GENESIS ENERGY LP
10-Ks and 10-Qs
UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington,
D.C. 20549
Form
10-K
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T
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ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
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For
the fiscal year ended December 31, 2009
OR
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£
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TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
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Commission
file number 1-12295
GENESIS
ENERGY, L.P.
(Exact
name of registrant as specified in its charter)
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Delaware
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76-0513049
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(State
or other jurisdiction of
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(I.R.S.
Employer
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| incorporation or organization) | Identification No.) |
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919
Milam, Suite 2100, Houston, TX
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77002
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(Address
of principal executive offices)
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(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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Common
Units
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NYSE
Amex LLC
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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
R
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
R
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
R
No
£
Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding
12 months (or for such shorter period that the registrant was required to submit
and post such files).
Yes
£
No
£
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the best
of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.
R
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
R
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Non-accelerated
filer
£
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Smaller
reporting company
£
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Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2) of the Act).
Yes
£
No
R
The
aggregate market value of the common units held by non-affiliates of the
Registrant on June 30, 2009 (the last business day of Registrant’s most recently
completed second fiscal quarter) was approximately $300,168,000 based on $12.72
per unit, the closing price of the common units as reported on the NYSE Amex LLC
(formerly the American Stock Exchange.) For purposes of this
computation, all executive officers, directors and 10% owners of the registrant
are deemed to be affiliates. Such a determination should not be
deemed an admission that such executive officers, directors and 10% beneficial
owners are affiliates. On February 19, 2010, the Registrant had
39,585,692 common units outstanding.
1
GE
NESIS ENERGY, L.P.
2009
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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36
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Item 2.
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36
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Item 3.
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36
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Item 4.
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36
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Part
II
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Item 5.
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36
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Item 6.
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38
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Item 7.
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40
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Item 7A.
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63
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Item 8.
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65
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Item 9.
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65
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Item 9A.
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65
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Item 9B.
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67
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Part
III
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Item 10.
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67
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Item 11.
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70
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Item 12.
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88
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Item 13.
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90
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Item 14.
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93
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Part
IV
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Item 15.
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94
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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 or bankruptcy 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.
It
em 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 (including DG Marine, as defined);
“DG Marine” means DG Marine Transportation, LLC and its subsidiaries; “Quintana”
means Quintana Capital Group II, L.P. and its affiliates; “CO
2
” means
carbon dioxide; and “NaHS”, which is commonly pronounced as “nash”, means sodium
hydrosulfide.
DG Marine
is a joint venture in which we own an effective 49% economic
interest. Our joint venture partner holds a 51% economic interest and
controls decision-making over key operational matters. For financial
reporting purposes, we consolidate DG Marine as discussed in Note 3 to the
Consolidated Financial Statements. References in this annual report
to DG Marine include 100% of the operations and activities of DG Marine unless
the context indicates differently.
Except to
the extent otherwise provided, the information contained in this form is as of
December 31, 2009.
General
We are a
growth-oriented limited partnership focused on the midstream segment of the oil
and gas industry in the Gulf Coast region of the United States, primarily Texas,
Louisiana, Arkansas, Mississippi, Alabama and Florida. We were formed
in 1996 as a master limited partnership, or MLP. We have a diverse
portfolio of customers, operations and assets, including refinery-related
plants, pipelines, storage tanks and terminals, barges, and
trucks. We provide an integrated suite of services to refineries;
oil, natural gas and CO
2
producers;
industrial and commercial enterprises that use NaHS and caustic soda; and
businesses that use CO
2
and other
industrial gases. Substantially all of our revenues are derived from
providing services to integrated oil companies, large independent oil and gas or
refinery companies, and large industrial and commercial
enterprises.
We
conduct our operations 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. We manage our businesses through four
divisions that constitute our reportable segments:
Pipeline Transportation
—We
transport crude oil and CO
2
for others
for a fee in the Gulf Coast region of the U.S. through approximately 550 miles
of pipeline. Our Pipeline Transportation segment owns and operates
three crude oil common carrier pipelines and two CO
2
pipelines. Our 235-mile Mississippi System provides shippers of crude
oil in Mississippi indirect access to refineries, pipelines, storage terminals
and other crude oil infrastructure located in the Midwest. Our 100-mile Jay
System originates in southern Alabama and the panhandle of Florida and provides
crude oil shippers access to refineries, pipelines and storage near Mobile,
Alabama. Our 90-mile Texas System transports crude oil from West
Columbia to several delivery points near Houston. Our crude oil
pipeline systems include access to a total of approximately 0.7 million barrels
of crude oil storage.
Our Free
State Pipeline is an 86-mile, 20” CO
2
pipeline
that extends from CO
2
source
fields near Jackson, Mississippi, to oil fields in eastern
Mississippi. We have a twenty-year transportation services agreement
(through 2028) related to the transportation of CO
2
on our
Free State Pipeline.
In
addition, Denbury Resources Inc. and its subsidiaries (Denbury) has leased from
us (through 2028) the NEJD Pipeline System, a 183-mile, 20” CO
2
pipeline
extending from the Jackson Dome, near Jackson, Mississippi, to near
Donaldsonville, Louisiana. The NEJD System transports CO
2
to
tertiary oil recovery operations in southwest Mississippi.
Refinery Services
—We
primarily (i) provide services to eight refining operations located
predominantly in Texas, Louisiana and Arkansas; (ii) operate significant storage
and transportation assets in relation to our business and (iii) sell NaHS
(commonly pronounced as “nash”) and caustic soda to large industrial and
commercial companies. Our refinery services primarily involve
processing refiner’s high sulfur (or “sour”) gas streams to remove the sulfur.
NaHS is a by-product derived from our refinery services process, and it
constitutes the sole consideration we receive for these services. A
majority of the NaHS we receive is sourced from refineries owned and operated by
large companies, including ConocoPhillips, CITGO and Ergon. Our refinery
services footprint also includes terminals and we utilize railcars, ships,
barges and trucks to transport product. Our refinery services
contracts are typically long-term in nature and have an average remaining term
of four years. We believe we are one of the largest marketers of NaHS
in North and South America.
Supply and Logistics
—We
provide services primarily to Gulf Coast oil and gas producers and refineries
through a combination of purchasing , transporting, storing, blending
and marketing of crude oil and refined products, primarily fuel
oil. In connection with these services, we utilize our portfolio of
logistical assets consisting of trucks, terminals, pipelines and
barges. We have access to a suite of more than 270 trucks, 270
trailers and 1.6 million barrels of terminal storage capacity in multiple
locations along the Gulf Coast as well as capacity associated with our three
common carrier crude oil pipelines. In addition, our ownership interest in DG
Marine provides us with access to twenty barges which, in the aggregate, include
approximately 660,000 barrels of refined product transportation
capacity. Usually, our supply and logistics segment experiences
limited commodity price risk because it involves back-to-back purchases and
sales, matching our sale and purchase volumes on a monthly
basis. Unsold volumes are hedged with NYMEX derivatives to offset the
remaining price risk.
Industrial
Gases
.
We
provide CO
2
and
certain other industrial gases and related services to industrial and commercial
enterprises.
We supply
CO
2
to industrial customers under long-term contracts. Our
compensation for supplying CO
2
to our industrial customers is the effective difference between the price at
which we sell our CO
2
under each contract and the price at which we acquired our CO
2
pursuant to our volumetric production payments (also known as VPPs), minus
transportation costs. In addition to supplying CO
2
, we own a
50% joint venture interest in T&P Syngas, from which we receive
distributions earned from fees for manufacturing syngas (a combination of carbon
monoxide and hydrogen), by Praxair, our 50% joint venture
partner. Our other joint venture is a 50% interest in Sandhill Group,
LLC, through which we process raw CO
2
for sale
to other customers for uses ranging from completing oil and natural gas
producing wells to food processing.
Our
General Partner and our Relationship with Quintana Capital Group and the Davison
Family
On
February 5, 2010, affiliates and co-investors of Quintana Capital Group II,
L.P., along with members of the Davison family and members of our Senior
Executive Management team (collectively the Quintana-Controlled Owner Group),
acquired control of our general partner. Our general partner owns all
of our general partner interest and all of our incentive distribution
rights.
Quintana,
an energy-focused private-equity firm headquartered in Houston, Texas, has
stated that it intends to use us as one of its primary vehicles for investing in
the midstream segment of the energy sector. Through its affiliated
investment funds, Quintana, which has offices in Houston, Dallas and Midland,
Texas and Beijing, China, currently manages approximately $900 million in
capital for various U.S. and international investors. Quintana
focuses on control-oriented investments across a wide range of sectors in the
energy industry, developing a portfolio that is diversified across the energy
value chain. Quintana is managed by highly experienced investors,
including Corbin J. Robertson, Jr. and former Secretary of Commerce Donald L.
Evans.
Members
of the Davison family have invested in us since 2007. In addition to
their investment in our general partner, members of the Davison family own
approximately 30% of our common units and 51% of DG Marine, our inland marine
transportation joint venture.
Prior to
Quintana’s investment in us, Denbury Resources Inc. (NYSE:DNR) controlled our
general partner. Denbury retained ownership of 10.2% of our
outstanding common units after the sale to Quintana.
Although
affiliates of our general partner are our investors, customers and
transaction counterparties from time to time, neither our general partner nor
any of its affiliates is obligated to enter into any additional transactions
with (or to offer any opportunities to) us or to promote our interest, and
neither our general partner or any of its affiliates 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, our general partner and each of its
affiliates may, at any time, and without notice, alter its business strategy,
including determining that it no longer desires to use us as an investment
vehicle or a provider of any services. If our general partner or any
of its affiliates were to make one or more offers to us, we cannot say that we
would elect to pursue or consummate any such opportunity. Thus,
though our relationship with our general partner is a strength, it also is a
source of potential conflicts. For more information regarding our
relationships with Quintana, members of the Davison family, and certain other
affiliates, please read the section entitled “Certain Relationships and Related
Transactions, and Director Independence.”
Business Strategy
Our
primary business strategy is to provide an integrated suite of transportation,
storage and marketing services to oil and gas producers, refineries and other
customers. Successfully executing this strategy will enable us
to generate sustainable cash flows to allow us to make quarterly cash
distributions to our unitholders and to increase those distributions over
time. We intend to develop our business by:
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Maintaining
a balanced and diversified portfolio of assets to service our
customers
;
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Optimizing
our existing assets and creating synergies through additional commercial
and operating advancement;
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Enhancing
and offering additional types of services to customers in our supply and
logistics segment;
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Expanding
the geographic reach of our refinery services and supply and logistics
segments; and
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Broadening
our asset base through strategic organic development projects as well as
acquisitions.
