date
|
Board
Approval Date
|
Threshold
$
|
Maximum
$
|
Number
of
Shares
of
Stock or Units (#) (2)
|
Value
of
Stock
and
Option Awards (3)
|
||||||||||||||
|
Ross
A. Benavides
|
12/18/2007
|
12/18/2007
|
9,176 | $ | 196,733 | |||||||||||||||
|
5/27/2003
|
$ | 0 | $ | 111,581 | ||||||||||||||||
|
Karen
N. Pape
|
12/18/2007
|
12/18/2007
|
8,156 | $ | 174,865 | |||||||||||||||
|
5/27/2003
|
$ | 0 | $ | 94,577 | ||||||||||||||||
|
(1)
|
Under
the terms of our Bonus Plan, the Executive Officers named in this table
were eligible to receive cash bonus awards in an amount that ranged from
no award to the amounts shown as the Maximum, which represent 40% of the
sum of their base salary and the retention bonus they were paid in
September 2007. The amount of the award is based on the amount
of Available Cash before bonus expense generated by us for the
year. Each of these Executive Officers received the maximum
award for 2007.
|
|
(2)
|
The
amounts in this column represent the phantom units granted to the named
Executive Officer during 2007.
|
|
(3)
|
The
amounts in this column represent the fair value of the award on the date
of the grant, December 18, 2007, as calculated in accordance with the
provisions of SFAS 123(R).
|
|
Oustanding
Equity Awards at 2007 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 ($)
|
Stock
Appreciation
Rights
Expiration
Date
|
Number
of Units of Phantom Units That Have Not Vested (#) (2)
|
Market
Value of Phantom Units That Have Not Vested ($)
|
|||||||||||||||
|
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
|
|||||||||||||||||
| 9,176 | $ | 215,636 | |||||||||||||||||||
|
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
|
|||||||||||||||||
| 8,156 | $ | 191,666 | |||||||||||||||||||
|
(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 and December 31,
2010.
|
|
(2)
|
These
phantom units vest on December 18,
2010.
|
Director
Compensation
The table
below reflects compensation for the directors. Mr. Goodman resigned
as a director of Genesis in December 2007. Directors who are
employees of our general partner, like Mr. Sims, do not receive compensation for
service as a director. During 2007, compensation for the three
independent directors consisted of an annual fee of $40,000. The
Audit Committee Chairman received an additional annual fee of
$4,000. We paid Denbury fees totaling $120,000 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 of
Directors 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 $30,000 were paid to Denbury.
|
Director
Compensation in Fiscal 2007
|
||||
|
Name
|
Fees
Earned or Paid in Cash ($)(1)
|
|||
|
Mark
C. Allen (2)
|
$ | 40,000 | ||
|
James
E. Davison
|
$ | 24,000 | ||
|
James
E. Davison, Jr.
|
$ | 24,000 | ||
|
Ronald
T. Evans (2)
|
$ | 38,000 | ||
|
Herbert
I. Goodman
(3)
|
$ | 57,000 | ||
|
Susan
O. Rheney
|
$ | 57,000 | ||
|
Gareth
Roberts (2)
|
$ | 34,000 | ||
|
Phil
Rykhoek (2)
|
$ | 38,000 | ||
|
J.
Conley Stone
|
$ | 54,000 | ||
|
(1)
|
Amounts
include annual retainer fees and fees for attending
meetings.
|
|
(2)
|
Fees
were paid in cash for these directors to
Denbury.
|
|
(3)
|
Mr.
Goodman resigned as a director of our general partner in December
2007.
|
The
outstanding awards of stock appreciation rights to the directors of our general
partner are shown in the table below.
|
Oustanding
Equity Awards at 2007 Fiscal Year-End to Directors
|
|||||||||||||
|
Stock
Appreciation Rights
|
|||||||||||||
|
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
|
|||||||||
|
Mark
C. Allen (1)
|
644 | 1,932 | $ | 15.77 |
9/29/2016
|
||||||||
| - | 1,000 | $ | 19.57 |
12/29/2016
|
|||||||||
|
Ronald
T. Evans (2)
|
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
|
|||||||||
|
Herbert
I. Goodman (3)
|
3,092 | - | $ | 9.26 |
12/12/2008
|
||||||||
| 735 | - | $ | 12.48 |
12/12/2008
|
|||||||||
| 781 | - | $ | 11.17 |
12/12/2008
|
|||||||||
| 1,000 | - | $ | 19.57 |
12/12/2008
|
|||||||||
|
Susan
O. Rheney
(2)
|
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
|
|||||||||
|
Gareth
Roberts (2)
|
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
|
|||||||||
|
Phil
Rykhoek (4)
|
1,932 | 644 | $ | 11.00 |
8/25/2014
|
||||||||
| - | 612 | $ | 12.48 |
12/31/2014
|
|||||||||
| - | 651 | $ | 11.17 |
12/31/2015
|
|||||||||
| - | 1,000 | $ | 19.57 |
12/29/2016
|
|||||||||
|
J.
Conley Stone (2)
(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)
|
Mr.
Allen’s first award will vest one-fourth annually beginning September 29,
2007 through September 29, 2010. Mr. Allen’s second award will
vest on January 1, 2011.
|
|
(2)
|
The
unexercisable rights of this director vest on the following dates in the
order they are listed: January 1, 2009, January 1, 2010 and
January 1, 2011.
|
|
(3)
|
Mr.
Goodman qualified under the provisions of the SAR Plan for retirement;
therefore upon his resignation from the Board of our general partner, he
is vested in all outstanding awards. He has until December 12,
2008 to exercise these awards.
|
|
(4)
|
The
unexercisable portion of Mr. Rykhoek’s first award will vest 644 rights on
August 25, 2008. Mr. Rykhoek’s remaining awards will vest on
January 1, 2009, January 1, 2010 and January 1,
2011.
|
|
(5)
|
Mr.
Stone exercised 2,319 rights in 2007 and received $57,836 in value upon
exercise.
|
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 Ownership 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 29, 2008,
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
|
|||||||||
|
Number
|
Percent
|
||||||||
|
Title
of Class
|
Name
and Address of Beneficial Owner
|
of
Units
|
of
Class
|
||||||
|
Genesis
Energy, L.P.
|
Genesis
Energy, Inc.
|
2,829,055 | 7.4 | ||||||
|
Common
Units
|
Gareth
Roberts
|
10,000 | * | ||||||
|
Grant
E. Sims (1)
|
1,000 | * | |||||||
|
James
E. Davison (2)
|
1,434,416 | 3.7 | |||||||
|
James
E. Davison, Jr. (3)
|
3,728,217 | 9.7 | |||||||
|
Ronald
T. Evans
|
11,000 | * | |||||||
|
Susan
O. Rheney
|
700 | * | |||||||
|
Phil
Rykhoek
|
5,000 | * | |||||||
|
J.
Conley Stone
|
2,000 | * | |||||||
|
Ross
A. Benavides (4)
|
18,459 | * | |||||||
|
Karen
N. Pape (5)
|
11,542 | * | |||||||
|
All
directors and executive officers as a group (12 in
total)
|
5,222,334 | 13.7 | |||||||
|
Davison
Petroleum Products, LLC (6) (7)
(8)
|
9,225,618 | 24.1 | |||||||
|
Fargo
Transport, Inc. (6) (8)
(9)
|
1,565,690 | 4.1 | |||||||
|
Davison
Terminal Service, Inc. (6)
(10)
|
1,010,835 | 2.6 | |||||||
|
Sunshine
Oil and Storage, Inc. (6)
(10)
|
423,581 | 1.1 | |||||||
|
Transport
Company (6)
(8)
|
393,345 | 1.0 | |||||||
|
Swank
Capital, LLC, Swank
|
|||||||||
|
Energy
Income Advisors,
|
|||||||||
|
L.P.
and Mr. Jerry V. Swank (11)
|
3,627,906 | 9.5 | |||||||
|
3300
Oak Lawn Ave., Suite 650
|
|||||||||
|
Dallas,
Texas 75219
|
|||||||||
|
(1)
|
Common
units are held by Mr. Sims’ father. Mr. Sims disclaims
beneficial ownership of these
units.
|
|
(2)
|
James
E. Davison is the sole stockholder of Davison Terminal Service, Inc. and
Sunshine Oil and Storage, Inc., which directly own 1,010,835 and 423,581
units, respectively.
|
|
(3)
|
James
E. Davison, Jr. is a one-third equity holder in Davison Petroleum
Products, L.L.C., Fargo Transport, Inc. (formerly known as Davison
Transport, Inc.), and Transport Company, Inc. These entities
own 9,225,618, 1,565,690 and 393,345 units, respectively. We
have been granted a lien on certain of these units as discussed in
footnote 7 below.
|
|
(4)
|
Includes
9,176 phantom units which will vest on December 18,
2010.
|
|
(5)
|
Includes
8,156 phantom units which will vest on December 18,
2010.
|
|
(6)
|
The
address for this entity is PO Box 607, Ruston,
Louisiana 71273.
|
|
(7)
|
We
have been granted a lien on 5,383,684 of these units to secure the Davison
unitholders indemnification obligations to us under the terms of our
acquisition of the Davison
businesses.
|
|
(8)
|
This
entity is owned equally by James E. Davison, Jr., Todd A. Davison and
Steven K. Davison, all of whom are sons of James E.
Davison.
|
|
(9)
|
This
entity was formerly known as Davison Transport,
Inc.
|
|
(10)
|
This
entity is owned by James E.
Davison.
|
|
(11)
|
Information
based on Schedule 13G filed with the SEC on February 14,
2008. 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.
|
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, Inc. and all officers and directors is 500
Dallas, Suite 2500, Houston, Texas, 77002.
Beneficial
Ownership of General Partner Interest
Genesis
Energy, Inc. owns all of our 2% general partner interest and all of our
incentive distribution rights, in addition to 7.4% of our
units. Genesis Energy, Inc. is a wholly-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 Relationships and Related Transactions,
and Director Independence
Our
General Partner
Our
operations are managed by, and our employees are employed by, Genesis Energy,
Inc., 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 2007, these reimbursements totaled $22.5
million. As of December 31, 2007, we owed our general partner $0.7
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.
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. Our general partner acquired 1,074,882
of these units in July 2007 for $20.8036 per unit and 734,732 of these units in
December 2007 for $21.12 per unit under its preferential right to maintain its
7.4% interest in our common units.
During
2007, our general partner received a total of $1.7 million from us as
distributions, with $1.2 million attributable to its limited partner units, $0.4
million for its general partner interest, and $0.1 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 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 seeks “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 acquisition or disposition 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 CO2 volumetric
production payments and related wholesale marketing contracts from Denbury for
$14.4 million, $4.7 million and $24.4 million,
respectively. Additionally we enter into transactions with Denbury in
the ordinary course of our operations. During 2007, these
transactions included:
|
|
·
|
Purchases
of crude oil from Denbury totaling $0.1
million.
|
|
|
·
|
Provision
of transportation services for crude oil by truck totaling $1.8
million.
|
|
|
·
|
Provision
of crude oil pipeline transportation services totaling $5.3
million.
|
|
|
·
|
Provision
of crude oil from and CO2
transportation to the Brookhaven field and crude oil from the Olive field
for $1.2 million.
|
|
|
·
|
Provision
of CO2
transportation services to our wholesale industrial customers by Denbury’s
pipeline. The fees for this service totaled $5.2 million in
2007.
|
|
|
·
|
Provision
of pipeline monitoring services to Denbury for its CO2
pipelines totaling $120,000 in
2007.
|
|
|
·
|
Provision
of services by Denbury officers as directors of our general
partner. We paid Denbury $150,000 for these services in
2007.
|
At
December 31, 2007, we owed Denbury $1.0 million for provision of CO2
transportation services. Denbury owed us $0.9 million for crude oil
trucking and pipeline transportation services.
We have
reached substantial agreement and are in the process of finalizing the business
issues with Denbury and the lenders in our credit facility as to the terms of
the drop-down by Denbury to us and the terms of a long-term transportation
service arrangement for the Free State line and a 20-year financing lease for
the NEJD system. We expect to pay for these pipeline assets with $225 million in
cash and $25 million of our common units based on the average closing price of
our units for the thirty trading days prior to the closing of the transaction.
We expect to receive approximately $30 million per annum, in the aggregate,
under the lease and the transportation services agreement (and a lesser
pro-rated amount for 2008), with future payments for the NEJD pipeline fixed at
$20.7 million per year during the term of the financing lease, and the payments
relating to the Free State pipeline dependant on the volumes of CO2
transported therein. While the business terms of the transactions and associated
documentation have been substantially completed, closing remains subject to
completion of closing documentation, receipt of a fairness opinion and approval
by the audit committee and the board of directors of our general
partner.
In 2002,
we amended our partnership agreement to broaden the right of the common
unitholders to remove our general partner. Prior to this amendment,
our general partner could only be removed for cause and with approval by holders
of two-thirds or more of the outstanding limited partner interests in
us. As amended, the 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.
The
amendment further provides that if it is proposed that the removal is without
cause and an affiliate of Denbury is our general partner to be removed and 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 CO2 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.
Relationship
with Davison family
From July
25, 2007 through December 31, 2007, the Davison family provided certain
transition services to us related to the payroll for persons who provide
services to us. These persons became employees of our general partner
on January 1, 2008; however, to create the least disruption for employees while
we evaluated benefit plan arrangements, the personnel in our Supply and
Logistics operations acquired from Davison were paid by entities owned by the
Davison family and we reimbursed them for all direct costs.
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, 2007 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;
|
|
|
·
|
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, 2007, the Davison unitholders held approximately 33% 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.
Director
Independence
Susan O.
Rheney and J. Conley Stone, both members of our Audit Committee, meet the
listing standard requirements of AMEX, and the SEC rules to be considered
independent directors of Genesis. 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.