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Financial Strategy
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We
believe that preserving financial flexibility is an important factor in our
overall strategy and success. Over the long-term, we intend
to:
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Maintain
a prudent capital structure that will allow us to execute our growth
strategy;
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Enhance
our credit metrics and gain access to additional
liquidity;
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Increase
cash flows generated through fee-based services, emphasizing longer-term
contractual arrangements and managing commodity price risks;
and
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Create
strategic arrangements and share capital costs and risks through joint
ventures and strategic alliances.
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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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Our businesses encompass a
balanced, diversified portfolio of customers, operations and
assets.
We operate four business segments and own and operate
assets which enable us to provide a number of services to refinery owners;
oil, natural gas and CO
2
producers; industrial and commercial enterprises that use NaHS and caustic
soda; and businesses which use CO
2
and
other industrial gases. Our business lines complement each
other as they allow us to offer an integrated suite of services to common
customers across segments.
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Our pipeline transportation
and related assets are strategically located.
Our owned and
operated crude oil pipelines are located in the Gulf Coast region and
provide our customers access to multiple delivery points. In addition, a
majority of our terminals are located in areas which can be accessed by
either truck, rail or barge,
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The scale of our refinery
services operations as well as our expertise and reputation for high
performance standards and quality enable us to provide refiners with
economic and proven services.
We believe we are one of the largest
marketers of NaHS in North and South America and we have a suite of assets
which enables us to facilitate growth in our business. In addition, our
extensive understanding of the sulfur removal process and refinery
services market provides us with an advantage when evaluating new
opportunities and/or markets.
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Our supply and logistics
business is operationally flexible.
Our portfolio of trucks, barges
and terminals affords us flexibility within our existing regional
footprint and the capability to enter new markets and expand our customer
relationships.
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We are financially flexible
and maintain significant liquidity.
As of December 31, 2009, we had
$320 million of loans and $5.2 million in letters of credit outstanding
under our $500 million credit facility. Our borrowing base was
$407 million at December 31, 2009.
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Experienced, Knowledgeable and
Motivated Senior Executive Management Team with Proven Track
Record
. Our senior executive management team has an average of more
than 25 years of experience in the midstream sector. They have worked
together and separately in leadership roles at a number of large,
successful public companies, including other publicly-traded partnerships.
Through their ownership in our limited partner and general partner, our
senior executive management team is incentivized to create value for our
equity holders.
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2010
Developments
Association
with Quintana Capital Group
In
February 2010, the Quintana-Controlled Owner Group acquired control of our
general partner. Our general partner owns all our general partner
interest and all of our incentive distribution rights.
Eighteen
Consecutive Distribution Rate Increases
We have
increased our quarterly distribution rate for eighteen consecutive
quarters. On February 12, 2010,
we paid a cash
distribution of $0.36 per unit to unitholders of record as of February 5, 2010,
an increase per unit of $0.0075 (or 2.1%) from the distribution in the prior
quarter, and an increase of 9.1% from the distribution in February
2009. 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.
Description
of Segments and Related Assets
We
conduct our business through four primary segments: Pipeline Transportation,
Refinery Services, Industrial Gases and Supply and Logistics. These segments are
strategic business units that provide a variety of energy-related
services. Financial information with respect to each of our segments
can be found in Note 13 to our Consolidated Financial Statements.
Pipeline
Transportation
Crude
Oil Pipelines
Overview.
Our core
pipeline transportation business is the transportation of crude oil for others
for a fee. Through the pipeline systems we own and operate, we
transport crude oil for our gathering and marketing operations and for other
shippers pursuant to tariff rates regulated by the Federal Energy Regulatory
Commission, or FERC, or the Railroad Commission of
Texas. Accordingly, we offer transportation services to any shipper
of crude oil, if the products tendered for transportation satisfy the conditions
and specifications contained in the applicable tariff. Pipeline
revenues are a function of the level of throughput and the particular point
where the crude oil was injected into the pipeline and the delivery
point. We also can earn revenue from pipeline loss allowance
volumes. In exchange for bearing the risk of pipeline volumetric
losses, we deduct volumetric pipeline loss allowances and crude oil quality
deductions. Such allowances and deductions are offset by measurement
gains and losses. When our actual volume losses are less than the
related allowances and deductions, we recognize the difference as income and
inventory available for sale valued at the market price for the crude
oil.
The
margins from our crude oil pipeline operations are generated by the difference
between the sum of revenues from regulated published tariffs and pipeline loss
allowance revenues and the fixed and variable costs of operating and maintaining
our pipelines.
We own
and operate three 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 which are in various phases of being produced
through tertiary recovery strategy, including CO
2
injection
and flooding. Increased production from these fields could create
increased demand for our crude oil transportation services because of the close
proximity of our pipeline.
We
provide transportation services on our Mississippi pipeline through an
“incentive” tariff which provides that the average rate per barrel that we
charge during any month decreases as our aggregate throughput for that month
increases above specified thresholds.
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.
We
completed construction of an extension of our existing Florida oil pipeline
system in 2009 extending the system to producers operating in southern Alabama.
The new lateral consists of approximately 33 miles of 8” pipeline originating in
the Little Cedar Creek Field in Conecuh County, Alabama to a connection to our
Florida Pipeline System in Escambia County, Alabama. The project also included
gathering connections to approximately 35 wells, additional oil storage capacity
of 20,000 barrels in the field and a new delivery connection to a refinery in
Alabama.
Texas System
. The
Texas System extends from West Columbia to Webster, Webster to Texas City and
Webster to Houston. Those segments include approximately 90 miles of
pipeline. The Texas System receives all of its volume from
connections to other pipeline carriers. We earn a tariff for our
transportation services, with the tariff rate per barrel of crude oil varying
with the distance from injection point to delivery point. We entered
into a joint tariff with TEPPCO Crude Pipeline, L.P. (TEPPCO) to receive oil
from its system at West Columbia and a joint tariff with TEPPCO and ExxonMobil
Pipeline Company to receive oil from their systems at Webster. We
also continue to receive barrels from a connection with Seminole Pipeline
Company at Webster. We own tankage with approximately 55,000 barrels
of storage capacity associated with the Texas System. We lease an
additional approximately 165,000 barrels of storage capacity for our Texas
System in Webster. We have a tank rental reimbursement agreement with
the primary shipper on our Texas System to reimburse us for the lease of this
storage capacity at Webster.
CO
2
Pipelines
We also
transport CO
2
for a
fee. The Free State Pipeline is an 86-mile, 20” pipeline that extends
from CO
2
source
fields at Jackson Dome, near Jackson, Mississippi, to oil fields in east
Mississippi. In addition, the NEJD Pipeline System, a 183-mile, 20”
CO
2
pipeline extends from the Jackson Dome, near Jackson, Mississippi, to near
Donaldsonville, Louisiana and is currently being used to transport CO
2
for
tertiary recovery operations in southwest Mississippi.
Customers
Currently
greater than 90% of the volume on the Mississippi System orignates from oil
fields operated by Denbury. Denbury is the largest producer (based
upon 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 fields. Our customers on our
Mississippi, Jay and Texas Systems are primarily large, energy
companies. Denbury has exclusive use of the NEJD Pipeline and is
responsible for all operations and maintenance on that system and will bear and
assume all obligations and liabilities with respect to that
system. Currently Denbury has rights to exclusive use of our Free
State Pipeline.
Revenues
from customers of our pipeline transportation segment did not account for more
than ten percent of our consolidated revenues.
Competition
Competition
among common carrier pipelines is based primarily on posted tariffs, quality of
customer service and proximity to production, refineries and connecting
pipelines. We believe that high capital costs, tariff regulation and
the cost of acquiring rights-of-way make it unlikely that other competing
pipeline systems, comparable in size and scope to our pipelines, will be built
in the same geographic areas in the near future.
Refinery
Services
Our
refinery services segment primarily (i) provides sulfur-extraction services to
eight refining operations predominately located in Texas, Louisiana and Arkansas
and (ii) transports and sells to commercial customers two products related to
its refinery services activities – NaHS and caustic soda (or NaOH), each of
which is discussed in more detail below. Our refinery services
activities involve processing high sulfur (or “sour”) gas streams that the
refineries have generated from crude oil processing operations. Our
process applies our proprietary technology, which uses large quantities of
caustic soda (the primary raw material used in our process) to act as a
scrubbing agent under prescribed temperature and pressure to remove
sulfur. Sulfur removal in a refinery is a key factor in optimizing
production of refined products such as gasoline, diesel, and aviation
fuel. Our sulfur removal technology returns a clean (sulfur-free)
hydrocarbon stream to the refinery for further processing into refined products,
and simultaneously produces NaHS (commonly pronounced “nash”). The
resultant NaHS constitutes the sole consideration we receive for our refinery
services activities.
In
conjunction with our supply and logistics segment, we sell and deliver NaHS and
caustic soda to over 100 customers. We believe we are one of the
largest marketers of NaHS in North America and South America. By
minimizing our costs by utilizing our own logistical assets and leased storage
sites, we believe we have a competitive advantage over other suppliers of
NaHS.
NaHS is
used in the specialty chemicals business (plastic additives, dyes and personal
care products), in pulp and paper business, and in connection with mining
operations (nickel, gold and separating copper from molybdenum) as well as
bauxite refining (aluminum). NaHS has also gained acceptance in
environmental applications, including waste treatment programs requiring
stabilization and reduction of heavy and toxic metals and flue gas
scrubbing. Additionally, NaHS can be used for removing hair from
hides at the beginning of the tannery process.
Caustic
soda is used in many of the same industries as NaHS. Many
applications require both chemicals for use in the same process – for example,
caustic soda can increase the yields in bauxite refining, pulp manufacturing and
in the recovery of copper, gold and nickel. Caustic soda
is also used as a cleaning agent (when combined with water and heated) for
process equipment and storage tanks at refineries.
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”) and the residual level of sulfur
allowed in lubricants and fuels is required to be reduced by regulatory agencies
domestically and internationally. 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, providing us the capacity to meet any
increases in NaHS demand.
Customers
At
December 31, 2009, we provided onsite services utilizing NaHS units at eight
refining locations, and we managed sulfur removal by exclusive rights to market
NaHS produced at three third-party sites. While some of our customers
have elected to own the sulfur removal facilities located at their refineries,
we operate those facilities. These NaHS facilities are located
primarily in the southeastern United States.
We sell
our NaHS to customers in a variety of industries, with the largest customers
involved in copper mining and the production of paper and pulp. We
sell to customers in the copper mining industry in the western United States,
Canada and Mexico. We also export the NaHS to South America for sale
to customers for mining in Peru and Chile. No customer of the
refinery services segment is responsible for more than ten percent of our
consolidated revenues. Approximately 12% of the revenues of the
refinery services segment in 2009 resulted from sales to Kennecott Utah Copper,
a subsidiary of Rio Tinto plc. While the market price of copper and
other ores where NaHS finds application declined in 2009 creating a reduction in
mining operations and economic circumstances resulted in reduced demand for
paper and pulp products from the paper mills that purchase NaHS, provisions in
our service contracts with refiners allow us to adjust our sour gas processing
rates (sulfur removal) to maintain a balance between NaHS supply and
demand.
We sell
caustic soda to many of the same customers who purchase NaHS from us, including
paper and pulp manufacturers and copper mining. We also supply
caustic soda to some of the refineries in which we operate for use in cleaning
processing equipment.
Competition
for Refinery Services and Sales of NaHS and Caustic Soda
We
believe that the U.S. refinery industry’s demand for sulfur extraction services
will increase because we believe sour oil will constitute an increasing portion
of the total worldwide supply of crude oil and the phase in of stricter
passenger vehicle emission standards will require refiners to produce additional
quantities of low sulfur fuels. Both of these conditions can be met
by refineries installing our sulfur removal technology under refinery service
agreements. 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, our proven reliability and the regulatory
permit processes required when changing methods of handling
sulfur. NaHS technology is a reliable and cost effective manner to
control refinery operating costs regardless of the crude slate being
processed. 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 these
refineries to continue to outsource their existing refinery services functions
to us.
Our
competitors for the supply of NaHS consist primarily of parties who produce NaHS
as a by-product of processes involved with agricultural pesticide products,
plastic additives and lubricant viscosity. Typically our competitors
for the production of NaHS have only one manufacturing location and they do not
have the logistical infrastructure we have to supply customers. Our
primary competitor has been AkzoNobel, a chemical manufacturing company that
produces NaHS primarily in its pesticide operations
Our
competitors for sales of caustic soda include manufacturers of caustic
soda. These competitors supply caustic soda to our refinery services
operations and support us in our third-party NaOH sales. By utilizing
our storage capabilities and access to transportation assets, we sell caustic
soda to third parties that gain efficiencies from acquiring both NaHS and NaOH
from one source.
Supply and
Logistics
Through
our supply and logistics segment we provide a wide array of services to oil
producers and refiners in the Gulf Coast region. Our crude oil
related services include gathering crude oil from producers at the wellhead,
transporting crude oil by truck to pipeline injection points and marketing crude
oil to refiners. Not unlike our crude oil operations, we also
gather refined products from refineries, transport refined products via truck,
railcar or barge, and sell refined products to customers in wholesale
markets. Our barge transportation services are provided through DG
Marine, in which we have a 49% interest. For our supply and logistics services,
we generate fee-based income and profit from the difference between the price at
which we re-sell the crude oil and petroleum products less the price at which we
purchase the oil and products, minus the associated costs of aggregation and
transportation.
Our crude
oil supply and logistics operations are concentrated in Texas, Louisiana,
Alabama, Florida and Mississippi. These operations help to ensure
(among other things) a base supply source for our oil pipeline systems and our
refinery customers while providing our producer customers with a market outlet
for their production. By utilizing our network of trucks,
terminals and pipelines, we are able to provide transportation related services
to crude oil producers and refiners as well as enter into back-to-back gathering
and marketing arrangements with these same parties. Additionally, our crude oil
gathering and marketing expertise and knowledge base, provides us with an
ability to capitalize on opportunities which arise from time to time in our
market areas. Given our network of terminals, we have the ability to store crude
oil during periods of contango (oil prices for future deliveries are higher than
for current deliveries) for delivery in future months. When we purchase and
store crude oil during periods of contango, we limit commodity price risk by
simultaneously entering into a contract to sell the inventory in 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 generally accepted accounting
principles. See Note 17 of the Notes to the Consolidated Financial
Statements. The most substantial component of the costs we incur
while aggregating crude oil and petroleum products relates to
operating our fleet of owned and leased trucks.
Our
refined products supply and logistics operations and DG Marine’s operations are
also concentrated in the Gulf Coast region, principally Texas and
Louisiana. Through our footprint of owned and leased trucks, leased
railcars, terminals as well as our interest in DG Marine and its barges, we are
able to provide Gulf Coast area refineries with transportation services as well
as market outlets for their finished refined products. We primarily engage in
the transportation and supply of fuel oil, asphalt, diesel and gasoline to our
customers in wholesale markets as well as paper mills and
utilities. By utilizing our broad network of relationships and
logistics assets, including our terminal accessibility, we have the ability to
gather, from refineries, various grades of refined products and blend them to
meet the requirements of our other market customers. Our refinery customers may
choose to manufacture various refined products depending on a number of economic
and operating factors, and therefore we cannot predict the timing of
contribution margins related to our blending services, However, when we are able
to purchase and subsequently blend refined products, our contribution margin as
a percentage of the revenues tends to be higher than the same percentage
attributable to our recurring operations.
Within
our supply and logistics business segment, in order to meet our customer needs,
we employ many types of logistically flexible assets. These assets
include 1.6 million barrels of leased and owned terminals, accessible by truck,
rail or barge, 270 trucks and trailers, as well as barges with approximately
660,000 barrels of refined products capacity owned and operated by DG
Marine. DG Marine’s assets consist of ten pushboats and twenty double
hulled, hot-oil asphalt-capable barges with capacities ranging from 30,000 to
38,000 barrels each.
Customers
and Competition
Our
supply and logistics encompasses hundreds of producers and customers, for which
we provide transportation related services, as well as gather from and market to
crude oil and refined products. During 2009, more than ten percent of
our consolidated revenues were generated from Shell Oil Company. We
do not believe that the loss of any one customer for crude oil or petroleum
products would have a material adverse effect on us as these products are
readily marketable commodities.
In our
crude oil supply and logistics operations, we compete with other midstream
service providers and regional and local companies who may have significant
market share in the areas in which they operate. In our supply and
logistics refined products operations, we compete primarily with regional
companies. Competitive factors in our supply and logistics business include
price, relationships with our customers, range and quality of services,
knowledge of products and markets, availability of trade credit and capabilities
of risk management systems.
Industrial
Gases
Overview
Our
industrial gases segment is a natural outgrowth from our pipeline transportation
business. We (i) supply CO
2
to
industrial customers, (ii) process raw CO
2
and sell
that processed CO
2
, and (iii)
manufacture and sell syngas, a combination of carbon monoxide and
hydrogen.
CO
2
–
Industrial Customers
We supply
CO
2
to
industrial customers under seven long-term CO
2
sales
contracts. We acquired those contracts, as well as the CO
2
necessary
to satisfy substantially all of our expected obligations under those contracts,
in three separate transactions. We purchased those contracts, along
with three VPPs representing 280.0 Bcf of CO
2
(in the
aggregate), from Denbury. We sell our CO
2
to
customers who treat the CO
2
and sell
it to end users for use for beverage carbonation and food chilling and
freezing. Our compensation for supplying CO
2
to our
industrial customers is the effective difference between the price at which we
sell our CO
2
under each
contract and the price at which we acquired our CO
2
pursuant
to our VPPs, minus transportation costs. We expect some seasonality
in our sales of CO
2
. The
dominant months for beverage carbonation and freezing food are from April to
October, when warm weather increases demand for beverages and the approaching
holidays increase demand for frozen foods. At December 31, 2009, we have 127.0
Bcf of CO
2
remaining
under the VPPs.
Currently,
all of our CO
2
supply is from our interests – our VPPs – in fields producing naturally
occurring CO
2
. The
agreements we executed when we acquired the VPPs provide that we may acquire
additional CO
2
from
Denbury under terms similar to the original agreements should additional volumes
be needed to meet our obligations under the existing customer
contracts. These contracts expire between 2011 and
2023. 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 additional CO
2
supply
should we choose to remain in the CO
2
supply
business.
One of
the parties that we supply with CO
2
under a
long-term sales contract is Sandhill Group, LLC. On April 1, 2006, we
acquired a 50% interest in Sandhill Group, LLC as discussed below.
CO
2
-
Processing
We own a
50% partnership interest in Sandhill. Reliant Processing Ltd. owns
the remaining 50% of Sandhill. Sandhill is a limited liability
company that owns a CO
2
processing
facility located in Brandon, Mississippi. Sandhill is engaged in the production
and distribution of liquid carbon dioxide for use in the food, chemicals and oil
industries. The facility acquires CO
2
from us
under a long-term supply contract. This contract expires in 2023, and
provides for a maximum daily contract quantity of 16,000 Mcf per day with a
take-or-pay minimum quantity of 2,500,000 Mcf per year.
Syngas
We own a
50% partnership interest in T&P Syngas. T&P Syngas is a
partnership which owns a facility located in Texas City, Texas that manufactures
syngas and high-pressure steam. Under a long-term processing
agreement, the joint venture receives fees from its sole customer,
Praxair Hydrogen Supply, Inc. during periods when processing occurs, and Praxair
has the exclusive right to use the facility through at least 2016, which Praxair
has the option to extend for two additional five year terms. Praxair
owns the remaining 50% interest in that joint venture.
Customers
Five of
our seven contracts for supplying CO
2
are with
large international companies. One of the remaining contracts is with
Sandhill Group, LLC, of which we own 50%. The remaining contract is
with a smaller company with a history in the CO
2
business. One of our sales contracts will expire on January 31,
2011. Sales under this contract accounted for $2.3 million, or 14%,
of our industrial gases revenues in 2009. 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 30 customers, with sales to three of those customers
representing approximately 66% of Sandhill’s total revenues of approximately $10
million in 2009. In 2009, Sandhill sold approximately $1.5 million of
CO
2
to
affiliates of Reliant Processing, Ltd., our partner in Sandhill, as discussed
above. Sandhill has long-term relationships with those customers and
has not experienced collection problems with them.