On
January 3, 2008, we received a letter from AMEX informing us that we are
currently not in compliance with Rule 121(B)(2)(a) of the AMEX Company Guide,
which requires our Audit Committee to consist of at least three independent
directors. Our Audit Committee membership decreased to two directors
upon Herbert I. Goodman’s resignation from the Board of Directors of our general
partner, on December 12, 2007. The letter from AMEX is a “warning
letter” and provides us until April 2, 2008 to regain compliance with the Amex
requirements by appointing an additional independent director to serve on the
Audit Committee. We have commenced a search for a qualified
individual to fill our Audit Committee vacancy and expect to fill the vacancy
before April 2, 2008.
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 Accounting Fees and
Services
The
following table summarizes the fees for professional services rendered by
Deloitte & Touche LLP for the years ended December 31, 2007 and
2006.
|
2007
|
2006
|
|||||||
|
(in
thousands)
|
||||||||
|
Audit
Fees (1)
|
$ | 3,107 | $ | 632 | ||||
|
Audit-Related
Fees (2)
|
1,945 | 25 | ||||||
|
Tax
Fees (3)
|
165 | 88 | ||||||
|
All
Other Fees
(4)
|
2 | 1 | ||||||
|
Total
|
$ | 5,219 | $ | 746 | ||||
|
|
(1)
|
Includes
fees for the annual audit and quarterly reviews, SEC registration
statements, accounting and financial reporting consultations and research
work regarding Generally Accepted Accounting Principles and the audit of
the effectiveness of our internal controls over financial
reporting.
|
|
|
(2)
|
Includes
fees for audits of acquired businesses and the audit of our employee
benefit plan.
|
|
|
(3)
|
Includes
fees for tax return preparation and tax
consultations.
|
|
|
(4)
|
Includes
fees associated with a license for accounting research
software.
|
Pre-Approval
Policy
The
services by Deloitte in 2007 and 2006 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 2007
and 2006, 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.
Item
15. Exhibits and Financial Statement
Schedules
(a)(1)
Financial Statements
See “Index to Consolidated
Financial Statements and Financial Statement Schedules” set forth on page
93.
(a)(2) Financial
Statement Schedules
See “Index to Consolidated Financial
Statements and Financial Statement Schedules” set forth on page 93.
(a)(3) Exhibits
|
3.1
|
Certificate
of Limited Partnership of Genesis Energy, L.P. (“Genesis”) (incorporated
by reference to Exhibit 3.1 to Registration Statement, File No.
333-11545)
|
||
|
|
3.2
|
Fourth
Amended and Restated Agreement of Limited Partnership of Genesis
(incorporated by reference to Exhibit 4.1 to Form 8-K dated June 15,
2005)
|
|
|
|
|||
|
*
|
Amendment
No. 1 to Fourth Amended and Restated Agreement of Limited Partnership of
Genesis
|
||
|
|
3.4
|
Certificate
of Limited Partnership of Genesis Crude Oil, L.P. (“the Operating
Partnership”) (incorporated by reference to Exhibit 3.3 to Form 10-K for
the year ended December 31, 1996)
|
|
|
|
3.5
|
Fourth
Amended and Restated Agreement of Limited Partnership of the Operating
Partnership (incorporated by reference to Exhibit 4.2 to Form 8-K dated
June 15, 2005)
|
|
|
*
|
Certificate
of Incorporation of Genesis Energy, Inc.
|
||
|
*
|
Certificate
of Amendment of Certificate of Incorporation of Genesis Energy,
Inc.
|
||
|
*
|
Bylaws
of Genesis Energy, Inc.
|
||
|
|
|||
|
*
|
Form
of Unit Certificate of Genesis Energy, L.P.
|
||
|
|
|||
|
|
10.1
|
Purchase
& Sale and Contribution & Conveyance Agreement dated December 3,
1996 among Basis Petroleum, Inc., Howell Corporation (“Howell”), certain
subsidiaries of Howell, Genesis, the Operating Partnership and Genesis
Energy, L.L.C. (incorporated by reference to Exhibit 10.1 to Form 10-K for
the year ended December 31, 1996)
|
|
|
10.2
|
First
Amendment to Purchase & Sale and Contribution and Conveyance Agreement
(incorporated by reference to Exhibit 10.2 to Form 10-K for the year ended
December 31, 1996)
|
||
|
10.3
|
Credit
Agreement dated as of November 15, 2006 among Genesis Crude Oil, L.P.,
Genesis Energy, L.P., the Lenders Party Hereto, Fortis Capital Corp., and
Deutsche Bank Securities Inc. (incorporated by reference to Exhibit 10.1
to Form 8-K dated November 15, 2006)
|
||
|
|
|||
|
10.4
|
First
Amendment to Credit Agreement and Guarantee and Collateral Agreement dated
as of July 25, 2007 among Genesis Crude Oil, L.P., Genesis Energy,
L.P. and the Lenders, Issuing Banks and Guarantors (incorporated by
reference to Exhibit 10.6 to Form 8-K dated July 31,
2007)
|
||
|
|
|||
|
10.5
|
+
|
Letter
dated August 3, 2006 to Grant E. Sims regarding Offer to Enter into
Employment Agreements (incorporated by reference to Exhibit 10.1 to Form
10-Q for the quarterly period ended September 30, 2006)
|
|
|
10.6
|
Pipeline
Sale and Purchase Agreement between TEPPCO Crude Pipeline, L.P. and
Genesis Crude Oil, L.P. and Genesis Pipeline Texas, L.P. (incorporated by
reference to Exhibit 10.1 to Form 8-K dated October 31,
2003)
|
|
10.7
|
Purchase
and Sale Agreement between TEPPCO Crude Pipeline, L.P. and Genesis Crude
Oil, L.P. (incorporated by reference to Exhibit 10.2 to Form 8-K dated
October 31, 2003)
|
||
|
10.8
|
Production
Payment Purchase and Sale Agreement between Denbury Resources, Inc. and
Genesis Crude Oil, L.P. (incorporated by reference to Exhibit 10.7 to Form
10-K for the year ended December 31, 2003)
|
||
|
10.9
|
Carbon
Dioxide Transportation Agreement between Denbury Resources, Inc. and
Genesis Crude Oil, L.P. (incorporated by reference to Exhibit 10.8 to Form
10-K for the year ended December 31, 2003)
|
||
|
10.10
|
+
|
Genesis
Stock Appreciation Rights Plan (incorporated by reference to Exhibit 10.9
to Form 10-K for the year ended December 31, 2004)
|
|
|
10.11
|
+
|
Form
of Stock Appreciation Rights Plan Grant Notice (incorporated by reference
to Exhibit 10.10 to Form 10-K for the year ended December 31,
2004)
|
|
|
10.12
|
+
|
Summary
of Genesis Energy, Inc. Bonus Plan (incorporated by reference to Exhibit
10.12 to Form 10-K for the year ended December 31,
2006)
|
|
|
10.13
|
+
|
Genesis
Energy Amended and Restated Severance Protection Plan (incorporated by
reference to Exhibit 10.1 to Form 8-K dated December 12,
2006)
|
|
|
10.14
|
Second
Production Payment Purchase and Sale Agreement between Denbury Onshore,
LLC and Genesis Crude Oil, L.P. executed August 26, 2004 (incorporated by
reference to Exhibit 99.1 to Form 8-K dated August 26,
2004)
|
||
|
10.15
|
Second
Carbon Dioxide Transportation Agreement between Denbury Onshore, LLC and
Genesis Crude Oil, L.P. (incorporated by reference to Exhibit 99.2 to Form
8-K dated August 24, 2004)
|
||
|
10.16
|
Third
Production Payment Purchase and Sale Agreement between Denbury Onshore,
LLC and Genesis Crude Oil, L.P. executed October 11, 2005 (incorporated by
reference to Exhibit 99.2 to Form 8-K dated October 11,
2005)
|
||
|
10.17
|
Third
Carbon Dioxide Transportation Agreement between Denbury Onshore, LLC and
Genesis Crude Oil, L.P. (incorporated by reference to Exhibit 99.3 to Form
8-K dated October 11, 2005)
|
||
|
10.18
|
Contribution
and Sale Agreement by and among Davison Petroleum Products, L.L.C.,
Davison Transport, Inc., Transport Company, Davison Terminal Service,
Inc., Sunshine Oil & Storage, Inc., T&T Chemical, Inc. Fuel
Masters, LLC, TDC, L.L.C. and Red River Terminals, L.L.C. dated
April 25, 2007 (incorporated by reference to Exhibit 10.1 to Form 8-K
dated July 31, 2007)
|
||
|
|
|||
|
10.19
|
Amendment
No. 1 to the Contribution and Sale Agreement dated July 25, 2007
(incorporated by reference to Exhibit 10.2 to Form 8-K dated July 31,
2007)
|
||
|
10.20
|
Amendment
No. 2 to the Contribution and Sale Agreement dated October 15, 2007
(incorporated by reference to Exhibit 10.1 to Form 8-K dated October 19,
2007)
|
||
|
*
|
Amendment
No. 3 to the Contribution and Sale Agreement dated March 3,
2008
|
||
|
10.22
|
Registration
Rights Agreement (incorporated by reference to Exhibit 10.3 to Form 8-K
dated July 31, 2007)
|
||
|
10.23
|
Amendment
No. 1 to the Registration Rights Agreement dated November 16, 2007
(incorporated by reference to Exhibit 10.1 to Form 8-K dated November 16,
2007)
|
||
|
10.24
|
Amendment
No. 2 to the Registration Rights Agreement dated December 6, 2007
(incorporated by reference to Exhibit 10.1 to Form 8-K dated December 12,
2007)
|
|
10.25
|
Unitholder
Rights Agreement (incorporated by reference to Exhibit 10.4 to Form 8-K
dated July 31, 2007)
|
||
|
10.26
|
Amendment
No. 1 to the Unitholder Rights Agreement dated October 15, 2007
(incorporated by reference to Exhibit 10.2 to Form 8-K dated October 19,
2007)
|
||
|
10.27
|
Pledge
and Security Agreement (incorporated by reference to Exhibit 10.5 to Form
8-K dated July 31, 2007)
|
||
|
10.28
|
+
|
Genesis
Energy, Inc. 2007 Long Term Incentive Plan (incorporated by reference to
Exhibit 10.1 to Form 8-K dated December 21, 2007)
|
|
|
10.29
|
+
|
Form
of 2007 Phantom Unit Grant Agreement (3-Year Graded) (incorporated by
reference to Exhibit 10.2 to Form 8-K dated December 21,
2007)
|
|
|
10.30
|
+
|
Form
of 2007 Phantom Unit Grant Agreement (3-Year Cliff) (incorporated by
reference to Exhibit 10.3 to Form 8-K dated December 21,
2007)
|
|
|
11.1
|
Statement
Regarding Computation of Per Share Earnings (See Notes 2 and 11 to the
Consolidated Financial Statements
|
||
|
*
|
Subsidiaries
of the Registrant
|
||
|
*
|
Certification
by Chief Executive Officer Pursuant to Rule 13a-14(a) under the Securities
Exchange Act of 1934
|
||
|
*
|
Certification
by Chief Financial Officer Pursuant to Rule 13a-14(a) under the Securities
Exchange Act of 1934
|
||
|
*
|
Certification
by Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002
|
||
|
*
|
Certification
by Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002
|
* Filed
herewith
+ A
management contract or compensation plan or arrangement.
SIGNATURES
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its behalf by
the undersigned, thereunto duly authorized.
|
GENESIS
ENERGY, L.P.
(A
Delaware Limited Partnership)
|
|||
|
By:
|
GENESIS
ENERGY, INC.,
|
||
| as General Partner | |||
|
Date:
March 17, 2008
|
By:
|
/s/ Grant E.
Sims
|
|
|
Grant
E. Sims
Chief
Executive Officer
|
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons in the capacities and on the dates
indicated.
|
NAME
|
TITLE
|
DATE
|
|||
|
(OF
GENESIS ENERGY, INC.)*
|
|||||
|
/s/
|
Grant
E. Sims
|
Director
and Chief Executive Officer
|
March
17, 2008
|
||
|
Grant
E. Sims
|
(Principal
Executive Officer
|
||||
|
/s/
|
Ross
A. Benavides
|
Chief
Financial Officer,
|
March
17, 2008
|
||
|
Ross
A. Benavides
|
General
Counsel and Secretary
|
||||
|
(Principal
Financial Officer)
|
|||||
|
/s/
|
Karen
N. Pape
|
Vice
President and Controller
|
March
17, 2008
|
||
|
Karen
N. Pape
|
(Principal
Accounting Officer)
|
||||
|
/s/
|
Gareth
Roberts
|
Chairman
of the Board and
|
March
17, 2008
|
||
|
Gareth
Roberts
|
Director
|
||||
|
/s/
|
Mark
C. Allen
|
Director
|
March
17, 2008
|
||
|
Mark
C. Allen
|
|||||
|
/s/
|
James
E. Davison
|
Director
|
March
17, 2008
|
||
|
James
E. Davison
|
|||||
|
/s/
|
James
E. Davison, Jr.
|
Director
|
March
17, 2008
|
||
|
James
E. Davison, Jr.
|
|||||
|
/s/
|
Ronald
T. Evans
|
Director
|
March
17, 2008
|
||
|
Ronald
T. Evans
|
|||||
|
/s/
|
Susan
O. Rheney
|
Director
|
March
17, 2008
|
||
|
Susan
O. Rheney
|
|||||
|
/s/
|
Phil
Rykhoek
|
Director
|
March
17, 2008
|
||
|
Phil
Rykhoek
|
|||||
|
/s/
|
J.
Conley Stone
|
Director
|
March
17, 2008
|
||
|
J.
Conley Stone
|
*Genesis
Energy, Inc. is our general partner.
AND
FINANCIAL STATEMENT SCHEDULES
|
Page
|
||
|
Financial
Statements
|
|
|
|
Report
of Independent Registered Public Accounting Firm
|
94
|
|
|
Consolidated
Balance Sheets, December 31, 2007 and 2006
|
95
|
|
|
|
||
|
Consolidated
Statements of Operations for the Years Ended December 31, 2007, 2006 and
2005
|
96
|
|
|
|
||
|
Consolidated
Statements of Partners’ Capital for the Years Ended December 31, 2007,
2006 and 2005
|
97
|
|
|
|
||
|
Consolidated
Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and
2005
|
98
|
|
|
|
||
|
Notes
to Consolidated Financial Statements
|
99
|
|
|
Financial
Statement Schedules
|
|
|
|
Schedule
I – Condensed Financial Information
|
131
|
|
|
Financial Statements of
Significant Equity Investees – T&P Syngas Supply
Company. To be filed by amendment within 90 days of the filing
of this Annual Report on Form 10-K
|
|
|
All other
financial statement schedules are not required under the relevant instructions
or are inapplicable and therefore have been omitted.
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Board of Directors of Genesis Energy, Inc. and Unitholders of
Genesis
Energy, L.P.
Houston,
Texas
We have
audited the accompanying consolidated balance sheets of Genesis Energy, L.P. and
subsidiaries (the "Partnership") as of December 31, 2007 and 2006, and the
related consolidated statements of operations, partners' capital, and cash flows
for each of the three years in the period ended December 31, 2007. Our
audits also included the financial statement schedule listed in the Index at
Item 15. These financial statements and financial statement schedule are
the responsibility of the Partnership's management. Our responsibility is
to express an opinion on the financial statements and financial statement
schedule based on our audits.
We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our
opinion, such consolidated financial statements present fairly, in all material
respects, the financial position of Genesis Energy, L.P. and subsidiaries at
December 31, 2007 and 2006, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2007, in
conformity with accounting principles generally accepted in the United States of
America. Also, in our opinion, such financial statement schedule, when
considered in relation to the basic consolidated financial statements taken as a
whole, presents fairly, in all material respects, the information set forth
therein.
As
described in Note 2 to the consolidated financial statements and effective as of
January 1, 2006, the Partnership adopted Statement of Financial Accounting
Standards (“SFAS”) No. 123R, which established new accounting and reporting
standards for share-based compensation. Additionally, as described in
Note 5 to the consolidated financial statements and effective as of
December 15, 2005, the Partnership adopted FASB Interpretation 47,
which established new accounting and reporting standards for asset retirement
obligations.
We have
also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the Partnership's internal control over
financial reporting as of December 31, 2007, based on the criteria established
in Internal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission and our report dated March 14, 2008 expressed an unqualified
opinion on the Partnership's internal control over financial
reporting.
DELOITTE
& TOUCHE LLP
Houston,
Texas
March 14,
2008
|
GENESIS
ENERGY, L.P.
|
||||||||
|
CONSOLIDATED
BALANCE SHEETS
|
||||||||
|
(In
thousands)
|
||||||||
|
December
31,
|
December
31,
|
|||||||
|
2007
|
2006
|
|||||||
|
ASSETS
|
||||||||
|
CURRENT
ASSETS:
|
||||||||
|
Cash
and cash equivalents
|
$ | 11,851 | $ | 2,318 | ||||
|
Accounts
receivable - trade
|
178,658 | 88,006 | ||||||
|
Accounts
receivable - related party
|
1,441 | 1,100 | ||||||
|
Inventories
|
15,988 | 5,172 | ||||||
|
Net
investment in direct financing leases, net of unearned income - current
portion - related party
|
609 | 568 | ||||||
|
Other
|
5,693 | 2,828 | ||||||
|
Total
current assets
|
214,240 | 99,992 | ||||||
|
FIXED
ASSETS, at cost
|
150,413 | 70,382 | ||||||
|
Less: Accumulated
depreciation
|
(48,413 | ) | (39,066 | ) | ||||
|
Net
fixed assets
|
102,000 | 31,316 | ||||||
|
NET
INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income - related
party
|
4,764 | 5,373 | ||||||
|
CO2
ASSETS, net of amortization
|
28,916 | 33,404 | ||||||
|
JOINT
VENTURES AND OTHER INVESTMENTS
|
18,448 | 18,226 | ||||||
|
INTANGIBLE
ASSETS, net of amortization
|
211,050 | - | ||||||
|
GOODWILL
|
320,708 | - | ||||||
|
OTHER
ASSETS, net of amortization
|
8,397 | 2,776 | ||||||
|
TOTAL
ASSETS
|
$ | 908,523 | $ | 191,087 | ||||
|
LIABILITIES
AND PARTNERS' CAPITAL
|
||||||||
|
CURRENT
LIABILITIES:
|
||||||||
|
Accounts
payable - trade
|
$ | 154,614 | $ | 85,063 | ||||
|
Accounts
payable - related party
|
2,647 | 1,629 | ||||||
|
Accrued
liabilities
|
17,537 | 9,220 | ||||||
|
Total
current liabilities
|
174,798 | 95,912 | ||||||
|
LONG-TERM
DEBT
|
80,000 | 8,000 | ||||||
|
DEFERRED
TAX LIABILITIES
|
20,087 | - | ||||||
|
OTHER
LONG-TERM LIABILITIES
|
1,264 | 991 | ||||||
|
MINORITY
INTERESTS
|
570 | 522 | ||||||
|
COMMITMENTS
AND CONTINGENCIES (Note 18)
|
||||||||
|
PARTNERS'
CAPITAL:
|
||||||||
|
Common
unitholders, 38,253 and 13,784 units issued and outstanding at December
31, 2007 and 2006, respectively
|
615,265 | 83,884 | ||||||
|
General
partner
|
16,539 | 1,778 | ||||||
|
Total
partners' capital
|
631,804 | 85,662 | ||||||
|
TOTAL
LIABILITIES AND PARTNERS' CAPITAL
|
$ | 908,523 | $ | 191,087 | ||||
The
accompanying notes are an integral part of these consolidated financial
statements.
|
GENESIS
ENERGY, L.P.
|
||||||||||||
|
CONSOLIDATED
STATEMENTS OF OPERATIONS
|
||||||||||||
|
(In
thousands, except per unit amounts)
|
||||||||||||
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
REVENUES:
|
||||||||||||
|
Supply
and logistics:
|
||||||||||||
|
Unrelated
parties (including revenues
from buy/sell arrangements of $69,772 and $365,067 in 2006 and 2005,
respectively)
|
$ | 1,092,398 | $ | 872,443 | $ | 1,037,577 | ||||||
|
Related
parties
|
1,791 | 825 | 972 | |||||||||
|
Refinery
services
|
62,095 | - | - | |||||||||
|
Pipeline
transportation, including natural gas sales:
|
||||||||||||
|
Transportation
services - unrelated parties
|
17,153 | 17,119 | 14,760 | |||||||||
|
Transportation
services - related parties
|
5,754 | 4,948 | 4,591 | |||||||||
|
Natural
gas sales revenues
|
4,304 | 7,880 | 9,537 | |||||||||
|
CO2
marketing:
|
||||||||||||
|
Unrelated
parties
|
13,376 | 13,098 | 11,302 | |||||||||
|
Related
parties
|
2,782 | 2,056 | - | |||||||||
|
Total
revenues
|
1,199,653 | 918,369 | 1,078,739 | |||||||||
|
COSTS
AND EXPENSES:
|
||||||||||||
|
Supply
and logistics costs:
|
||||||||||||
|
Product
costs - unrelated parties (including costs from buy/sell
arrangements of $68,899 and $363,208 in 2006 and 2005,
respectively)
|
1,041,637 | 850,106 | 1,014,249 | |||||||||
|
Product
costs - related parties
|
101 | 1,565 | 4,647 | |||||||||
|
Operating
costs
|
37,121 | 14,231 | 15,992 | |||||||||
|
Refinery
services operating costs
|
40,197 | - | - | |||||||||
|
Pipeline
transportation costs:
|
||||||||||||
|
Pipeline
transportation operating costs
|
10,054 | 9,928 | 9,741 | |||||||||
|
Natural
gas purchases
|
4,122 | 7,593 | 9,343 | |||||||||
|
CO2
marketing costs:
|
||||||||||||
|
Transportation
costs - related party
|
5,213 | 4,640 | 3,501 | |||||||||
|
Other
costs
|
152 | 202 | 148 | |||||||||
|
General
and administrative
|
25,920 | 13,573 | 9,656 | |||||||||
|
Depreciation
and amortization
|
38,747 | 7,963 | 6,721 | |||||||||
|
Net
loss (gain) on disposal of surplus assets
|
266 | (16 | ) | (479 | ) | |||||||
|
Impairment
expense
|
1,498 | - | - | |||||||||
|
Total
costs and expenses
|
1,205,028 | 909,785 | 1,073,519 | |||||||||
|
OPERATING
(LOSS) INCOME
|
(5,375 | ) | 8,584 | 5,220 | ||||||||
|
Equity
in earnings of joint ventures
|
1,270 | 1,131 | 501 | |||||||||
|
Interest
income
|
385 | 198 | 71 | |||||||||
|
Interest
expense
|
(10,485 | ) | (1,572 | ) | (2,103 | ) | ||||||
|
(Loss)
income from continuing operations before income taxes and minority
interest
|
(14,205 | ) | 8,341 | 3,689 | ||||||||
|
Income
tax benefit
|
654 | 11 | - | |||||||||
|
Minority
interest
|
1 | (1 | ) | - | ||||||||
|
(LOSS)
INCOME FROM CONTINUING OPERATIONS
|
(13,550 | ) | 8,351 | 3,689 | ||||||||
|
Income
from discontinued operations
|
- | - | 312 | |||||||||
|
Cumulative
effect adjustment of adoption of new accounting principles
|
- | 30 | (586 | ) | ||||||||
|
NET
(LOSS) INCOME
|
$ | (13,550 | ) | $ | 8,381 | $ | 3,415 | |||||
|
GENESIS
ENERGY, L.P.
|
||||||||||||
|
CONSOLIDATED
STATEMENTS OF OPERATIONS - CONTINUED
|
||||||||||||
|
(In
thousands, except per unit amounts)
|
||||||||||||
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
NET
(LOSS) INCOME PER COMMON UNIT - BASIC AND DILUTED:
|
||||||||||||
|
(Loss)
income from continuing operations
|
$ | (0.64 | ) | $ | 0.59 | $ | 0.38 | |||||
|
Income
from discontinued operations
|
- | - | 0.03 | |||||||||
|
Cumulative
effect adjustment
|
- | - | (0.06 | ) | ||||||||
|
NET
(LOSS) INCOME
|
$ | (0.64 | ) | $ | 0.59 | $ | 0.35 | |||||
|
Weighted
average number of common units outstanding - basic
|
20,754 | 13,784 | 9,547 | |||||||||
The
accompanying notes are an integral part of these consolidated financial
statements.
|
GENESIS
ENERGY, L.P.
|
||||||||||||||||
|
CONSOLIDATED
STATEMENTS OF PARTNERS' CAPITAL
|
||||||||||||||||
|
(In
thousands)
|
||||||||||||||||
|
Partners'
Capital
|
||||||||||||||||
|
Number
of
|
||||||||||||||||
|
Common
|
Common
|
General
|
||||||||||||||
|
Units
|
Unitholders
|
Partner
|
Total
|
|||||||||||||
|
Partners'
capital, January 1, 2005
|
9,314 | $ | 44,326 | $ | 913 | $ | 45,239 | |||||||||
|
Net
income
|
- | 3,347 | 68 | 3,415 | ||||||||||||
|
Cash
distributions
|
- | (5,682 | ) | (116 | ) | (5,798 | ) | |||||||||
|
Issuance
of units
|
4,470 | 43,879 | 954 | 44,833 | ||||||||||||
|
Partners'
capital, December 31, 2005
|
13,784 | 85,870 | 1,819 | 87,689 | ||||||||||||
|
Net
income
|
- | 8,214 | 167 | 8,381 | ||||||||||||
|
Cash
distributions
|
- | (10,200 | ) | (208 | ) | (10,408 | ) | |||||||||
|
Partners'
capital, December 31, 2006
|
13,784 | 83,884 | 1,778 | 85,662 | ||||||||||||
|
Net
loss
|
- | (13,279 | ) | (271 | ) | (13,550 | ) | |||||||||
|
Cash
contributions
|
- | - | 1,412 | 1,412 | ||||||||||||
|
Contribution
for management compensation (Note 11)
|
- | - | 3,434 | 3,434 | ||||||||||||
|
Cash
distributions
|
- | (16,743 | ) | (432 | ) | (17,175 | ) | |||||||||
|
Issuance
of units
|
24,469 | 561,403 | 10,618 | 572,021 | ||||||||||||
|
Partners'
capital, December 31, 2007
|
38,253 | $ | 615,265 | $ | 16,539 | $ | 631,804 | |||||||||
The accompanying notes are an integral part of
these consolidated financial statements.
|
GENESIS
ENERGY, L.P.