Competition
Currently,
all of our CO
2
supply is from our interest – our VPPs – in fields producing naturally occurring
sources. In the future we may have to obtain our CO
2
supply
from manufactured processes. Naturally-occurring CO
2
, like that
from the Jackson Dome area, occurs infrequently, and only in limited areas east
of the Mississippi River. Our industrial CO
2
customers
have facilities that are connected to the NEJD CO
2
pipeline,
which makes delivery easy and efficient. Once our existing VPPs
expire, we will have to obtain additional CO
2
should we
choose to remain in the CO
2
supply
business, and the competition and pricing issues we will face at that time are
uncertain.
With
regard to our CO
2
supply
business, our contracts have long terms and generally include take-or-pay
provisions requiring annual minimum volumes that each customer must pay for even
if the CO
2
is not
taken.
Due to
the long-term contract and location of our syngas facility, as well as the costs
involved in establishing facilities, we believe it is unlikely that competing
facilities will be established for our syngas processing services.
Sandhill
has competition from the other industrial customers to whom we supply CO
2
. As
discussed above, the limited amounts of naturally-occurring CO
2
east of
the Mississippi River makes it difficult for competitors of Sandhill to
significantly increase their production or sales and, thereby, increase their
market share.
Geographic
Segments
All of our operations are in the United
States. Additionally, we transport and sell NaHS to customers in
South America and Canada. Revenues from customers in foreign
countries totaled approximately $9.5 million in 2009. The remainder
of our revenues in 2009 and all of our revenues in 2008 and 2007 were generated
from sales to customers in the United States.
Credit
Exposure
Due to
the nature of our operations, a disproportionate percentage of our trade
receivables constitute obligations of oil companies, independent refiners, and
mining and other industrial companies that purchase NaHS. This energy
industry concentration has the potential to impact our overall exposure to
credit risk, either positively or negatively, in that our customers could be
affected by similar changes in economic, industry or other
conditions. However, we believe that the credit risk posed by this
industry concentration is offset by the creditworthiness of our customer
base. Our portfolio of accounts receivable is comprised in large part
of 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 procedures to manage our credit
exposure, including initial credit approvals, credit limits, collateral
requirements and rights of offset. Letters of credit, prepayments and
guarantees are also utilized to limit credit risk to ensure that our established
credit criteria are met. We use similar procedures to manage our exposure to our
customers in the pipeline transportation and industrial gases
segments.
Some of
our customers experienced cash flow difficulties in 2009 as a result of the
tightening of the credit markets and the economic recession in the United
States. These customers generally purchase petroleum products and
NaHS from us. We have strengthened our credit monitoring procedures
to perform more frequent review of our customer base. As a result of
cash flow difficulties of some of our customers, we have experienced a delay in
collections from these customers and have established an allowance for possible
uncollectible receivables at December 31, 2009 in the amount of $1.4
million. During 2009, we charged approximately $0.6 million to bad
debt expense in our Consolidated Statements of Operations.
Employees
To carry
out our business activities, our general partner employed approximately 525
employees at December 31, 2009. Additionally, DG Marine employed 151
employees. None of these employees are represented by labor unions,
and we believe that relationships with these employees are good.
Organizational
Structure
Genesis
Energy, LLC, a Delaware limited liability company, serves as our sole general
partner and as the general partner of certain of our
subsidiaries. Our general partner is controlled by Quintana Capital
Group, L.P. Certain members of the Davison family and our Senior Management team
own an interest in our general partner as described below. Below are
charts depicting our ownership structure as of February 5, 2010 and December 31,
2009.
As of
February 5, 2010:
As of
December 31, 2009:
(1)
Through
February 4, 2010, the incentive compensation arrangement between our general
partner and our Senior Executive Management team (see Item 11. Executive
Compensation.), represented by the Class B Membership Interests, provided them
long-term incentive equity compensation that generally increased in value as the
incentive distribution rights held by our general partner increased in value.
The maximum amount of that interest was 20% (17.2% currently awarded) and would
fluctuate in value with increases or decreases in our distributions to our
partners and our success in generating available cash. As a result of
the change in control transaction that occurred in February 2010, certain
members of our Senior Executive Management team own Class A Membership Interests
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—cost-of-service, competitive market showings (“Market-Based
Rates”), or agreements between shippers and the oil pipeline company that the
rate is acceptable (“Settlement Rates”). The pipeline tariff rates on
our Mississippi and Jay Systems are either rates that were grandfathered and
have been changed under the index methodology, or Settlement
Rates. None of our tariffs have been subjected to a protest or
complaint by any shipper or other interested party.
Our
intrastate common carrier pipeline operations in Texas are subject to regulation
by the Railroad Commission of Texas. The applicable Texas statutes
require that pipeline rates be non-discriminatory and provide a fair return on
the aggregate value of the property of a common carrier, after providing
reasonable allowance for depreciation and other factors and for reasonable
operating expenses. Most of the volume on our Texas System is now
shipped under joint tariffs with TEPPCO and Exxon. Although no
assurance can be given that the tariffs we charge would ultimately be upheld if
challenged, we believe that the tariffs now in effect can be
sustained.
Our
natural gas gathering pipelines and CO
2
pipeline
are subject to regulation by the state agencies in the states in which they are
located.
Barge
Regulations
DG
Marine’s inland marine transportation operations are subject to regulation by
the United States Coast Guard (USCG), federal and state laws. The
Jones Act is a federal cabotage law that restricts domestic marine
transportation in the U.S. to vessels built and registered in the U.S., manned
by U.S. citizens and owned and operated by U.S. citizens. The crews
employed on the pushboats are required to be licensed by the
USCG. Federal regulations require that all tank barges engaged in the
transportation of oil and petroleum in the U.S. be double hulled by
2015. All of DG Marine’s barges are double-hulled.
Environmental
Regulations
General
We are
subject to stringent federal, state and local laws and regulations governing the
discharge of materials into the environment or otherwise relating to
environmental protection. These laws and regulations may require the
acquisition of and compliance with permits for regulated activities, limit or
prohibit operations on environmentally sensitive lands such as wetlands or
wilderness areas or areas inhabited by endangered or threatened species, result
in capital expenditures to limit or prevent emissions or discharges, and place
burdensome restrictions on our operations, including the management and disposal
of wastes. Failure to comply with these laws and regulations may
result in the assessment of administrative, civil and criminal penalties,
including the assessment of monetary penalties, the imposition of investigatory
and remedial obligations, and the issuance of orders enjoining future operations
or imposing additional compliance requirements. Changes in
environmental laws and regulations occur frequently, typically increasing in
stringency through time, and any changes that result in more stringent and
costly operating restrictions, emission control, waste handling, disposal,
cleanup, and other environmental requirements have the potential to have a
material adverse effect on our operations. While we believe that we
are in substantial compliance with current environmental laws and regulations
and that continued compliance with existing requirements would not materially
affect us, there is no assurance that this trend will continue in the
future.
Hazardous
Substances and Waste
The
Comprehensive Environmental Response, Compensation, and Liability Act, as
amended, or CERCLA, also known as the “Superfund” law, and analogous state laws
impose liability, without regard to fault or the legality of the original
conduct, on certain classes of persons. These persons include current
owners and operators of the site where a release of hazardous substances
occurred, prior owners or operators that owned or operated the site at the time
of the release of hazardous substances, and companies that disposed or arranged
for the disposal of the hazardous substances found at the site. Such
“responsible persons” may be subject to strict and joint and several liability
for the costs of cleaning up the hazardous substances that have been released
into the environment, for damages to natural resources, and for the costs of
certain health studies. CERCLA also authorizes the EPA and, in some
instances, third parties to act in response to threats to the public health or
the environment and to seek to recover the costs they incur from the responsible
classes of persons. It is not uncommon for neighboring landowners and
other third parties to file claims for personal injury and property damage
allegedly caused by hazardous substances or other pollutants released into the
environment.
We also
may incur liability under the Resource Conservation and Recovery Act, as
amended, or RCRA, and analogous state laws which impose requirements and also
liability relating to the management and disposal of solid and hazardous
wastes. While RCRA regulates both solid and hazardous wastes, it
imposes strict requirements on the generation, storage, treatment,
transportation and disposal of hazardous wastes. Certain petroleum
production wastes are excluded from RCRA’s hazardous waste
regulations. However, it is possible that these wastes, which could
include wastes currently generated during our operations, will in the future be
designated as “hazardous wastes” and, therefore, be subject to more rigorous and
costly disposal requirements. Any such changes in the laws and
regulations could have a material adverse effect on our capital expenditures and
operating expenses.
We
currently own or lease, and have in the past owned or leased, properties that
have been in use for many years with the gathering and transportation of
hydrocarbons including crude oil and other activities that could cause an
environmental impact. We also generate, handle and dispose of
regulated materials in the course of our operations, including some
characterized as “hazardous substances” under CERCLA and “hazardous wastes”
under RCRA. We may therefore be subject to liability and regulation
under CERCLA, RCRA and analogous state laws for hydrocarbons or other substances
that may have been disposed of or released on or under our current or former
properties or at other locations where wastes have been transported for
treatment or disposal. Under these laws and regulations, we could be
required to undertake investigations into suspected contamination, remove or
remediate previously disposed wastes (including wastes disposed of or released
by prior owners or operators), remediate or clean up environmental contamination
(including contaminated groundwater), restore affected properties, or undertake
measures to prevent future contamination.
Water
The
Federal Water Pollution Control Act, as amended, also known as the “Clean Water
Act”, and analogous state laws impose restrictions and strict controls regarding
the unauthorized discharge of pollutants, including oil, into navigable waters
of the United States, as well as state waters. Permits must be
obtained to discharge pollutants into these waters. The Clean Water
Act imposes substantial civil and criminal penalties for
non-compliance. In addition, the Clean Water Act and analogous state
laws require individual permits or coverage under general permits for discharges
of storm water runoff from certain types of facilities. These permits
may require us to monitor and sample the storm water runoff from certain of our
facilities. Some states also maintain groundwater protection programs
that require permits for discharges or operations that may impact groundwater
conditions. We believe we are in material compliance with these
requirements.