|
||||||||||||
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
||||||||||||
|
(In
thousands)
|
||||||||||||
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
||||||||||||
|
Net
(loss) income
|
$ | (13,550 | ) | $ | 8,381 | $ | 3,415 | |||||
|
Adjustments
to reconcile net (loss) income to net cash provided by operating
activities -
|
||||||||||||
|
Depreciation,
amortization and impairment
|
35,757 | 3,719 | 3,579 | |||||||||
|
Amortization
of CO2
contracts
|
4,488 | 4,244 | 3,142 | |||||||||
|
Amortization
and write-off of credit facility issuance costs
|
779 | 969 | 373 | |||||||||
|
Amortization
of unearned income on direct financing leases
|
(620 | ) | (655 | ) | (689 | ) | ||||||
|
Deferred
tax benefit
|
(2,658 | ) | (11 | ) | - | |||||||
|
Payments
received under direct financing leases
|
1,188 | 1,186 | 1,185 | |||||||||
|
Equity
in earnings of investments in joint ventures
|
(1,270 | ) | (1,131 | ) | (501 | ) | ||||||
|
Distributions
from joint ventures - return on investment
|
1,845 | 1,565 | 435 | |||||||||
|
Loss
(gain) on disposal of assets
|
266 | (16 | ) | (791 | ) | |||||||
|
Cumulative
effect adjustment
|
- | (30 | ) | 586 | ||||||||
|
Non-cash
effect of stock appreciation rights plan
|
910 | 1,929 | (481 | ) | ||||||||
|
Non-cash
compensation charge
|
3,434 | - | - | |||||||||
|
Other
non-cash charges (credits)
|
80 | (15 | ) | 427 | ||||||||
|
Changes
in components of operating assets and liabilities, net of working capital
acquired -
|
||||||||||||
|
Accounts
receivable
|
(35,362 | ) | (6,472 | ) | (13,313 | ) | ||||||
|
Inventories
|
(143 | ) | (4,664 | ) | 790 | |||||||
|
Other
current assets
|
(1,887 | ) | 870 | 132 | ||||||||
|
Accounts
payable
|
34,523 | 1,359 | 10,431 | |||||||||
|
Accrued
liabilities and taxes payable
|
6,149 | 34 | 770 | |||||||||
|
Net
cash provided by operating activities
|
33,929 | 11,262 | 9,490 | |||||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
||||||||||||
|
Payments
to acquire fixed assets
|
(8,235 | ) | (1,260 | ) | (6,106 | ) | ||||||
|
Distributions
from joint ventures - return of investment
|
395 | 528 | 388 | |||||||||
|
Investments
in joint ventures and other investments
|
(1,104 | ) | (6,042 | ) | (13,418 | ) | ||||||
|
Acquisition
of Davison assets, net of cash acquired
|
(301,640 | ) | - | - | ||||||||
|
Acquisition
of Port Hudson assets
|
(8,103 | ) | - | - | ||||||||
|
CO2
contracts acquisition
|
- | - | (14,446 | ) | ||||||||
|
Other,
net
|
(2,655 | ) | (68 | ) | 1,773 | |||||||
|
Net
cash used in investing activities
|
(321,342 | ) | (6,842 | ) | (31,809 | ) | ||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
||||||||||||
|
Bank
borrowings
|
392,200 | 8,000 | - | |||||||||
|
Bank
repayments
|
(320,200 | ) | - | (15,300 | ) | |||||||
|
Credit
facility issuance fees
|
(2,297 | ) | (2,726 | ) | - | |||||||
|
Issuance
of common units for cash
|
231,433 | - | 44,833 | |||||||||
|
General
partner contributions
|
12,030 | - | - | |||||||||
|
Minority
interest contributions, net of distributions
|
49 | (1 | ) | 5 | ||||||||
|
Other,
net
|
906 | (66 | ) | (400 | ) | |||||||
|
Distributions
to common unitholders
|
(16,743 | ) | (10,200 | ) | (5,682 | ) | ||||||
|
Distributions
to general partner
|
(432 | ) | (208 | ) | (116 | ) | ||||||
|
Net
cash provided by (used in) financing activities
|
296,946 | (5,201 | ) | 23,340 | ||||||||
|
Net
(decrease) increase in cash and cash equivalents
|
9,533 | (781 | ) | 1,021 | ||||||||
|
Cash
and cash equivalents at beginning of period
|
2,318 | 3,099 | 2,078 | |||||||||
|
Cash
and cash equivalents at end of period
|
$ | 11,851 | $ | 2,318 | $ | 3,099 | ||||||
The
accompanying notes are an integral part of these consolidated financial
statements.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization
We are a
publicly traded Delaware limited partnership formed in December
1996. Our operations are conducted through our operating subsidiary,
Genesis Crude Oil, L.P., and its subsidiary partnerships and
corporations. We are engaged in pipeline transportation of crude oil,
and, to a lesser degree, natural gas and carbon dioxide, or CO2, crude oil
gathering and marketing, and we engage in industrial gas activities, including
wholesale marketing of CO2 and
processing of syngas through a joint venture. Our assets are located
in the United States Gulf Coast area.
Our 2%
general partner interest is held by Genesis Energy, Inc., a Delaware corporation
and indirect wholly-owned subsidiary of Denbury Resources
Inc. Denbury and its subsidiaries are hereafter referred to as
Denbury. Our general partner also owns 7.4% of our 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, 2007 and 2006 and our results of
operations, cash flows and changes in partners’ capital for the years ended
December 31, 2007, 2006 and 2005. All intercompany transactions have
been eliminated. The accompanying consolidated financial statements
include Genesis Energy, L.P., its operating subsidiary and its subsidiary
partnerships. Our general partner owns a 0.01% general partner
interest in Genesis Crude Oil, L.P., which is reflected in our financial
statements as a minority interest.
In July
2007, we acquired the energy-related businesses of the Davison
family. The results of the operations of these businesses have been
included in the consolidated financial statements of Genesis Energy, L.P. since
August 1, 2007.
In 2005,
we acquired a 50% interest in T&P Syngas Supply Company. In 2006,
we acquired a 50% interest in Sandhill Group, LLC. These investments
are accounted for by the equity method, as we exercise significant influence
over their operating and financial policies. See Note 8.
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, (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 our outstanding stock appreciation rights and awards under our
long-term incentive plan, 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. Cash and cash equivalents are stated at cost
which approximates market value.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
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 which approximates first-in, first-out.
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, 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
In
general, our future asset retirement obligations relate to future costs
associated with the removal of our oil, natural gas and CO2 pipelines,
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.
Direct
Financing Leasing Arrangements
We lease
three pipelines to Denbury under direct financing leases. These
leases to Denbury of pipeline segments will expire in eight to ten
years.
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.
CO2
Assets
Our
CO2
assets include three volumetric production payments and long-term contracts to
sell the CO2
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.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
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, 2007, 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.
Other
Assets
Other
assets consist primarily of deferred credit facility fees, deferred charges, and
deposits. We are amortizing the deferred credit facility fees over
the period the facility is in effect.
Deferred
charges consist of third-party costs related to projects or planned acquisitions
in the preliminary stages. We review these deferred charges at each
reporting date and charge costs related to projects that have been cancelled or
abandoned to expense.
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.
At a
special meeting of our unitholders on December 18, 2007, our unitholders
approved the 2007 Long-term Incentive Plan, which 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.
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.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
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.
CO2 Sales -
Revenues from CO2 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, both personnel to operate our fleet of trucks
and the costs to fuel and maintain our vehicles.
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 2005 and the first quarter of 2006, our
reported supply and logistics revenues from unrelated parties for the year ended
December 31, 2006 and 2005 would have been reduced by $69 million to $803
million and by $365 million to $673 million, respectively. Our
reported supply and logistics product costs from unrelated parties for the year
ended December 31, 2006 and 2005 would have been reduced by $69 million to $781
million and by $363 million to $651 million, respectively. 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.
Cost of
sales for the CO2 marketing
activities consists of a transportation fee charged by Denbury to transport the
CO2 to
the customer through Denbury’s pipeline and insurance costs. The
transportation fee charged by Denbury is adjusted annually for
inflation. For the year ended December 31, 2007, 2006 and 2005,, the
fee averaged $0.1848, $0.174 and $0.1688 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 cost of products.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL 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. The aggregate difference in the basis of our net
assets for financial and tax reporting purposes cannot be readily determined as
we do not have access to information about each partner’s tax attributes in
us.
Some of
our corporate subsidiaries and corporations in which we have an equity
investment do 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.
In June
2006, the Financial Accounting Standards Board (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.
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. 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. 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
Basic net
income per common unit is calculated on the weighted average number of
outstanding common units, after exclusion of the general partner’s interest from
net income. The general partner’s percentage interest in our net
income is based on its percentage of cash distributions from Available Cash for
each 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.
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. See Note 11 for a computation of net (loss) income per common
unit.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
Recent
and Proposed Accounting Pronouncements
SFAS
157
In
September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements”, or SFAS
157. SFAS 157 defines fair value, establishes a framework for
measuring fair value in accordance with accounting principles generally accepted
in the United States, and expands disclosures about fair value
measurements. SFAS 157 emphasizes that fair value is a market-based
measurement that should be determined based on the assumptions that market
participants would use in pricing an asset or liability. In February
2008, the FASB issued SFAS No. 157-2, “Effective Date of FASB Statement No.
157”, or SFAS 157-2, which delays the effective date of SFAS 157 for all
non-financial assets and non-financial liabilities. In accordance
with SFAS 157-2, SFAS 157 is effective for fiscal years beginning after November
15, 2007.for financial assets and liabilities as well as for any other assets
and liabilities that are carried at fair value on a recurring basis in financial
statements. We adopted SFAS 157 on January 1, 2008 for such assets
and liabilities with no material impact on our consolidated financial
statements. We will begin the new disclosure requirements
of SFAS 157 in the first quarter of 2008. We do not
currently know what the effects of the deferred provisions of SFAS 157 will be
on our financial position and results of operations when adopted in
2009.
SFAS
159
In
February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for
Financial Assets and Financial Liabilities”, or SFAS 159. SFAS 159
permits entities to choose to measure many financial assets and financial
liabilities at fair value, with the objective of improving financial reporting
by giving entities the opportunity to mitigate volatility in reported earnings
caused by measuring related assets and liabilities differently without having to
apply complex hedge accounting provisions. SFAS 159 is effective for us
beginning Januray 1, 2008. We are currently assessing the impact of
SFAS 159 on our financial condition or results of operations.
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 will
adopt SFAS 141(R) on January 1, 2009 for acquisitions on or after that
date.
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 will adopt SFAS 160 on January 1,
2009. We are assessing the impact of this statement on our financial
statements, but expect it to impact the presentation of the minority interest in
our operating partnership.
EITF
07-4
In May
2007, 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.” This EITF considers the question of whether
the incentive distribution rights (“IDRs”) of a master limited partnership
represent a participating security and should be considered in the calculation
of earnings per unit. Under the “two class” method of computing
earnings per unit, earnings are allocated to participating securities as if all
of the earnings for the period had been distributed. The EITF also
presents alternative methods for inclusion of IDRs in the computation of
earnings per unit, depending on whether cash distributions exceed earnings for
the period. The EITF has issued a draft abstract on this topic and
will address comments it receives before issuing a final
consensus. Once a final consensus is issued it is expected to be
effective for fiscal years beginning after December 15, 2008, and interim
periods within those fiscal years. We will assess the impact of EITF
07-4 once a final consensus is issued; however we would expect it to have an
impact on our presentation of earnings per unit in the future. For
additional information on our incentive distribution rights, see Note
11.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
3. Acquisitions
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.
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 with the assistance of a third-party valuation firm. The allocation
of the purchase price is summarized as follows (in thousands):
|
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.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
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.
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.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
4. Inventories
Inventories
are valued at the lower of cost or market. The costs of inventories
did not exceed market values at December 31, 2007 and 2006. The major
components of inventories were as follows (in thousands):
|
December
31,
|
||||||||
|
2007
|
2006
|
|||||||
|
Crude
oil
|
3,710 | $ | 5,081 | |||||
|
Petroleum
products
|
6,527 | - | ||||||
|
Caustic
soda
|
1,998 | - | ||||||
|
NaHS
|
3,557 | - | ||||||
|
Other
|
196 | 91 | ||||||
|
Total
inventories
|
$ | 15,988 | $ | 5,172 | ||||
5. Fixed
Assets and Asset Retirement Obligations
Fixed
Assets
Fixed
assets consisted of the following (in thousands).
|
December
31,
|
||||||||
|
2007
|
2006
|
|||||||
|
Land,
buildings and improvements
|
$ | 11,978 | $ | 808 | ||||
|
Pipelines
and related assets
|
63,169 | 58,428 | ||||||
|
Machinery
and equipment
|
25,097 | - | ||||||
|
Transportation
equipment
|
32,906 | 1,257 | ||||||
|
Office
equipment, furniture and fixtures
|
2,759 | 2,616 | ||||||
|
Construction
in progress
|
7,102 | 78 | ||||||
|
Other
|
7,402 | 7,195 | ||||||
|
Subtotal
|
150,413 | 70,382 | ||||||
|
Accumulated
depreciation and impairment
|
(48,413 | ) | (39,066 | ) | ||||
|
Total
|
$ | 102,000 | $ | 31,316 | ||||
In 2007,
2006 and 2005, $57,000, $9,000 and $35,000 of interest cost, respectively, was
capitalized related to the construction of pipelines and related
assets.
Depreciation
expense was $8,909,000, $3,719,000 and $3,579,000 for the years ended December
31, 2007, 2006, and 2005, 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.
Asset
Retirement Obligations
On
December 31, 2005, we adopted FASB Interpretation No. 47, “Accounting for
Conditional Asset Retirement Obligations, an interpretation of FASB Statement
No. 143”, or FIN 47. FIN 47 clarified that the term “conditional
asset retirement obligation”, as used in SFAS No. 143, “Accounting for Asset
Retirement Obligations”, refers to a legal obligation to perform an asset
retirement activity in which the timing and/or method of settlement are
conditional upon a future event that may or may not be within our
control. Although uncertainty about the timing and/or method of
settlement may exist and may be conditional upon a future event, the obligation
to perform the asset retirement activity is
unconditional. Accordingly, we are required to recognize a liability
for the fair value of a conditional asset retirement obligation if the fair
value of the liability can be reasonably estimated.
Upon
adoption of FIN 47, we recorded a fixed asset and a liability for the estimated
fair value of the asset retirement obligations at the time we acquired the
related assets. This $0.3 million fixed asset is being depreciated
over the life of the related assets. The accretion of the discount on
the liability and the depreciation through December 31, 2005 were recorded in
the statement of operations as a cumulative effect adjustment totaling $0.5
million. Additionally, we reflected our share of the asset retirement
obligation recorded in accordance with FIN 47 of our equity method joint venture
as a cumulative affect adjustment of $0.1 million.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
A
reconciliation of our liability for asset retirement obligations is as follows
(in thousands):
|
Asset
retirement obligations as of December 31, 2005
|
$ | 657 | ||
|
Accretion
expense
|
51 | |||
|
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 |
At
December 31, 2007, $0.1 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 2007. Certain of our
unconsolidated affiliates have asset retirement obligations recorded at December
31, 2007 and 2006 relating to contractual agreements. These amounts
are immaterial to our financial statements.