The Oil
Pollution Act, or OPA, is the primary federal law for oil spill
liability. The OPA addresses three principal areas of oil
pollution—prevention, containment and cleanup, and liability. The OPA
subjects owners of certain facilities to strict, joint and potentially unlimited
liability for containment and removal costs, natural resource damages and
certain other consequences of an oil spill, where such spill affects navigable
waters, along shorelines or in the exclusive economic zone of the United
States. Any unpermitted release of petroleum or other pollutants from
our operations could also result in fines and penalties. The OPA also
requires operators of offshore facilities and certain onshore facilities near or
crossing waterways to provide financial assurance generally ranging from $10
million in state waters to $35 million in federal waters to cover potential
environmental cleanup and restoration costs. This amount can be
increased to a maximum of $150 million under certain limited circumstances where
the Minerals Management Service believes such a level is justified based on the
worst case spill risks posed by the operations. We have developed an
Integrated Contingency Plan to satisfy components of OPA as well as the federal
Department of Transportation, the federal Occupational and Safety Health Act, or
OSHA, and state laws and regulations. We believe this plan meets
regulatory requirements as to notification, procedures, response actions,
response resources and spill impact considerations in the event of an oil
spill.
Air
Emissions
The
Federal Clean Air Act, as amended, and analogous state and local laws and
regulations restrict the emission of air pollutants, and impose permit
requirements and other obligations. Regulated emissions occur as a
result of our operations, including the handling or storage of crude oil and
other petroleum products. Both federal and state laws impose
substantial penalties for violation of these applicable requirements,
accordingly, our failure to comply with these requirements could subject us to
monetary penalties, injunctions, conditions or restrictions on operations and,
potentially, criminal enforcement actions.
NEPA
Under the
National Environmental Policy Act, or NEPA, a federal agency, commonly in
conjunction with a current permittee or applicant, may be required to prepare an
environmental assessment or a detailed environmental impact statement before
taking any major action, including issuing a permit for a pipeline extension or
addition that would affect the quality of the environment. Should an
environmental impact statement or environmental assessment be required for any
proposed pipeline extensions or additions, NEPA may prevent or delay
construction or alter the proposed location, design or method of
construction.
DG
Marine
DG Marine
is subject to many of the same regulations as our other operations, including
the Clean Water Act, OPA and the Clean Air Act. OPA and CERCLA
require DG Marine to obtain a Certificate of Financial Responsibility for each
barge and most of its pushboats to evidence financial ability to satisfy
statutory liabilities for oil and hazardous substance water
pollution.
Climate
Change
Recent
scientific studies have suggested that emissions of certain gases, commonly
referred to as “greenhouse gases”, including CO
2
, methane
and certain other gases may be contributing to the warming of the Earth’s
atmosphere. In June 2009, the U.S. House of Representatives passed
the American Clean Energy and Security Act of 2009, also known as the
Waxman-Markey Bill. The U.S. Senate is considering a number of
comparable measures. One such measure, the Clean Energy Jobs and
American Power Act, or the Boxer-Kerry Bill, has been reported out of the Senate
Committee on Energy and Natural Resources, but has not yet been considered by
the full Senate. Although these bills include several differences
that require reconciliation before becoming law, both contain the basic feature
of establishing a “cap and trade” system for restricting greenhouse gas
emissions in the U.S. Under such system, certain sources of
greenhouse gas emissions would be required to obtain greenhouse gas emission
“allowances” corresponding to their annual emissions of greenhouse
gases. The number of emission allowances issued each year would
decline as necessary to meet overall emission reduction goals. As the
number of greenhouse gas emission allowances declines each year, the cost or
value of allowances is expected to escalate significantly. The
ultimate outcome of this legislative initiative remains
uncertain. Any laws or regulations that may be adopted to restrict or
reduce emissions of U.S. greenhouse gases could require us to incur increased
operating costs, and could have an adverse affect on demand for the refined
products produced by our refining customers. In addition, at least 20
states have already taken legal measures to reduce emissions of greenhouse
gases, primarily through the planned development of greenhouse gas emission
inventories and/or regional greenhouse gas cap and trade programs.
On April
2, 2007, the United States Supreme Court found that the EPA has the authority to
regulate carbon dioxide, or CO2, emissions from automobiles as “air pollutants”
under the Clean Air Act (the “CAA”). Although this decision did not address CO2
emissions from electric generating plants, the EPA has similar authority under
the CAA to regulate “air pollutants” from those and other facilities. On April
17, 2009, the EPA released a “Proposed Endangerment and Cause or Contribute
Findings for Greenhouse Gases under the Clean Air Act.” The EPA’s proposed
finding concludes that the atmospheric concentrations of several key greenhouse
gases threaten the health and welfare of future generations and that the
combined emissions of these gases by motor vehicles contribute to the
atmospheric concentrations of these key greenhouse gases and hence to the threat
of climate change. Although the EPA’s proposed finding, if finalized, does not
establish emission requirements for motor vehicles, such requirements would be
expected to occur through further rulemakings. Additionally, while the EPA’s
proposed findings do not specifically address stationary sources, those
findings, if finalized, would be expected to support the establishment of future
emission requirements by the EPA for stationary sources. On September 23, 2009,
the EPA finalized a greenhouse gas reporting rule establishing a national
greenhouse gas emissions collection and reporting program. The EPA rules will
require covered entities to measure greenhouse gas emissions commencing in 2010
and submit reports commencing in 2011. On September 30, 2009, EPA proposed new
thresholds for greenhouse gas emissions that define when Clean Air Act permits
under the New Source Review, or NSR, and Title V operating permits programs
would be required. Under the Title V operating permits program, EPA is proposing
a major source emissions applicability threshold of 25,000 tons per year (tpy)
of carbon dioxide CO2e (carbon dioxide equivalency) for existing industrial
facilities. Facilities with greenhouse gas emissions below this
threshold would not be required to obtain an operating permit. Under the
Prevention of Significant Deterioration, or PSD, portion of NSR, EPA is
proposing a major stationary source threshold of 25,000 tpy CO2e. This threshold
level would be used to determine if a new facility or a major modification at an
existing facility would trigger PSD permitting requirements. EPA is also
proposing a significance level between 10,000 and 25,000 tpy CO2e. Existing
major sources making modifications that result in an increase of emissions above
the significance level would be required to obtain a PSD permit. EPA is
requesting comment on a range of values in this proposal, with the intent of
selecting a single value for the greenhouse gas significance
level. These proposals, along with new federal or state restrictions
on emissions of carbon dioxide that may be imposed in areas of the United States
in which we conduct business could also adversely affect our cost of doing
business.
Safety and Security
Regulations
Our crude
oil, natural gas and CO
2
pipelines
are subject to construction, installation, operation and safety regulation by
the Department of Transportation, or DOT, and various other federal, state and
local agencies. The Pipeline Safety Act of 1992, among other things,
amends the Hazardous Liquid Pipeline Safety Act of 1979, or HLPSA, in several
important respects. It requires the Pipeline and Hazardous Materials
Safety Administration of DOT to consider environmental impacts, as well as its
traditional public safety mandates, when developing pipeline safety
regulations. In addition, the Pipeline Safety Improvement Act of 2005
mandates the establishment by DOT of pipeline operator qualification rules
requiring minimum training requirements for operators, the development of
standards and criteria to evaluate contractors’ methods to qualify their
employees and requires that pipeline operators provide maps and other records to
the DOT. It also authorizes the DOT to require that pipelines be
modified to accommodate internal inspection devices, to mandate the evaluation
of emergency flow restricting devices for pipelines in populated or sensitive
areas, and to order other changes to the operation and maintenance of petroleum
pipelines. Significant expenses could be incurred in the future if
additional safety measures are required or if safety standards are raised and
exceed the current pipeline control system capabilities.
On March
31, 2001, the DOT promulgated Integrity Management Plan, or IMP, regulations.
The IMP regulations require that we perform baseline assessments of all
pipelines that could affect a High Consequence Area, or HCA, including certain
populated areas and environmentally sensitive areas. Due to the
proximity of all of our pipelines to water crossings and populated areas, we
have designated all of our pipelines as affecting HCAs. The integrity
of these pipelines must be assessed by internal inspection, pressure test, or
equivalent alternative new technology.
The IMP
regulation required us to prepare an Integrity Management Plan that details the
risk assessment factors, the overall risk rating for each segment of pipe, a
schedule for completing the integrity assessment, the methods to assess pipeline
integrity, and an explanation of the assessment methods selected. The
risk factors to be considered include proximity to population areas, waterways
and sensitive areas, known pipe and coating conditions, leak history, pipe
material and manufacturer, adequacy of cathodic protection, operating pressure
levels and external damage potential. The IMP regulations required
that the baseline assessment be completed by April 1, 2008, with 50% of the
mileage assessed by September 30, 2004. Reassessment is then required
every five years. As testing is complete, we are required to take
prompt remedial action to address all integrity issues raised by the
assessment. No assurance can be given that the cost of testing and
the required rehabilitation identified will not be material costs to us that may
not be fully recoverable by tariff increases.
We have
developed a Risk Management Plan as part of our IMP. This plan is
intended to minimize the offsite consequences of catastrophic
spills. As part of this program, we have developed a mapping
program. This mapping program identified HCAs and unusually sensitive
areas along the pipeline right-of-ways in addition to mapping of shorelines to
characterize the potential impact of a spill of crude oil on
waterways.
States
are responsible for enforcing the federal regulations and more stringent state
pipeline regulations and inspection with respect to hazardous liquids pipelines,
including crude oil and CO
2
pipelines,
and natural gas pipelines that do not engage in interstate
operations. In practice, states vary considerably in their authority
and capacity to address pipeline safety. We do not anticipate any
significant problems in complying with applicable state laws and regulations in
those states in which we operate.
Our crude
oil pipelines are also subject to the requirements of the federal Department of
Transportation regulations requiring qualification of all pipeline
personnel. The Operator Qualification, or OQ, program requires
operators to develop and submit a written program. The regulations
also require all pipeline operators to develop a training program for pipeline
personnel and to qualify them for covered tasks at the operator’s pipeline
facilities. The intent of the OQ regulations is to ensure a qualified
workforce by pipeline operators and contractors when performing covered tasks on
the pipeline and its facilities, thereby reducing the probability and
consequences of incidents caused by human error.
Our crude
oil, refined products and refinery services operations are also subject to the
requirements of OSHA and comparable state statutes. We believe that
our operations have been operated in substantial compliance with OSHA
requirements, including general industry standards, record keeping requirements
and monitoring of occupational exposure to regulated
substances. Various other federal and state regulations require that
we train all operations employees in HAZCOM and disclose information about the
hazardous materials used in our operations. Certain information must
be reported to employees, government agencies and local citizens upon
request.
We have
an operating authority issued by the Federal Motor Carrier Administration of the
Department of Transportation for our trucking operations, and we are subject to
certain motor carrier safety regulations issued by the DOT. The
trucking regulations cover, among other things, driver operations, maintaining
log books, truck manifest preparations, the placement of safety placards on the
trucks and trailer vehicles, drug testing, safety of operation and equipment,
and many other aspects of truck operations. We are subject to federal
EPA regulations for the development of written Spill Prevention Control and
Countermeasure, or SPCC, Plans for our trucking facilities and crude oil
injection stations. Annually, trucking employees receive training
regarding the transportation of hazardous materials and the SPCC
Plans.
The USCG
regulates occupational health standards related to DG Marine’s vessel
operations. Shore-side operations are subject to the
regulations of OSHA and comparable state statutes. The Maritime
Transportation Security Act requires, among other things, submission to and
approval of the USCG of vessel security plans.
Since the
terrorist attacks of September 11, 2001, the United States Government has issued
numerous warnings that energy assets could be the subject of future terrorist
attacks. We have instituted security measures and procedures in
conformity with DOT guidance. We will institute, as appropriate,
additional security measures or procedures indicated by the DOT or the
Transportation Safety Administration (an agency of the Department of Homeland
Security, which has assumed responsibility from the DOT). None of
these measures or procedures should be construed as a guarantee that our assets
are protected in the event of a terrorist attack.
Commodities
Regulation
When we
use futures and options contracts that are traded on the NYMEX, these contracts
are subject to strict regulation by the Commodity Futures Trading Commission and
the rules of the NYMEX.
Website
Access to Reports
We make
available free of charge on our internet website (
www.genesisenergy.com
)
our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports
on Form 8-K and amendments to those reports filed or furnished pursuant to
Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as
reasonably practicable after we electronically file the material with, or
furnish it to, the SEC. Additionally, these documents are available
at the SEC’s website (
www.sec.gov
). Information
on our website is not incorporated into this Form 10-K or our other securities
filings and is not a part of them.
It
em 1A. Risk Factors
Risks
Related to Our Business
We
may not be able to fully execute our growth strategy if we are unable to raise
debt and equity capital at an affordable price.
Our
strategy contemplates substantial growth through the development and acquisition
of a wide range of midstream and other energy infrastructure assets while
maintaining a strong balance sheet. This strategy includes constructing and
acquiring additional assets and businesses to enhance our ability to compete
effectively, diversify our asset portfolio and, thereby, provide more stable
cash flow. We regularly consider and enter into discussions regarding, and are
currently contemplating, additional potential joint ventures, stand-alone
projects and other transactions that we believe will present opportunities to
realize synergies, expand our role in the energy infrastructure business, and
increase our market position and, ultimately, increase distributions to
unitholders.
We will
need new capital to finance the future development and acquisition of assets and
businesses. Limitations on our access to capital will impair our ability to
execute this strategy. Expensive capital will limit our ability to develop or
acquire accretive assets. Although we intend to continue to expand our business,
this strategy may require substantial capital, and we may not be able to raise
the necessary funds on satisfactory terms, if at all.
The
capital and credit markets have been, and continue to be, disrupted and volatile
as a result of adverse conditions. The government response to the
disruptions in the financial markets may not adequately restore investor or
customer confidence, stabilize such markets, or increase liquidity and the
availability of credit to businesses. If the credit markets continue
to experience volatility and the availability of funds remains limited, we may
experience difficulties in accessing capital for significant growth projects or
acquisitions which could adversely affect our strategic plans.
In
addition, we experience competition for the assets we purchase or contemplate
purchasing. Increased competition for a limited pool of assets could result in
our not being the successful bidder more often or our acquiring assets at a
higher relative price than that which we have paid historically. Either
occurrence would limit our ability to fully execute our growth strategy. Our
ability to execute our growth strategy may impact the market price of our
securities.
Economic
developments in the United States and worldwide in credit markets and concerns
about economic growth could impact our operations and materially reduce our
profitability and cash flows.
Continued
uncertainty in the credit markets and concerns about local and global economic
growth have had a significant adverse impact on global financial markets and
commodity prices, both of which have contributed to a decline in our unit price
and corresponding market capitalization. If these disruptions, which
existed throughout 2009, continue, they could negatively impact our
profitability. Further tightening of the credit markets, lower levels
of liquidity in many financial markets, and extreme volatility in fixed income,
credit and equity markets could limit our access to capital. Our
credit facility arrangements involve over fifteen different lending
institutions. While none of these institutions have combined or
ceased operations, further consolidation of the credit markets could result in
lenders desiring to limit their exposure to an individual
enterprise. Additionally, some institutions may desire to limit
exposure to certain business activities in which we are engaged. Such
consolidations or limitations could impact us when we desire to extend or make
changes to our existing credit arrangements.
Additionally,
significant decreases in our operating cash flows could affect the fair value of
our long-lived assets and result in impairment charges. At December
31, 2009, we had $325 million of goodwill recorded on our Consolidated Balance
Sheet.
Fluctuations
in interest rates could adversely affect our business.
We have
exposure to movements in interest rates. The interest rates on our credit
facility are variable. Interest rates in 2009 remained low,
reducing our interest costs. Our results of operations and our cash
flow, as well as our access to future capital and our ability to fund our growth
strategy, could be adversely affected by significant increases in interest
rates.
We
may not have sufficient cash from operations to pay the current level of
quarterly distribution following the establishment of cash reserves and payment
of fees and expenses, including payments to our general partner.
The
amount of cash we distribute on our units principally depends upon margins we
generate from our refinery services, pipeline transportation, logistics and
supply and industrial gases businesses which will fluctuate from quarter to
quarter based on, among other things:
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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, barge and pipeline transportation
services;
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the
volumes of CO
2
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, 2009, we
had approximately $320 million outstanding of senior secured indebtedness of
Genesis and an additional $46.9 million of senior secured indebtedness of DG
Marine.
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
competit
ive
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, and, under our credit facility, any such event could limit our
ability to fulfill our obligations under our debt instruments and to make cash
distributions to unitholders which could adversely affect the market price of
our securities.
Our
profitability and cash flow are dependent on our ability to increase or, at a
minimum, maintain our current commodity - oil, refined products, NaHS, caustic
soda and CO
2
- volumes, which often depends on actions and commitments by parties
beyond our control.
Our
profitability and cash flow are dependent on our ability to increase or, at a
minimum, maintain our current commodity— oil, refined products, NaHS, caustic
soda and CO
2
— volumes.
We access commodity volumes through two sources, producers and service providers
(including gatherers, shippers, marketers and other aggregators). Depending on
the needs of each customer and the market in which it operates, we can either
provide a service for a fee (as in the case of our pipeline transportation
operations) or we can purchase the commodity from our customer and resell it to
another party.
Our
source of volumes depends on successful exploration and development of
additional oil reserves by others; continued demand for our refinery services,
for which we are paid in NaHS; the breadth and depth of our logistics
operations; the extent that third parties provide NaHS for resale; and other
matters beyond our control.
The oil,
refined products, and CO
2
available
to us are derived from reserves produced from existing wells, and these reserves
naturally decline over time. In order to offset this natural decline, our energy
infrastructure assets must access additional reserves. Additionally, some of the
projects we have planned or recently completed are dependent on reserves that we
expect to be produced from newly discovered properties that producers are
currently developing.
Finding
and developing new reserves is very expensive, requiring large capital
expenditures by producers for exploration and development drilling, installing
production facilities and constructing pipeline extensions to reach new wells.
Many economic and business factors out of our control can adversely affect the
decision by any producer to explore for and develop new reserves. These factors
include the prevailing market price of the commodity, the capital budgets of
producers, the depletion rate of existing reservoirs, the success of new wells
drilled, environmental concerns, regulatory initiatives, cost and availability
of equipment, capital budget limitations or the lack of available capital, and
other matters beyond our control. Additional reserves, if discovered, may not be
developed in the near future or at all. Thus, oil production in our market area
may not rise to sufficient levels to allow us to maintain or increase the
commodity volumes we are experiencing.
Our
ability to access NaHS depends primarily on the demand for our proprietary
refinery services process. Demand for our services could be adversely
affected by many factors, including lower refinery utilization
rates, U.S. refineries accessing more “sweet” (instead of sour)
crude, and the development of alternative sulfur removal processes that might be
more economically beneficial to refiners.
We are
dependent on third parties for NaOH for use in our refinery services process as
well as volume to market to third parties. Should regulatory
requirements or operational difficulties disrupt the manufacture of caustic soda
by these producers, we could be affected.
A
substantial portion of our CO
2
operations
involves us supplying CO
2
to industrial customers using reserves attributable to our volumetric production
payment interests, which are a finite resource and projected to terminate around
2015.
The cash
flow from our CO
2
operations
involves us supplying CO
2
to
industrial customers using reserves attributable to our volumetric production
payments. Unless we are able to obtain a replacement supply of CO
2
and enter
into sales arrangements that generate substantially similar economics, our cash
flow could decline significantly around 2015 as some of our CO
2
industrial
sales contracts expire.
Fluctuations
in demand for CO
2
by our
customers could have a material adverse impact on our profitability, results of
operations and cash available for distribution.
Our
customers are not obligated to purchase volumes in excess of specified minimum
amounts in our contracts. As a result, fluctuations in our customers’ demand due
to market forces or operational problems could result in a reduction in our
revenues from our sales of CO
2
.
Our
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. As a large consumer of caustic soda,
economies of scale and logistics capabilities allow us to effectively market
caustic soda to third parties. 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.
Additionally,
if we misjudge demand for caustic soda, or the demand for NaHS, (as caustic soda
is a key component in the provision of services for which we receive the
by-product NaHS), we could own excess NaHS and NaOH for which there is no
market, or that we are forced to sell at a loss. For example,
in 2009, macroeconomic conditions negatively impacted the demand for NaHS,
primarily in mining and industrial activities. If demand for NaHS
remains low or declines further, our refinery services revenue will be
negatively affected.
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
face intense competition to obtain oil and refined products commodity
volumes.