The pro
forma impact for the period ended December 31, 2005 of the adoption of FIN 47 if
it had been adopted at the beginning of that period is as follows (in
thousands):
|
Year
Ended
December
31,
|
||||
|
2005
|
||||
|
(Unaudited)
|
||||
|
Income
from continuing operations - as reported
|
$ | 3,689 | ||
|
Impact
of change in accounting principle
|
(85 | ) | ||
|
Pro
forma income from continuing operations
|
$ | 3,604 | ||
|
Net
income - as reported
|
$ | 3,415 | ||
|
Add
back cumulative effect adjustment
|
586 | |||
|
Impact
of change in accounting principle
|
(85 | ) | ||
|
Pro
forma income from continuing operations
|
$ | 3,916 | ||
|
Basic
and diluted net income per common unit:
|
||||
|
Income
from continuing operations - as reported
|
$ | 0.38 | ||
|
Impact
of change in accounting principle
|
(0.01 | ) | ||
|
Pro
forma income from continuing operations
|
$ | 0.37 | ||
|
Net
income - as reported
|
$ | 0.35 | ||
|
Impact
of change in accounting principle and add back of cumulative effect
adjustment
|
0.05 | |||
|
Pro
forma income from continuing operations
|
$ | 0.40 | ||
6. Net
Investment in Direct Financing Leases
In the
fourth quarter of 2004, we constructed two segments of crude oil pipeline and a
CO2
pipeline segment to transport crude oil from and CO2 to
producing fields operated by Denbury. Denbury pays us a minimum
payment each month for the right to use these pipeline
segments. These arrangements have been accounted for as direct
financing leases.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
The
following table lists the components of the net investment in direct financing
leases (in thousands):
|
December
31,
|
||||||||
|
2007
|
2006
|
|||||||
|
Total
minimum lease payments to be received
|
$ | 7,039 | $ | 8,225 | ||||
|
Estimated
residual values of leased property (unguaranteed)
|
1,287 | 1,287 | ||||||
|
Less
unearned income
|
(2,953 | ) | (3,571 | ) | ||||
|
Net
investment in direct financing leases
|
$ | 5,373 | $ | 5,941 | ||||
At
December 31, 2007, minimum lease payments to be received for each of the five
succeeding fiscal years are $1.2 million per year for 2008 through 2011 and $1.1
million for 2012.
7. CO2
Assets
CO2 assets
consisted of the following (in thousands).
|
December
31,
|
||||||||
|
2007
|
2006
|
|||||||
|
CO2
volumetric production payments
|
$ | 43,570 | $ | 43,570 | ||||
|
Less
- Accumulated amortization
|
(14,654 | ) | (10,166 | ) | ||||
|
Net
CO2
assets
|
$ | 28,916 | $ | 33,404 | ||||
The
volumetric production payments entitle us to a maximum daily quantity of CO2 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 CO2 to our
industrial customers and receive a fee of $0.16 per Mcf, subject to inflationary
adjustments. During 2007 this fee averaged $0.1848 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.
The
CO2
assets are being amortized on a units-of-production method. After
purchase price adjustments, we had 276.7 Bcf of CO2 at
acquisition, and the total $43.6 million cost is being amortized based on the
volume of CO2 sold each
month. For 2007, 2006 and 2005, we recorded amortization
of $4,488,000, $4,244,000 and $3,142,000, respectively. We have 182.3
Bcf of CO2 remaining
under the volumetric production payments at December 31, 2007. Based
on the historical deliveries of CO2 to the
customers (which have exceeded minimum take-or-pay volumes), we expect
amortization for the next five years to be approximately $4,488,000 from 2008 to
2010 and $4,187,000 for 2011 and 2012.
8. Joint
Ventures and Other Investments
T&P
Syngas Supply Company
On April
1, 2005, we acquired a 50% interest in T&P Syngas Supply Company, a Delaware
general partnership, for $13.4 million in cash from a subsidiary of
ChevronTexaco Corporation. Praxair Hydrogen Supply Inc. owns the
remaining 50% partnership interest in T&P Syngas. We paid for our
interest in T&P Syngas with proceeds from our credit
facilities.
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.
We are
accounting for our 50% ownership in T&P Syngas under the equity method of
accounting. We reflect in our consolidated statements of operations
our equity in T&P Syngas’ net income, net of the amortization of the excess
of our investment over our share of partners’ capital of T&P
Syngas. We paid $4.0 million more for our interest in T&P Syngas
than our share of partners’ capital on the balance sheet of T&P Syngas at
the date of the acquisition. This excess amount of the purchase price
over the equity in T&P Syngas is being amortized using the straight-line
method over the remaining useful life of the assets of T&P Syngas of eleven
years. Our consolidated statements of operations for the years ended
December 31, 2007, 2006 and 2005 included $1.6 million, $1.5 million and $0.8
million, respectively, as our share of the operating earnings of T&P Syngas,
reduced by amortization of the excess purchase price of $0.4 million in 2007 and
2006 and $0.3 million in 2005. Additionally, our consolidated
statements of operations for 2005 include our share of the cumulative effect
adjustment to record asset retirement obligations of $54,000 of T&P
Syngas. We received distributions from T&P Syngas of $2.0 million
during the years ended December 31, 2007 and 2006 and $0.8 million during the
year ended December 31, 2005, respectively. In February 2008, we
received a distribution of $0.6 million from T&P with respect to the fourth
quarter of 2007. Our net investment in T&P Syngas at December 31,
2007, 2006 and 2005 was $11.5 million, $12.2 million and $13.0 million,
respectively.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
The table
below reflects summarized financial information for T&P Syngas at December
31, 2007 and December 31, 2006 (in thousands).
|
Year
Ended December 31,
|
Nine
Months Ended
|
|||||||||||
|
2007
|
2006
|
December
31, 2005
|
||||||||||
|
Revenues
|
$ | 5,040 | $ | 5,221 | $ | 3,454 | ||||||
|
Operating
expenses and depreciation
|
(2,223 | ) | (1,343 | ) | (1,509 | ) | ||||||
|
Other
income
|
19 | 17 | 9 | |||||||||
|
Income
tax expense
|
(23 | ) | (5 | ) | - | |||||||
|
Cumulative
effect adjustment
|
(109 | ) | ||||||||||
|
Net
income
|
$ | 2,813 | $ | 3,890 | $ | 1,845 | ||||||
|
December
31,
|
||||||||
|
2007
|
2006
|
|||||||
|
Current
assets
|
$ | 2,535 | $ | 2,268 | ||||
|
Non-current
assets
|
20,261 | 21,369 | ||||||
|
Total
assets
|
$ | 22,796 | $ | 23,637 | ||||
|
Current
liabilities
|
$ | 330 | $ | 90 | ||||
|
Non-current
liabilties
|
180 | 165 | ||||||
|
Partners'
capital
|
22,286 | 23,382 | ||||||
|
Total
liabilites and partners' capital
|
$ | 22,796 | $ | 23,637 | ||||
Sandhill
Group, LLC
On April
1, 2006, we acquired a 50% interest in Sandhill Group, LLC, for $5 million in
cash. At December 31, 2007, Reliant Processing Ltd. held the other
50% interest in Sandhill. Sandhill is a limited liability company
that owns a CO2 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 CO2 from us
under a long-term supply contract that we acquired in 2005 from
Denbury.
We paid
for our interest in Sandhill with cash on hand. The terms of the
acquisition include earnout provisions such that we could pay up to
an additional $2 million to Magna Carta, the former 50% owner in Sandhill, for
our interest in Sandhill, based on the distributable cash generated by Sandhill
during the period 2006 through no later than 2012. Should the
cumulative distributable cash of Sandhill in the period beginning with 2006
average at least $1.5 million per year, and distributions to the members average
at least $1.2 million per year, we will owe Magna Carta $1.0 million at the end
of the year when the target is exceeded. If the distributable cash
averages $2.0 million per year and distributions average $1.6 million per year
in the period beginning with 2006, we will owe Magna Carta an additional $1.0
million.
During
2003, Sandhill was authorized to issue a series of “Issuer Floating Rate Option
Notes” in an amount not to exceed $15,000,000. In 2003, Sandhill
issued notes in the amount of $5,900,000 which are backed by a letter of credit
from a bank and have a maturity date of December 1, 2013. At December
31, 2007, the outstanding balance of these notes was $3.9 million. We
provide a guarantee of 50% of the letter of credit to Sandhill’s bank;
therefore, our guaranty represents $1.95 million. Sandhill makes
principal payments totaling $0.6 million annually. We recorded the
estimated fair value of this guarantee of $0.1 million as a long-term liability
in our consolidated balance sheet, with a corresponding increase to our
investment in Sandhill.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
We are
accounting for our 50% ownership in Sandhill under the equity method of
accounting as both partners have substantive participating rights. We
reflect in our consolidated statements of operations our equity in Sandhill’s
net income, net of the amortization of the excess of our investment over our
share of partners’ capital of Sandhill that is not considered
goodwill. We paid $3.8 million more for our interest in Sandhill than
our share of partners’ capital on the balance sheet of Sandhill at the date of
the acquisition. This excess amount of the purchase price over the
equity in Sandhill has been allocated to the property and equipment of Sandhill
and certain intangible assets based on the fair value of those assets, with the
remainder of the excess purchase price of $0.7 million allocated to
goodwill. The amount allocated to property and equipment and
intangible assets is being amortized using the straight-line method over the
remaining useful lives of those assets. In accordance with Accoutning
Principles Board Opinion 18, we annually test our investment in Sandhill to
determine if an impairment of our investment that is other than temporary has
occurred.
Our
consolidated statements of operations for the years ended December 31, 2007 and
2006 included $312,000 and $141,000, respectively as our share of the operating
earnings of Sandhill, reduced by amortization of the excess purchase price of
$277,000 and $208,000, respectively. We received distributions from
Sandhill of $0.3 million during the year ended December 31, 2007 and $0.1
million during the nine month period in 2006 that we owned our interest. Our net
investment in Sandhill was $4.7 million at December 31, 2007.
Other
Projects
In 2006,
we invested $1.0 million in the Faustina Project, a petroleum coke to ammonia
project that is in the development stage. We have subsequently
invested an additional $1.1 million. All of our investment may later
be redeemed, with a return, or converted to equity after the project has
obtained construction financing. We have committed to invest an
additional $0.8 million in the Faustina Project in 2008. The funds we have
invested will be 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.
No events
or changes in circumstances have occurred that indicate a significant adverse
effect on the fair value of our investment at December 31, 2007, therefore the
investment is included in our consolidated balance sheet at cost.
9. Intangible
Assets, Goodwill and Other Assets
Intangible
Assets
As
explained in Note 3, in connection with the Davison acquisition, 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, 2007:
|
December
31, 2007
|
|||||||||||||||
|
Weighted
Amortization Period
in
Years
|
Gross
Carrying
Amount
|
Accumulated
Amortization
|
Carrying
Value
|
||||||||||||
|
Refinery
services customer relationships
|
3
|
$ | 94,654 | $ | 9,380 | $ | 85,274 | ||||||||
|
Supply
and logistics customer relationships
|
5
|
|
34,630 | 3,287 | 31,343 | ||||||||||
|
Refinery
services supplier relationships
|
2
|
36,469 | 9,241 | 27,228 | |||||||||||
|
Refinery
services licensing agreements
|
6
|
38,678 | 2,218 | 36,460 | |||||||||||
|
Supply
and logistics trade name
|
7
|
17,988 | 930 | 17,058 | |||||||||||
|
Supply
and logistics favorable lease
|
15
|
13,260 | 197 | 13,063 | |||||||||||
|
Other
|
3
|
721 | 97 | 624 | |||||||||||
|
Total
|
5
|
$ | 236,400 | $ | 25,350 | $ | 211,050 | ||||||||
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
The
licensing agreements referred to in the table above relate to the agreements we
have with refiners to provide services. The trade name is the Davison
name, 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 $25.4 million
for the year ended December 31, 2007.
The
following table reflects our estimated amortization expense for each of the five
subsequent fiscal years:
|
2008
|
2009
|
2010
|
2011
|
2012
|
||||||||||||||||
|
Refinery
services customer relationships
|
16,637 | 15,433 | 11,689 | 8,972 | 7,056 | |||||||||||||||
|
Supply
and logistics customer relationships
|
6,651 | 5,481 | 4,435 | 3,552 | 2,769 | |||||||||||||||
|
Refinery
services supplier relationships
|
15,205 | 4,068 | 2,925 | 2,629 | 2,364 | |||||||||||||||
|
Refinery
services licensing agreements
|
4,958 | 4,505 | 4,105 | 3,690 | 3,416 | |||||||||||||||
|
Supply
and logistics trade name
|
2,130 | 1,983 | 1,812 | 1,626 | 1,432 | |||||||||||||||
|
Supply
and logistics favorable lease
|
474 | 474 | 474 | 474 | 474 | |||||||||||||||
|
Other
|
232 | 232 | 135 | - | - | |||||||||||||||
|
Total
|
46,287 | 32,176 | 25,575 | 20,943 | 17,511 | |||||||||||||||
Goodwill
As
explained in Note 3, in connection with the Davison and Port Hudson
acquisitions, the residual of the purchase price over the fair values of the net
tangible and identifiable intangible assets acquired was allocated to
goodwill. The carrying amount of goodwill by business segment at
December 31, 2007 was $297.6 million to refinery services and $23.1 million to
supply and logistics. We have not recognized any impairment
losses related to goodwill for any of the periods presented.