Our
competitors—gatherers, transporters, marketers, brokers and other
aggregators—include independents and major integrated energy companies, as well
as their marketing affiliates, who vary widely in size, financial resources and
experience. Some of these competitors have capital resources many times greater
than ours and control substantially greater supplies of crude oil and other
refined products..
Even if
reserves exist or refined products are produced in the areas accessed by our
facilities, we may not be chosen by the producers or refiners to gather, refine,
market, transport, store or otherwise handle any of these reserves, CO
2
, NaHS,
caustic soda or other refined products. We compete with others for any such
volumes on the basis of many factors, including:
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geographic
proximity to the production;
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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 transported by our pipelines. As a result, we may
experience declines in our margin and profitability if our volumes
decrease.
Fluctuations
in commodity prices could adversely affect our business.
Oil,
natural gas, other petroleum products, NaHS, caustic soda and CO
2
prices are
volatile and could have an adverse effect on our profits and cash flow. Prices
for commodities can fluctuate in response to changes in supply, market
uncertainty and a variety of additional factors that are beyond our control. Our
operations can be affected by price reductions in those commodities depending on
the extent to which we can pass on those costs to our customers. 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.
We
are exposed to the credit risk of our customers in the ordinary course of our
business activities.
When we
market any of our products or services, we must determine the amount, if any, of
the line of credit we will extend to any given customer. Since typical sales
transactions can involve very large volumes, the risk of nonpayment and
nonperformance by customers is an important consideration in our
business.
In those
cases where we provide division order services for crude oil purchased at the
wellhead, we may be responsible for distribution of proceeds to all of the
interest owners. In other cases, we pay all of or a portion of the production
proceeds to an operator who distributes these proceeds to the various interest
owners. These arrangements expose us to operator credit risk. As a result, we
must determine that operators have sufficient financial resources to make such
payments and distributions and to indemnify and defend us in case of a protest,
action or complaint.
We sell
petroleum products to many wholesalers and end-users that are not large
companies and are privately-owned operations. While those sales are
not large volume sales, they tend to be frequent transactions such that a large
balance can develop quickly. Additionally, we sell NaHS and caustic
soda to customers in a variety of industries. Many of these customers
are in industries that have been impacted by a decline in demand for their
products and services. Even if our credit review and analytical
procedures work properly, we have, and we could continue to experience losses in
dealings with other parties.
Additionally,
many of our customers are impacted by the weakening economic outlook and
declining commodity prices in a manner that could influence the need for our
products and services.
Our
wholesale CO
2
industrial
operations are dependent on five customers and our syngas operations are
dependent on one customer.
If one or
more of those customers experience financial difficulties or any deterioration
in its ability to satisfy its obligations, (including failing to purchase their
required minimum take-or-pay volumes), our cash flows could be adversely
affected.
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 one or 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 or any deterioration in its ability to satisfy its obligations to
us (including failing to provide volumes to process), our cash flow from the
syngas joint venture could be adversely affected.
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 2009, 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 sour gas to us (except during periods of force
majeure). Although the primary term of that contract extends until
2018, if, for any reason, Conoco does not meet its obligations under that
contract for an extended period of time, such non-performance could have a
material adverse effect on our profitability and cash flow.
Our
CO
2
operations are exposed to risks related to Denbury’s operation of its CO
2
fields,
equipment and pipeline as well as any of our facilities that Denbury
operates.
Because
Denbury produces the CO
2
and
transports the CO
2
to our
customers (including Denbury), any major failure of its operations could have an
impact on our ability to meet our obligations to our CO
2
customers.
We have no other supply of CO
2
or method
to transport it to our customers. Sandhill relies on us for its
supply of CO
2
therefore
our share of the earnings of Sandhill would also be impacted by any major
failure of Denbury’s CO
2
-related
operations.
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 consequences of varying degrees for noncompliance, and
require us to expend resources in an effort to maintain compliance. Moreover,
our operations, including the transportation and storage of crude oil and other
commodities, involves a risk that crude oil and related hydrocarbons or other
substances may be released into the environment, which may result in substantial
expenditures for a response action, significant government penalties, liability
to government agencies for natural resources damages, liability to private
parties for personal injury or property damages, and significant business
interruption. These costs and liabilities could rise under increasingly strict
environmental and safety laws, including regulations and enforcement policies,
or claims for damages to property or persons resulting from our operations. If
we are unable to recover such resulting costs through increased rates or
insurance reimbursements, our cash flows and distributions to our unitholders
could be materially affected.
FERC
Regulation and a changing regulatory environment could affect our cash
flow.
The FERC
regulates certain of our energy infrastructure assets engaged in interstate
operations. Our intrastate pipeline operations are regulated by state
agencies. This regulation extends to such matters as:
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rate
structures;
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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 evolving nature of federal and state regulation
and the possibility for additional changes, the current regulatory regime may
change and affect our financial position, results of operations or cash
flows.
Our
growth strategy may adversely affect our results of operations if we do not
successfully integrate the businesses that we acquire or if we substantially
increase our indebtedness and contingent liabilities to make
acquisitions.
We may be
unable to integrate successfully businesses we acquire. We may incur substantial
expenses, delays or other problems in connection with our growth strategy that
could negatively impact our results of operations. Moreover, acquisitions and
business expansions involve numerous risks, including:
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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.
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. To the extent we hedge our commodity price exposure, we forego the
benefits we would otherwise experience if commodity prices were to increase. In
addition, we could experience losses resulting from our hedging and other
derivative positions. Such losses could occur under various circumstances,
including if our counterparty does not perform its obligations under the hedge
arrangement, our hedge is imperfect, or our hedging policies and procedures are
not followed.
A
natural disaster, accident, terrorist attack or other interruption event
involving us could result in severe personal injury, property damage and/or
environmental damage, which could curtail our operations and otherwise adversely
affect our assets and cash flow.
Some of
our operations involve significant risks of severe personal injury, property
damage and environmental damage, any of which could curtail our operations and
otherwise expose us to liability and adversely affect our cash flow. Virtually
all of our operations are exposed to the elements, including hurricanes,
tornadoes, storms, floods and earthquakes.
If one or
more facilities that are owned by us or that connect to us is damaged or
otherwise affected by severe weather or any other disaster, accident,
catastrophe or event, our operations could be significantly interrupted. Similar
interruptions could result from damage to production or other facilities that
supply our facilities or other stoppages arising from factors beyond our
control. These interruptions might involve significant damage to people,
property or the environment, and repairs might take from a week or less for a
minor incident to six months or more for a major interruption. Any event that
interrupts the fees generated by our energy infrastructure assets, or which
causes us to make significant expenditures not covered by insurance, could
reduce our cash available for paying our interest obligations as well as
unitholder distributions and, accordingly, adversely impact the market price of
our securities. Additionally, the proceeds of any property insurance maintained
by us may not be paid in a timely manner or be in an amount sufficient to meet
our needs if such an event were to occur, and we may not be able to renew it or
obtain other desirable insurance on commercially reasonable terms, if at
all.
On
September 11, 2001, the United States was the target of terrorist attacks of
unprecedented scale. Since the September 11 attacks, the U.S. government has
issued warnings that energy assets, specifically the nation’s pipeline
infrastructure, may be the future targets of terrorist organizations. These
developments have subjected our operations to increased risks. Any future
terrorist attack at our facilities, those of our customers and, in some cases,
those of other pipelines, could have a material adverse effect on our
business.
We
cannot cause our joint ventures to take or not to take certain actions unless
some or all of the joint venture participants agree.
Due to
the nature of joint ventures, each participant (including us) in our joint
ventures has made substantial investments (including contributions and other
commitments) in that joint venture and, accordingly, has required that the
relevant charter documents contain certain features designed to provide each
participant with the opportunity to participate in the management of the joint
venture and to protect its investment in that joint venture, as well as any
other assets which may be substantially dependent on or otherwise affected by
the activities of that joint venture. These participation and protective
features include a corporate governance structure that consists of a management
committee composed of four members, only two of which are appointed by us, or in
the case of DG Marine, only one of which is appointed by us. In
addition, the other 50% owners in our T&P Syngas and Sandhill joint ventures
operate those joint venture facilities and the other 51% owner of our DG Marine
joint venture controls key operational decisions of the joint venture. Thus,
without the concurrence of the other joint venture participant, we cannot cause
our joint ventures to take or not to take certain actions, even though those
actions may be in the best interest of the joint ventures or us.
Our
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.
Our
investment in DG Marine exposes us to certain risks that are inherent to the
barge transportation industry as well certain risks applicable to our other
operations.
DG
Marine’s inland barge transportation business has exposure to certain risks
which are significant to our other operations and certain risks inherent to the
barge transportation industry. For example, unlike our other
operations, DG Marine operates barges that transport products to and from
numerous marine locations, which exposes us to new risks,
including:
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being
subject to the Jones Act and other federal laws that restrict U.S.
maritime transportation to vessels built and registered in the U.S. and
owned and manned by U.S. citizens, with any failure to comply with such
laws potentially resulting in severe penalties, including permanent loss
of U.S. coastwise trading rights, fines or forfeiture of
vessels;
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relying
on a limited number of customers;
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having
primarily short-term charters which DG Marine may be unable to renew as
they expire; and
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competing
against businesses with greater financial resources and larger operating
crews than DG Marine.
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In
addition, like our other operations, DG Marine’s refined products transportation
business is an integral part of the energy industry infrastructure, which
increases our exposure to declines in demand for refined petroleum products or
decreases in U.S. refining activity.
Risks
Related to Our Partnership Structure
Our
general partner and its affiliates have conflicts of interest with us and
limited fiduciary responsibilities, which may permit them to favor their own
interests to our unitholders’ detriment.
While
Quintana has publicly announced that it intends to use as one of its primary
vehicles for investing in the midstream segment of the energy sector, neither
our general partner nor any of its affiliates is obligated to enter into any
additional transactions with (or to offer any opportunities to) us or to promote
our interest, and neither our general partner or any of its affiliates 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, our general partner and
each of its affiliates may, at any time, and without notice, alter its business
strategy. Additionally, if our general partner or any of its affiliates were to
make one or more offers to us, we cannot say that we would elect to pursue or
consummate any such opportunity.
If
conflicts of interest arise between our general partner and its affiliates, on
the one hand, and us and our unitholders, on the other hand, 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 the owner of
our general partner to pursue a business strategy that favors us or
utilizes our assets. For example, our directors and officers
who are also directors and/or officers of other entities (such as
Quintana) have a fiduciary duty to make decisions based on the best
interests of the equity holders of such other
entities.