Other
Assets
Other
assets consisted of the following (in thousands).
|
December
31,
|
||||||||
|
2007
|
2006
|
|||||||
|
Credit
facility fees
|
$ | 5,022 | $ | 2,726 | ||||
|
Deferred
tax asset
|
941 | - | ||||||
|
Other
deferred costs and deposits
|
3,284 | 119 | ||||||
| 9,247 | 2,845 | |||||||
|
Less
- Accumulated amortization
|
(850 | ) | (69 | ) | ||||
|
Net
other assets
|
$ | 8,397 | $ | 2,776 | ||||
Amortization
expense of credit facility fees for the years ended December 31, 2007, 2006 and
2005 was $779,000, $394,000 and $373,000, 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. Amortization of credit facility fees for the next four
years will be $1,079,000 for 2008, 2009 and 2010 and $941,000 in
2011.
10. Debt
Our
credit facility, with a maximum facility amount of $500 million, of which $100
million could be used for letters of credit, is with a group of banks led by
Fortis Capital Corp. and Deutsche Bank Securities Inc. The maximum
facility amount represents the amount the banks have committed to fund pursuant
to the terms of the credit agreement. 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.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
The
borrowing base may be increased to the extent of pro forma additional EBITDA
attributable to acquisitions or internal growth projects with approval of the
lenders. Our borrowing base as of December 31, 2007 was approximately
$356 million.
At
December 31, 2007, we had $80 million borrowed under our credit facility and we
had $5.3 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, 2007 was $270.8 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,
2007, our borrowing rates were the prime rate plus 1.25% or the LIBOR rate
plus 2.25%.
|
|
|
·
|
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, 2007, our letter of credit rate was
2.25%.
|
|
|
·
|
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, 2007, the commitment fee was
0.50%.
|
Collateral
under the credit facility consists of substantially all our assets. 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) and 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 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.
|
Required
|
Actual
|
|||||
|
Ratio
|
Ratio
as of
|
|||||
|
through
|
December
31,
|
|||||
|
Financial
Covenant
|
Requirement
|
June
30, 2008
|
2007
|
|||
|
Debt
Service Coverage Ratio
|
Minimum
|
2.75
to 1.0
|
3.39
to 1.0
|
|||
|
Leverage
Ratio
|
Maximum
|
6.5
to 1.0
|
1.1
to 1.0
|
|||
|
Funded
Indebtedness Ratio
|
Maximum
|
0.80
to 1.0
|
0.10
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 generated by us for the eight most recent quarters,
less the sum of the distributions made with respect to those
quarters. At December 31, 2007, the excess of distributable cash over
distributions under this provision of the credit facility was $38.1
million.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
The
carrying value of our debt under our credit facility approximates fair value
primarily because interest rates fluctuate with prevailing market rates, and the
applicable margin on outstanding borrowings reflect what we believe is
market.
11. Partners’
Capital and Distributions
Partner’s
capital at December 31, 2007 consists of 38,253,264 common units, including
2,829,055 units owned by our general partner, 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. Included in these amounts are the common units issued on
July 25, 2007 in connection with the Davison acquisition and common units issued
in December 2007 in connection with a public offering.
We issued
13,459,209 common units to the entities owned and controlled by the Davison
family. The issuance of the units was recorded in the financial
statements at a value of $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 our
common units issued was determined using an average price of $24.52, which was
the average closing price of our common units for the two days before and after
the terms of the acquisition were agreed to and
announced. Additionally, 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.
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.
During
the four years ended December 31, 2007, we issued new common units to the public
and our general partner for cash as follows:
|
Period
|
Purchaser
of
Common
Units
|
Units
|
Gross
Unit
Price
|
Issuance
Value
|
GP
Contributions
|
Costs
|
Net
Proceeds
|
|||||||||||||||||||
|
(in
thousands, except per unit amounts)
|
||||||||||||||||||||||||||
|
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 | ||||||||||||||
|
December
2005
|
Public
|
4,140 | $ | 10.500 | $ | 43,470 | $ | 887 | $ | 2,889 | $ | 41,468 | ||||||||||||||
|
December
2005
|
General
Partner
|
331 | $ | 9.975 | $ | 3,298 | $ | 67 | $ | - | $ | 3,365 | ||||||||||||||
|
November
2003
|
General
Partner
|
689 | $ | 7.150 | $ | 4,925 | $ | 101 | $ | 14 | $ | 5,012 | ||||||||||||||
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. While the incentive interest
in our general partner may ultimately qualify as an equity award under SFAS
123(R), there is no mutual understanding of the terms of the award at December
31, 2007; therefore an amount could not be calculated in accordance with the
provisions of SFAS 123(R). The expense recorded for this arrangement
was an amount agreed to by the parties as a fair representation of the value
provided and earned in 2007. 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.
Our
general partner owns all of our general partner interest, including incentive
distribution rights, all of the 0.01% general partner interest in our operating
partnership (which is reflected as a minority interest in the consolidated
balance sheet at December 31, 2007) 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.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
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,
2007, our restricted net assets (as defined in Rule 4-03 (e)(3) of Regulation
S-X) were $593.7 million.
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. 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 | % | 25.74 | % | ||||
|
Over
Second Target - Cash distributions greater than $.033 per
Unit
|
49.02 | % | 50.98 | % | ||||
We paid
distributions in 2006 and 2007 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 2005
|
February
2006
|
$ | 0.170 | $ | 2,343 | $ | 48 | $ | - | $ | 2,391 | |||||||||||
|
First
quarter 2006
|
May
2006
|
$ | 0.180 | $ | 2,481 | $ | 51 | $ | - | $ | 2,532 | |||||||||||
|
Second
quarter 2006
|
August
2006
|
$ | 0.190 | $ | 2,619 | $ | 53 | $ | - | $ | 2,672 | |||||||||||
|
Third
quarter 2006
|
November
2006
|
$ | 0.200 | $ | 2,757 | $ | 56 | $ | - | $ | 2,813 | |||||||||||
|
Fourth
quarter 2006
|
February
2007
|
$ | 0.210 | $ | 2,895 | $ | 59 | $ | - | $ | 2,954 | |||||||||||
|
First
quarter 2007
|
May
2007
|
$ | 0.220 | $ | 3,032 | $ | 62 | $ | - | $ | 3,094 | |||||||||||
|
Second
quarter 2007
|
August
2007
|
$ | 0.230 | $ | 3,170 | (1) | $ | 65 | $ | - | $ | 3,235 | (1) | |||||||||
|
Third
quarter 2007
|
November
2007
|
$ | 0.270 | $ | 7,646 | $ | 156 | $ | 90 | $ | 7,892 | |||||||||||
|
Fourth
quarter 2007
|
February
2008
|
$ | 0.285 | $ | 10,902 | $ | 222 | $ | 245 | $ | 11,369 | |||||||||||
(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.
The total
amounts in the table above increased with the issuance of new common units in
December 2005, July 2007 and December 2007.
Net
Income (Loss) Per Common Unit
Subject
to the applicability of Emerging Issues Task Force Issue No. 03-06 (“EITF
03-06”), Participating Securities and the Two-Class Method under Financial
Accounting Standards Board Statement No. 128,” as discussed below, 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.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
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.
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
will 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, 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.
The
following table sets forth the computation of basic net (loss) income per common
unit for 2007, 2006, and 2005 (in thousands, except per unit
amounts).
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
(in
thousands, except per unit amounts)
|
||||||||||||
|
Numerators
for basic and diluted net (loss) income per common unit:
|
||||||||||||
|
(Loss)
income from continuing operations
|
$ | (13,550 | ) | $ | 8,351 | $ | 3,689 | |||||
|
Less
general partner 2% ownership
|
(271 | ) | 167 | 74 | ||||||||
|
(Loss)
income from continuing operations available for common
unitholders
|
$ | (13,279 | ) | $ | 8,184 | $ | 3,615 | |||||
|
Income
from discontinued operations
|
$ | - | $ | - | $ | 312 | ||||||
|
Less
general partner 2% ownership
|
- | - | 6 | |||||||||
|
Income
from discontinued operations available for common
unitholders
|
$ | - | $ | - | $ | 306 | ||||||
|
Income
(loss) from cumulative effect adjustment
|
$ | - | $ | 30 | $ | (586 | ) | |||||
|
Less
general partner 2% ownership
|
- | - | (12 | ) | ||||||||
|
Income
(loss) from cumulative effect adjustment available for common
unitholders
|
$ | - | $ | 30 | $ | (574 | ) | |||||
|
Denominator
for basic and diluted per common unit -weighted average number of common
units outstanding
|
20,754 | 13,784 | 9,547 | |||||||||
|
Basic
and diluted net (loss) income per common unit:
|
||||||||||||
|
(Loss)
income from continuing operations
|
$ | (0.64 | ) | $ | 0.59 | $ | 0.38 | |||||
|
Income
from discontinuted operations
|
- | - | 0.03 | |||||||||
|
Loss
from cumulative effect adjustment
|
- | - | (0.06 | ) | ||||||||
|
Net
(loss) income
|
$ | (0.64 | ) | $ | 0.59 | $ | 0.35 | |||||
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 CO2 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 CO2 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 crude oil and
petroleum products and other dry goods. Our Supply and Logistics
segment was previously known as Crude Oil Gathering and
Marketing. With the Davison acquisition, we expanded our operations
into petroleum products and other transportation services, and combined these
operations due to their similarities and our approach to managing these
operations. 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. The tables below reflect our segment information as
though the current segment designations had existed in all periods
presented.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
We
evaluate segment performance based on segment margin. We calculate
segment margin as revenues less costs of sales and operating expenses, and we
include income from investments in joint ventures. We do not deduct depreciation
and amortization. All of our revenues are derived from, and all of
our assets are located in the United States. The pipeline
transportation segment information includes the revenue, segment margin and
assets of our direct financing leases.
|
Pipeline
|
Refinery
|
Industrial
|
Supply
&
|
|||||||||||||||||
|
Transportation
|
Services
|
Gases
(a)
|
Logistics
|
Total
|
||||||||||||||||
|
(in
thousands)
|
||||||||||||||||||||
|
Year Ended December
31, 2007
|
||||||||||||||||||||
|
Segment
margin excluding depreciation and amortization (b)
|
$ | 13,035 | $ | 21,898 | $ | 12,063 | $ | 15,330 | $ | 62,326 | ||||||||||
|
Capital
expenditures
|
$ | 6,592 | $ | 1,448 | $ | 1,104 | $ | 1,141 | $ | 10,285 | ||||||||||
|
Maintenance
capital expenditures
|
$ | 2,880 | $ | 469 | - | $ | 491 | $ | 3,840 | |||||||||||
|
Net
fixed and other long-term assets (c)
|
$ | 32,936 | $ | 468,068 | $ | 47,364 | $ | 145,915 | $ | 694,283 | ||||||||||
|
Revenues:
|
||||||||||||||||||||
|
External
customers
|
$ | 23,226 | $ | 62,095 | $ | 16,158 | $ | 1,094,189 | $ | 1,195,668 | ||||||||||
|
Intersegment
(d)
|
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)
|
$ | 12,426 | - | $ | 11,443 | $ | 7,366 | $ | 31,235 | |||||||||||
|
Capital
expenditures
|
$ | 971 | - | $ | 6,058 | $ | 356 | $ | 7,385 | |||||||||||
|
Maintenance
capital expenditures
|
$ | 611 | - | - | $ | 356 | $ | 967 | ||||||||||||
|
Net
fixed and other long-term assets (c)
|
$ | 31,863 | - | $ | 51,630 | $ | 7,602 | $ | 91,095 | |||||||||||
|
Revenues:
|
||||||||||||||||||||
|
External
customers
|
$ | 25,479 | - | $ | 15,154 | $ | 873,268 | $ | 913,901 | |||||||||||
|
Intersegment
(d)
|
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
|
Pipeline Transportation |
Refinery Services |
Industrial Gases (a) |
Supply
& Logistics |
Total
|
||||||||||||||||
|
(in
thousands)
|
||||||||||||||||||||
|
Year Ended December
31, 2005
|
||||||||||||||||||||
|
Segment
margin excluding depreciation and amortization (b)
|
$ | 9,804 | - | $ | 8,154 | $ | 3,661 | $ | 21,619 | |||||||||||
|
Capital
expenditures
|
$ | 5,425 | - | $ | 27,864 | $ | 547 | $ | 33,836 | |||||||||||
|
Maintenance
capital expenditures
|
$ | 1,256 | - | - | $ | 287 | $ | 1,543 | ||||||||||||
|
Net
fixed and other long-term assets (c)
|
$ | 34,725 | - | $ | 50,690 | $ | 5,913 | $ | 91,328 | |||||||||||
|
Revenues:
|
||||||||||||||||||||
|
External
customers
|
$ | 25,613 | - | $ | 11,302 | $ | 1,038,549 | $ | 1,075,464 | |||||||||||
|
Intersegment
(d)
|
3,275 | - | - | - | 3,275 | |||||||||||||||
|
Total
revenues of reportable segments
|
$ | 28,888 | - | $ | 11,302 | $ | 1,038,549 | $ | 1,078,739 | |||||||||||
|
|
(a)
|
The
industrial gases segment includes our CO2
marketing operations and the income from our investments in T&P Syngas
Supply Company and Sandhill Group,
LLC.
|
|
|
(b)
|
Segment
margin was calculated as revenues less cost of sales and operations
expense. It includes our share of the operating income of
equity joint ventures. A reconciliation of segment margin to
income before income taxes and minority interest for each year presented
is as follows:
|
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Segment
margin excluding depreciation and amortization
|
$ | 62,326 | $ | 31,235 | $ | 21,619 | ||||||
|
General
and administrative expenses
|
(25,920 | ) | (13,573 | ) | (9,656 | ) | ||||||
|
Depreciation,
amortization and impairment
|
(40,245 | ) | (7,963 | ) | (6,721 | ) | ||||||
|
Net
(loss) gain on disposal of surplus assets
|
(266 | ) | 16 | 479 | ||||||||
|
Interest
expense, net
|
(10,100 | ) | (1,374 | ) | (2,032 | ) | ||||||
|
(Loss)
income from continuing operations before income taxes and minority
interest
|
$ | (14,205 | ) | $ | 8,341 | $ | 3,689 | |||||
|
|
(c)
|
Net
fixed and other long-term assets are the measure used by management in
evaluating the results of its operations on a segment
basis. Current assets are not allocated to segments as the
amounts are shared by the segments or are not meaningful in evaluating the
success of the segment’s
operations.
|
|
|
(d)
|
Intersegment
sales were conducted on an arm’s length
basis.
|
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
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.
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Truck
transportation services provided to Denbury
|
$ | 1,791 | $ | 825 | $ | 796 | ||||||
|
Pipeline
transportation services provided to Denbury
|
$ | 5,290 | $ | 4,228 | $ | 3,853 | ||||||
|
Payments
received under direct financing leases from Denbury
|
$ | 1,188 | $ | 1,186 | $ | 1,186 | ||||||
|
Pipeline
transportation income portion of direct financing lease
fees
|
$ | 641 | $ | 655 | $ | 689 | ||||||
|
Pipeline
monitoring services provided to Denbury
|
$ | 120 | $ | 65 | $ | 30 | ||||||
|
Directors'
fees paid to Denbury
|
$ | 150 | $ | 120 | $ | 120 | ||||||
|
CO2
transportation services provided by Denbury
|
$ | 5,213 | $ | 4,640 | $ | 3,501 | ||||||
|
Crude
oil purchases from Denbury
|
$ | 101 | $ | 1,565 | $ | 4,647 | ||||||
|
Crude
oil sales to Denbury
|
$ | - | $ | - | $ | 176 | ||||||
|
Purchase
of CO2
volumetric production payment from Denbury
|
$ | - | $ | - | $ | 14,363 | ||||||
|
Operations,
general and administrative services provided by our general
partner
|
$ | 22,490 | $ | 16,777 | $ | 15,145 | ||||||
|
Distributions
to our general partner on its limited partner units and general partner
interest
|
$ | 1,671 | $ | 963 | $ | 536 | ||||||
|
Sales
of CO2 to
Sandhill (for the period since Sandhill became a related
party)
|
$ | 2,783 | $ | 2,056 | $ | - | ||||||
|
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
gathering and marketing revenues.
Denbury
is the only shipper on our Mississippi pipeline other than us, and we earned
tariffs for transporting their crude oil. We also earned fees from
Denbury under the direct financing lease arrangements for the Olive and
Brookhaven crude oil pipelines and the Brookhaven CO2 pipeline
and recorded pipeline transportation income from these
arrangements. See Note 6.
We also
provide pipeline monitoring services to Denbury. This revenue is
included in pipeline revenues in the statement 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 a rate that was $10,000 per person less
annually than the rate at which our independent directors were
paid.
CO2 Operations
and Transportation
We
acquired contracts, along with volumetric production payments, from Denbury in
2005 and 2004. Denbury charges us a transportation fee of $0.16 per
Mcf (adjusted for inflation) to deliver the CO2 for us to
our customers. See Note 7.
Sales
and Purchases of Crude Oil
Denbury
began shipping its own crude oil on our Mississippi System in September 2004, so
our purchases of crude oil from Denbury (and our related crude oil sales) have
declined.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
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.
Transition
Services from Davison
Until the
end of 2007, the Davison family is providing certain transition services to us
related to the payroll for persons who provide services to us. These
persons became employees of our general partner on January 1, 2008; however, to
create the least disruption for employees while we evaluated benefit plan
arrangements, the personnel in our Supply and Logistics operations acquired from
Davison were paid by entities owned by the Davison family and we reimbursed them
for all direct costs.
Amounts
due to and from Related Parties
At
December 31, 2007 and 2006, we owed Denbury $1.0 million and $0.8 million,
respectively, for purchases of crude oil and CO2
transportation charges. Denbury owed us $0.9 million and $0.6 million
for transportation services at December 31, 2007 and 2006,
respectively. We owed our general partner $0.7 million and $0.9
million for administrative services at December 31, 2007 and 2006,
respectively. At December 31, 2007 and 2006 Sandhill owed us $0.5
million, respectively for purchases of CO2. At
December 31, 2007, we owed the Davison family entities $0.8 million for
reimbursement of costs paid primarily related to employee transition
services.
Financing
Our
general partner, a wholly owned subsidiary of Denbury, guarantees our
obligations under our credit facility. Our general partner’s
principal assets are its general and limited partnership interests in
us. The obligations are not guaranteed by Denbury or any of its other
subsidiaries. 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 our operating partnership.
We
guarantee 50% of the obligation of Sandhill to a bank. At December
31, 2007, the total amount of Sandhill’s obligation to the bank was $3.9
million; therefore, our guarantee was for $1.95 million. See Note
8.
As
discussed in Note 11, our general partner purchased common units and made
general partner contributions in order to maintain its capital account totaling
$37.9 million and $10.6 million, respectively. In addition, our
general partner made a capital contribution of $1.5 million in December 2007 to
offset a portion of the severance payment to a former executive.
14. Supplemental
Cash Flow Information
Cash
received by us for interest during the years ended December 31, 2007, 2006 and
2005 was $269,000, $192,000 and $46,000, respectively. Payments of
interest and commitment fees were $8,401,000, $1,041,000 and $1,468,000, during
the years ended December 31, 2007, 2006 and 2005, respectively.
Cash paid
for income taxes in during the year ended December 31, 2007 was
$1,600,000.
At
December 31, 2007 and 2006, we had incurred liabilities for fixed asset
additions totaling $893,000 and $81,000, 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 $271,000
and $46,000 at December 31, 2007 and 2006, respectively 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 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 by which they are
expected to earn an interest in our general partner.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
15. Employee
Benefit Plans and Unit-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
our 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 $821,000,
$660,000, and $620,000 for the years ended December 31, 2007, 2006 and 2005,
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 $1,454,000, $1,269,000, and $1,773,000 in
2007, 2006 and 2005, respectively.
Stock
Appreciation Rights Plan
Under the
terms of our stock appreciation rights plan, all regular, full-time active
employees (with the exception of the new senior management team) 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, 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. The initial
award to a participant will vest one-fourth each year beginning with the first
anniversary of the grant date of the award. Subsequent awards to
participants will vest on the fourth anniversary of the grant
date. 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.
Prior to
January 1, 2006, we had accounted for this plan under the provisions of 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. On January 1, 2006, we adopted SFAS No.
123 (revised December 2004), “Share-Based Payments.” The adoption of
this statement required 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. 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.
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.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
The
estimates that we made upon the adoption of this standard included the following
assumptions:
|
|
·
|
In
determining the expected life of the rights, we used 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 simplified method produces an initial
expected life of 6.25 years for those rights we issued that vest 25% per
year for four years, and an initial expected life of 7 years for those
rights we issued that fully vest at the end of a four-year
period.
|
|
|
·
|
The
expected volatility of our units was 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 expected
volatility used in the fair value calculations was approximately 34% and
32% at December 31, 2007 and December 31, 2006,
respectively.
|
|
|
·
|
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. At December 31, 2007, the risk-free
interest rate ranged from 3.12% to 3.65%. At December 31, 2006, the
risk-free interest rate ranged from 4.53% to
4.57%.
|
|
|
·
|
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. At
December 31, 2007 and December 31, 2006, we used an expected future
distribution yield of 6%.
|
|
|
·
|
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.
|
At
December 31, 2005, we had a recorded liability of $0.8 million, computed under
the provisions of FASB Interpretation No. 28. We calculated the
effect of adoption of SFAS 123(R) at January 1, 2006, and determined that our
recorded liability at December 31, 2005 should be reduced by
$30,000. This reduction is reflected as income from the cumulative
effect of the adoption of a new accounting principle on our statement of
operations. We do not believe the effect of adoption of this
accounting principle at January 1, 2005 would have been material. The
adjustment of the liability to its fair value of $2.4 million at December 31,
2006, resulted in total expense of $1.9 million for the year ended December 31,
2006, with $0.3 million, $0.3 million and $1.3 million included in field
operating costs, pipeline operating costs and general and administrative
expenses, respectively. The adjustment of the liability to its fair
value of $3.3 million at December 31, 2007, resulted in total expense of $2.5
million for the year ended December 31, 2007, with $0.5 million, $0.4 million
and $1.6 million included in field operating costs, pipeline operating costs and
general and administrative expenses, respectively.
The
following table reflects rights activity under our plan as of January 1, 2007,
and changes during the year ended December 31, 2006:
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
|
Stock
Appreciation Rights
|
Rights
|
Weighted
Average Exercise Price
|
Weighted
Average Contractual Remaining Term (Yrs)
|
Aggregate
Intrinsic Value (in
thousands)
|
||||||||||||
|
Outstanding
at January 1, 2007
|
659,010 | $ | 12.79 | |||||||||||||
|
Granted
during 2007
|
99,430 | $ | 29.06 | |||||||||||||
|
Exercised
during 2007
|
(94,267 | ) | $ | 10.06 | ||||||||||||
|
Forfeited
or expired during 2007
|
(70,715 | ) | $ | 16.97 | ||||||||||||
|
Outstanding
at December 31, 2007
|
593,458 | $ | 15.45 | 8.0 | $ | 5,177 | ||||||||||
|
Exercisable
at December 31, 2007
|
231,021 | $ | 11.05 | 6.7 | $ | 2,912 | ||||||||||
The
weighted-average fair value at December 31, 2007 of rights granted during 2007
was $3.56 per right. The total intrinsic value of rights exercised
during 2007 was $1,599,000, which was paid in cash to the
participants.
At
December 31, 2007, there was $1.2 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, 2007 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, 2007, the
remaining cost will be recognized over a weighted average period of one
year.
Prior to
January 1, 2006, the method of accounting for our stock appreciation rights plan
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. In 2005, we recorded a non-cash credit of $0.5 million in
general and administrative expense for the decrease in the value of the
outstanding rights due to the decrease in the closing market price for common
units between December 31, 2005 and December 31, 2004.
2007
Long Term Incentive Plan
At a
special meeting of the unitholders of Genesis Energy, L.P on December 18, 2007,
our unitholders approved the Genesis Energy, Inc. 2007 Long Term Incentive Plan
(the “2007 LTIP”), which provides for awards of Phantom Units and Distribution
Equivalent Rights to non-employee directors and employees of Genesis Energy,
Inc., 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.
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
960,638 remain authorized for issuance at December 31, 2007. In
December 2007, 39,362 Phantom Units were granted with the vesting restrictions
on those units follows: (a) 47% of the awards vest 33-1/3% per year over three
years and, (b) 53% of the awards vest at the end of three
years. 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 goup of employees 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, 2007.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
As of
December 31, 2007, there was $0.8 million of unrecognized compensation expense
related to these units. This unrecognized compensation cost is
expected to be recognized over a weighted-average period of 3.0
years.
The
following table summarizes information regarding our non-vested Phantom Unit
grants as of December 31, 2007:
|
Non-vested
Phantom Unit Grants
|
Number
of
Units
|
Weighted-Average
Grant-Date
Fair
Value
|
||||||
|
Non-vested
at January 1, 2007 Granted
|
39,362 | $ | 21.92 | |||||
|
Non-vested
at December 31, 2007
|
39,362 | |||||||
The
aggregate grant date fair value of Phantom Unit awards granted during 2007 was
$0.9 million based on the grant date market price of our common units of $24.52
per unit, adjusted for distributions that holders of phantom units will not
receive during the vesting period. The grant-date fair value of the
award was 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. Our expected distribution rate was based on our the rate of the
distribution we paid in November 2007 of $0.27 and the risk-free interest rates
in calculating the present value of our expected dividends ranged from 3.19% to
3.31%.
Bonus
Plan
In March
2003, the Compensation Committee of the Board of Directors of our general
partner approved a Bonus Plan for all employees of the general partner (with the
exception of the new senior management team.) Through December 31,
2007, the Bonus Plan excluded the personnel in the Davison operations who became
employees of the general partner on January 1, 2008. The Bonus Plan
is designed to enhance the financial performance of the Partnership by rewarding
all employees for achieving financial performance objectives. The
Bonus Plan is administered by the Compensation Committee. Under this
plan, amounts will be allocated for the payment of bonuses to employees each
time our operating partnership earns $2.0 million of available cash, subject to
certain adjustments. The amount allocated to the bonus pool increases
for each $2.0 million earned, such that a bonus pool of $2.3 million will exist
if the Partnership earns $18.4 million of available cash. We accrued
$2.0 million, $1.8 million and $1.2 million for the bonus pool for 2007, 2006
and 2005, respectively.
Bonuses
will be paid to employees after the end of the year, but only if distributions
are made to the common unitholders. The amount in the bonus pool will
be allocated to employees based on the group to which they are
assigned. Employees in the first group can receive bonuses that range
from zero to ten percent of base compensation. The next group
includes employees who could earn a total bonus ranging from zero to twenty
percent. Certain members are eligible to earn a total bonus ranging
from zero to thirty percent. Lastly, our officers, excluding our new
senior management team, and other key management are eligible for a total bonus
ranging from zero to forty percent. The Bonus Plan will be at the
discretion of the Compensation Committee, and our general partner can amend or
change the Bonus Plan at any time. Our Compensation Committee will
determine what changes are needed in the plan as a result of the Davison
acquisition.
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.
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 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. Occidental Energy Marketing, Inc. and Shell Oil Company
accounted for 26.5% and 12.5% of total revenues in 2005,
respectively. The revenues from these five customers in all three
years relate primarily to our gathering and marketing 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.
We may
utilize crude oil futures contracts and other financial derivatives to reduce
our exposure to unfavorable changes in crude oil prices and fuel oil
prices. Every derivative instrument (including certain derivative
instruments embedded in other contracts) must be recorded in the balance sheet
as either an asset or liability measured at its fair value. Changes
in the derivative’s fair value must be recognized currently in earnings unless
specific hedge accounting criteria are met. Special accounting for
qualifying hedges allows a derivative’s gains and losses to offset related
results on the hedged item in the income statement. We must formally
document, designate and assess the effectiveness of transactions that receive
hedge accounting.
We mark
to fair value our derivative instruments at each period end, with changes in the
fair value of derivatives that are not designated as hedges being recorded as
unrealized gains or losses. Such unrealized gains or losses will
change, based on prevailing market prices, at each balance sheet date prior to
the period in which the transaction actually occurs. The effective
portion of unrealized gains or losses on derivative transactions qualifying as
cash flow hedges are reflected in other comprehensive
income. Derivative transactions qualifying as fair value hedges are
evaluated for hedge effectiveness and the resulting hedge ineffectiveness is
recorded as a gain or loss in the consolidated statements of
operations.
We review
our contracts to determine if the contracts meet the definition of derivatives
pursuant to SFAS 133. At December 31, 2007, we had futures contracts
that were considered free-standing derivatives that are accounted for at fair
value. The fair value of these contracts was determined based on the
closing price for such contracts on December 31, 2007. We marked
these contracts to fair value at December 31, 2007. During the year
ended December 31, 2007, we recorded losses of $2,155,000 related to derivative
transactions, which are included in the consolidated statements of operations
under the caption “Supply and logistics costs.”
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
For a
portion of 2007 we had futures contracts that qualified as derivatives and were
formally documented and designated as fair value hedges of
inventory. During the year ended December 31, 2007 we recognized
gains, due to hedge ineffectiveness, on the fair value hedge of inventory of
approximately $119,000. These gains are included in the caption
“Product costs” in the consolidated statements of operations. The
time value component of the derivative gain or loss excluded from the assessment
of hedge effectiveness was not material. At December 31, 2007, our
fair value hedges of inventory were closed.
The
consolidated balance sheet at December 31, 2007 includes a decrease in other
current assets of $744,000 as a result of these derivative
transactions. The consolidated balance sheet at December 31, 2006
included an increase in other current assets of $165,000 as a result of
derivative transactions.
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, 2007 and December 31, 2006.
18. Commitments
and Contingencies
Commitments
and Guarantees
We lease
office space for our headquarters under a long-term lease that extends
until October 31, 2008. 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, 2007, were as follows (in thousands).
|
Office
Space
|
Transportation
Equipment
|
Terminals
and
Tanks
|
Total
|
|||||||||||||
|
2008
|
$ | 374 | $ | 4,075 | $ | 2,437 | $ | 6,886 | ||||||||
|
2009
|
121 | 3,024 | 1,177 | 4,322 | ||||||||||||
|
2010
|
84 | 2,263 | 516 | 2,863 | ||||||||||||
|
2011
|
63 | 1,576 | 387 | 2,026 | ||||||||||||
|
2012
|
63 | 1,135 | 322 | 1,520 | ||||||||||||
|
2013
and thereafter
|
16 | 3,488 | 7,272 | 10,776 | ||||||||||||
|
Total
minimum lease obligations
|
$ | 721 | $ | 15,561 | $ | 12,111 | $ | 28,393 | ||||||||
Total
operating lease expense was as follows (in thousands).
|
Year
ended December 31, 2007
|
$ | 6,079 | ||
|
Year
ended December 31, 2006
|
$ | 3,258 | ||
|
Year
ended December 31, 2005
|
$ | 3,929 |
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, 2007 were $80.0 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.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
We
guaranteed $1.2 million of residual value related to the leases of trailers from
Paccar. 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, 2007, Sandhill owed $3.9 million; therefore our
guarantee was $1.95 million. Sandhill makes principal payments for
this obligation totaling $0.6 million per year.
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.
Pennzoil
Litigation
We were
named a defendant in a complaint filed on January 11, 2001, in the 125th
District Court of Harris County, Texas, Cause No.
2001-01176. Pennzoil-Quaker State Company, or PQS, was seeking from
us property damages, loss of use and business interruption suffered as a result
of a fire and explosion that occurred at the Pennzoil Quaker State refinery in
Shreveport, Louisiana, on January 18, 2000. PQS claimed the fire and
explosion were caused, in part, by crude oil we sold to PQS that was
contaminated with organic chlorides. In December 2003, our insurance
carriers settled this litigation for $12.8 million.
PQS is
also a defendant in five consolidated class action/mass tort actions brought by
neighbors living in the vicinity of the PQS Shreveport, Louisiana refinery in
the First Judicial District Court, Caddo Parish, Louisiana, Cause Nos.
455,647-A, 455,658-B, 455,655-A, 456,574-A, and 458,379-C. PQS has
brought third party claims against us for indemnity with respect to the fire and
explosion of January 18, 2000. We believe that the demand against us
is without merit and intend to vigorously defend ourselves in this
matter. We currently believe that this matter will not have a
material financial effect on our financial position, results of operations, or
cash flows.
Environmental
In 1992,
Howell Crude Oil Company (“Howell”) entered into a sublease with Koch
Industries, Inc. (“Koch”), covering a one acre tract of land located in Santa
Rosa County, Florida to operate a crude oil trucking station, known as Jay
Station. The sublease provided that Howell would indemnify Koch for
environmental contamination on the property under certain
circumstances. Howell operated the Jay Station from 1992 until
December of 1996 when this operation was sold to us by Howell. We
operated the Jay Station as a crude oil trucking station until
2003. Koch incurred certain investigative and/or other costs,
for which Koch alleges some or all should be reimbursed by us, under the
indemnification provisions of the sublease for environmental contamination on
the site and surrounding areas. Koch has also alleged that we are
responsible for future environmental obligations relating to the Jay
Station.
Howell
was acquired by Anadarko Petroleum Corporation (“Anadarko”) in
2002. In 2005, we entered into a joint defense and cost allocation
agreement with Anadarko. Under the terms of the joint allocation
agreement, we agreed to reasonably cooperate with each other to address any
liabilities or defense costs with respect to the Jay
Station. Additionally under the joint allocation agreement, Anadarko
will be responsible for sixty percent of the costs related to any liabilities or
defense costs incurred with respect to contamination at the Jay
Station.
We were
formed in 1996 by the sale and contribution of assets from Howell and Basis
Petroleum, Inc. (“Basis”). Anadarko's liability with respect to the
Jay Station is derived largely from contractual obligations entered into upon
our formation. We believe that Basis has contractual obligations
under the same formation agreements. We intend to seek recovery of
Basis' share of potential liabilities and defense costs with respect to Jay
Station.
We have
developed a plan of remediation for affected soil and groundwater at Jay Station
which has been approved by appropriate state regulatory agencies. We
recorded an estimate of our share of liability for this matter in the amount of
$0.5 million, and in 2007 we increased the accrual by $0.3 million based on
updated estimates of the costs to complete the remediation. The time
period over which our liability would be paid is uncertain and could be several
years. This liability may decrease if indemnification and/or cost
reimbursement is obtained by us for Basis' potential liabilities with respect to
this matter. At this time, our estimate of potential obligations does
not assume any specific amount contributed on behalf of the Basis obligations,
although we believe that Basis is responsible for a significant part of these
potential obligations.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
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.
In
connection with the sale of pipeline assets in Texas in the fourth quarter of
2003, we retained responsibility for environmental matters related to the
operations of those pipelines in the periods prior to the date of the sales,
subject to certain conditions. On the majority of the pipelines sold,
our responsibility for any environmental claim will not exceed an aggregate
total of $2 million. Our responsibility for indemnification related
to these sales will cease in 2013.
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.
19. Income
Taxes
We are
not a taxable entity for federal income tax purposes. As such, we do
not directly pay federal income taxes. 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 will 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.”
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 will be 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
January 1, 2007 we had no unrecognized tax benefits. At
December 31, 2007 we have unrecognized tax benefits of $1million. 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, 2007 were recognized, $1million would affect our effective income
tax rate. There are no uncertain tax positions as of December 31,
2007 for which it is reasonably possible that the amount of unrecognized tax
benefits would significantly decrease during 2008.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
Our
income tax provision (benefit) is as follows (in thousands):
|
December
31,
2007
|
||||
|
Current:
|
||||
|
Federal
|
$ | 1,665 | ||
|
State
|
339 | |||
|
Total
current income tax expense
|
2,004 | |||
|
Deferred:
|
||||
|
Federal
|
(2,432 | ) | ||
|
State
|
(226 | ) | ||
|
Total
deferred income tax benefit
|
(2,658 | ) | ||
|
Total
income tax benefit
|
$ | (654 | ) | |
Deferred
income taxes relate to temporary differences based on tax laws and statutory
rates in effect at the December 31, 2007 balance sheet date. We
believe we will utilize all of our deferred tax assets at December 31, 2007, and
therefore have provided no valuation allowance against our deferred tax
assets. Deferred tax assets and liabilities consist of the following
(in thousands):
|
December
31,
2007
|
||||
|
Deferred
tax assets:
|
||||
|
Current:
|
||||
|
Other
current liabilities
|
$ | 43 | ||
|
Other
|
17 | |||
|
Total
current deferred tax asset
|
60 | |||
|
Net
operating loss carryforwards - federal
|
861 | |||
|
Net
operating loss carryforwards - state
|
80 | |||
|
Total
long-term deferred tax asset
|
941 | |||
|
Total
deferred tax assets
|
1,001 | |||
|
Deferred
tax liabilities:
|
||||
|
Current:
|
||||
|
Other
|
(24 | ) | ||
|
Long-term:
|
||||
|
Fixed
assets
|
(11,125 | ) | ||
|
Intangible
assets
|
(8,962 | ) | ||
|
Total
long-term liability
|
(20,087 | ) | ||
|
Total
deferred tax liabilities
|
(20,111 | ) | ||
|
Total
net deferred tax liability
|
$ | (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 (in
thousands):
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
|
December
31,
2007
|
||||
|
Loss
before income taxes
|
$ | (13,550 | ) | |
|
Partnership
loss not subject to tax
|
8,239 | |||
|
Loss
subject to income taxes
|
(5,311 | ) | ||
|
Tax
benefit at federal statutory rate
|
$ | (1,859 | ) | |
|
State
income taxes, net of federal benefit
|
33 | |||
|
Effects
of FIN 48, federal and state
|
1,168 | |||
|
Other
|
4 | |||
|
Income
tax benefit
|
$ | (654 | ) | |
|
Effective
tax rate on loss before income taxes
|
5 | % | ||
Schedule
I - Condensed Financial Information
Genesis
Energy, L.P. (Parent Company Only)
Condensed
Statements of Operations
|
Years
Ended December 31,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Equity
in (losses) earnings of subsidiary
|
$ | (13,550 | ) | $ | 8,381 | $ | 3,415 | |||||
|
Net
(loss) income
|
$ | (13,550 | ) | $ | 8,381 | $ | 3,415 | |||||
Condensed
Balance Sheets
|
December
31,
|
||||||||
|
2007
|
2006
|
|||||||
|
(in
thousands)
|
||||||||
|
Assets
|
||||||||
|
Cash
|
$ | 10 | $ | 6 | ||||
|
Investment
in subsidiary
|
664,480 | 118,338 | ||||||
|
Advances
to subsidiary
|
84 | 88 | ||||||
|
Total
Assets
|
$ | 664,574 | $ | 118,432 | ||||
|
Partners'
Capital
|
||||||||
|
Limited
Partners
|
$ | 647,340 | $ | 115,960 | ||||
|
General
Partner
|
17,234 | 2,472 | ||||||
|
Total
Partners' Capital
|
$ | 664,574 | $ | 118,432 | ||||
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,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Cash
Flows from Operating Activities:
|
||||||||||||
|
Net
(loss) income
|
$ | (13,550 | ) | $ | 8,381 | $ | 3,415 | |||||
|
Equity
in (earnings) losses of GCO
|
$ | 13,550 | $ | (8,381 | ) | $ | (3,415 | ) | ||||
|
Change
in advances to GCO
|
4 | - | - | |||||||||
|
Net
cash provided by operating activities
|
4 | - | - | |||||||||
|
Cash
Flows from Investing Activities:
|
||||||||||||
|
Investment
in GCO
|
(216,172 | ) | - | (44,833 | ) | |||||||
|
Distributions
from GCO - return of investment
|
17,175 | 10,408 | 5,798 | |||||||||
|
Net
cash provided by (used in) investing activities
|
(198,997 | ) | 10,408 | (39,035 | ) | |||||||
|
Cash
Flows from Financing Activities:
|
||||||||||||
|
Issuance
of limited and general partner interests, net
|
216,172 | - | 44,833 | |||||||||
|
Distributions
to limited and general partners
|
(17,175 | ) | (10,408 | ) | (5,798 | ) | ||||||
|
Net
cash (used in) provided by financing activities
|
198,997 | (10,408 | ) | 39,035 | ||||||||
|
Net
increase in cash
|
4 | - | - | |||||||||
|
Cash
at beginning of period
|
$ | 6 | $ | 6 | $ | 6 | ||||||
|
Cash
at end of period
|
$ | 10 | $ | 6 | $ | 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
As
discussed in Note 10 of the Notes to the Consolidated Financial Statements, the
terms of the credit facility with Genesis Crude Oil, L.P., or GCO, limit the
amount of distributions that GCO and its subsidiaries may pay to Genesis Energy,
L.P., or 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 subsidiary.
The
parent company only financial statements for GEL summarize the results of
operations and cash flows for the years ended December 31, 2007, 2006 and 2005,
and the financial position as of December 31, 2007 and 2006. In these
statements, GEL’s investment in GCO is 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.
2. Contingencies
GEL
guarantees the obligations of GCO under our credit facility. See Note
10 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 18 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 $46.8 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.
3. Supplemental
Cash Flow Information
In July
2007, GCO common units with a value of $330 million were issued to GEL. GEL
issued common units with an equal value as part of the consideration in the
Davison acquisition. These transactions are non-cash transactions and
are not included in the Statements of Cash Flows in investing or financing
activities.
133