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affiliates
of our general partner may compete with us. For example,
affiliates of Quintana own other midstream
interests.
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our
general partner is allowed to take into account the interest of parties
other than us, such as one or more of its affiliates, in resolving
conflicts of interest;
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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 such 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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Affiliates
of our general partner are not obligated to enter into any transactions with (or
to offer any opportunities to) us. Further, 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, those entities could make 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,
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 direction of management.
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(s) 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. We obtained an
amendment to the change in control provision in connection with the transfer of
our general partner to Quintana by Denbury.
Our
significant unitholders may sell units or other limited partner interests in the
trading market, which could reduce the market price of common
units.
As of
December 31, 2009, affiliates of Denbury owned 4,028,096 (approximately 10.2%)
of our common units and members of the Davison family owned 11,785,979
(approximately 30%) of our common units. We also have other unitholders that may
have large positions in our common units. In the future, any such
parties may acquire additional interest or dispose of some or all of their
interest. If they dispose of a substantial portion of their interest in the
trading markets, 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, members of the Davison family, Denbury and others to cause us
to register for sale the partnership interests held by such persons, including
common units. Those registration rights allow those unitholders to request
registration of those partnership interests and to include any of those
securities in a registration of other capital securities by
us. Additionally, we have filed shelf registration statements for the
units held by some holders of large blocks of our units, and those holders may
sell their common units at any time, subject to certain restrictions under
securities laws.
Unitholders
with registration rights have rights to require underwritten offerings that
could limit our ability to raise capital in the public equity
market.
Unitholders
with registration rights have rights to require us to conduct underwritten
offerings of our common units. If we want to access the capital
markets, those unitholders’ ability to sell a portion of their common units
could satisfy investor’s demand for our common units or may reduce the market
price for our common units, thereby reducing the net proceeds we would receive
from a sale of newly issued units.
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
those equity securities on the same terms as they are issued to the other
purchasers. 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 Quintana and Denbury, adverse developments
concerning either of them could adversely affect us, even if we have not
suffered any similar developments.
Prior to
February 5, 2010, Denbury controlled our general partner. We continue
to have some important relationships with Denbury. It is the operator
of our largest CO
2
pipeline
and the operator of the fields that produce our CO
2
reserves. We are also parties to agreements with Denbury,
including the lease of the NEJD CO
2
pipeline
and the transportation arrangements related to the Free State
pipeline. Denbury is also a significant customer of our Mississippi
System. On February 5, 2010, affiliates and co-investors of Quintana Capital
Group II, L.P., along with members of the Davison family and members of our
Senior Executive Management team acquired control of our general
partner. We could be adversely affected if Denbury experiences any
adverse developments or fails to pay us for our services on a timely basis or
fails to meet its obligations to us. Additionally, if Quintana
experiences any adverse developments (i) it could alter its business strategy,
including determining that it no longer desires to use us as an investment
vehicle, and (ii) the “market” could become concerned about our stability, each
of which could negatively affect us.
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 may decrease in direct correlation with decreases in the
amount we distribute per unit. Accordingly, if we experience a liquidity problem
in the future, we may not be able to issue more equity to
recapitalize.
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, 2009, our balance sheet reflected $325 million of goodwill and $136
million of intangible assets. Goodwill is recorded when the purchase price of a
business exceeds the fair market value of the tangible and separately measurable
intangible net assets. Generally accepted accounting principles in the United
States (“GAAP”) require us to test goodwill for impairment on an annual basis or
when events or circumstances occur indicating that goodwill might be impaired.
Long-lived assets such as intangible assets with finite useful lives are
reviewed for impairment whenever events or changes in circumstances indicate
that the carrying amount may not be recoverable. Financial and credit markets
volatility directly impacts our fair value measurements for tests of impairment
through our weighted average cost of capital that we use to determine our
discount rate. If we determine that any of our goodwill or intangible
assets were impaired, we would be required to record the
impairment. Our assets, equity and earnings as recorded in our
financial statements would be reduced, and it could adversely affect certain of
our borrowing metrics. While such a write-off would not reduce our
primary borrowing base metric of EBITDA, it would reduce our consolidated
capitalization ratio, which, if significant enough, could result in an event of
default under our credit agreement. At December 31, 2009, such a
write-off would need to exceed $329.2 million in order to result in an event of
default.
Tax
Risks to Common Unitholders
Our
tax treatment depends on our status as a partnership for federal income tax
purposes, as well as our not being subject to a material amount of entity-level
taxation by individual states. A publicly-traded partnership can lose
its status as a partnership for a number of reasons, including not having enough
“qualifying income.” If the Internal Revenue Service, or
IRS, were to treat us as a corporation or if we were to become
subject to a material amount of entity-level taxation for state tax purposes,
then our cash available for distribution to unitholders would be substantially
reduced.
The
anticipated after-tax economic benefit of an investment in our common units
depends largely on our being treated as a partnership for federal income tax
purposes. Section 7704 of the Internal Revenue Code provides that
publicly traded partnerships will, as a general rule, be taxed as
corporations. However, an exception, referred to in this discussion
as the “Qualifying Income Exception,” exists with respect to publicly traded
partnerships 90% or more of the gross income of which for every taxable year
consists of “qualifying income.” If less than 90% of our gross income
for any taxable year is “qualifying income” from transportation or processing of
natural resources including crude oil, natural gas or products thereof,
interest, dividends or similar sources, we will be taxable as a corporation
under Section 7704 of the Internal Revenue Code for federal income tax purposes
for that taxable year and all subsequent years. We have not
requested, and do not plan to request, a ruling from the IRS with respect to our
treatment as a partnership for federal income tax purposes.
Although
we do not believe based upon our current operations that we are treated as a
corporation for federal income tax purposes, a change in our business (or a
change in current law) could cause us to be treated as a corporation for federal
income tax purposes or otherwise subject us to taxation as an
entity. If we were treated as a corporation for federal income tax
purposes, we would pay federal income tax on our taxable income at the corporate
tax rate, which is currently a maximum of 35% and would pay state income tax at
varying rates. Distributions to our unitholders would generally be
taxable to them again as corporate distributions and no income, gains, losses,
or deductions would flow through to them. Because a tax would be
imposed upon us as a corporation, our cash available for distribution to
unitholders would be substantially reduced. Therefore, treatment of
us as a corporation would result in a material reduction in the anticipated cash
flow and after-tax return to our unitholders, likely causing a substantial
reduction in the value of our common units.
Current
law may change so as to cause us to be treated as a corporation for federal
income tax purposes or otherwise subject us to entity-level
taxation. Moreover, any modification to the federal income tax laws
and interpretations thereof may or may not be applied
retroactively. Any such changes could negatively impact the value of
an investment in our common units. At the state level, because of
widespread state budget deficits and other reasons, several states are
evaluating ways to subject partnerships to entity-level taxation through the
imposition of state income, franchise and other forms of
taxation. For example, we are required to pay Texas franchise tax on
our gross income apportioned to Texas. Imposition of any such taxes
on us by any other state would reduce the cash available for distribution to our
unitholders.
A
successful IRS contest of the federal income tax positions we take may adversely
affect the market for our common units, and the cost of any IRS contest will
reduce our cash available for distribution to our unitholders and our general
partner.
We have
not requested, and do not plan to request, a ruling from the IRS with respect to
our treatment as a partnership for federal income tax purposes or any other
matter affecting us. The IRS may adopt positions that differ from the
positions we take. It may be necessary to resort to administrative or
court proceedings to sustain some or all of the positions we take. A
court may not agree with some or all of the positions we take. Any
contest with the IRS may materially and adversely impact the market for our
common units and the price at which they trade. In addition, our
costs of any contest with the IRS will be borne indirectly by our unitholders
and our general partner because these costs will reduce our cash available for
distribution.
Unitholders
maybe required to pay taxes on their share of income from us even if they do not
receive any cash distributions from us.
Because
our unitholders are treated as partners to whom we allocate taxable income which
could be different in amount than the cash we distribute, our unitholders may be
required to pay federal income taxes and, in some cases, state and local income
taxes on their share of our taxable income even if they receive no cash
distributions from us. Unitholders may not receive cash distributions
from us equal to their share of our taxable income or equal to the actual tax
liability that results from that income.
Tax
gain or loss on the disposition of our common units could be more or less than
expected.
If
unitholders sell their common units, they will recognize a gain or loss equal to
the difference between the amount realized and their tax basis in those common
units. Prior distributions to unitholders in excess of the total net
taxable income unitholders were allocated for a common unit, which decreased
their tax basis in that common unit, will, in effect, become taxable income to
unitholders if the common unit is sold at a price greater than their tax basis
in that common unit, even if the price they receive is less than their original
cost. A substantial portion of the amount realized, whether or not
representing gain, may be ordinary income due to potential recapture items,
including depreciation recapture. In addition, because the amount
realized includes a unitholder’s share of our non-recourse liabilities, if
unitholders sell their units, they may incur a tax liability in excess of the
amount of cash they receive from the sale.
Tax-exempt
entities and non-U.S. persons face unique tax issues from owning our common
units that may result in adverse tax consequences to them.
Investment
in common units by tax-exempt entities, such as individual retirement accounts
(known as IRAs), other retirement plans, and non-U.S. persons raises issues
unique to them. For example, virtually all of our income allocated to
organizations that are exempt from federal income tax, including IRAs and other
retirement plans, will be unrelated business taxable income and will be taxable
to them. Distributions to non-U.S. persons will be reduced by
withholding taxes at the highest applicable effective tax rate and non-U.S.
persons will be required to file U.S. federal income tax returns and pay tax on
their share of our taxable income. Tax-exempt entities and non-U.S.
persons should consult their tax advisors before investing in our common
units.
We
will treat each purchaser of our common units as having the same tax benefits
without regard to the actual common units purchased. The IRS may
challenge this treatment, which could adversely affect the value of our common
units.
Because
we cannot match transferors and transferees of our common units, we adopt
depreciation and amortization conventions that may not conform to all aspects of
existing Treasury Regulations and may result in audit adjustments to our
unitholders’ tax returns without the benefit of additional
deductions. A successful IRS challenge to those conventions could
adversely affect the amount of tax benefits available to a common
unitholder. It also could affect the timing of these tax benefits or
the amount of gain from a sale of common units and could have a negative impact
on the value of our common units or result in audit adjustments to the common
unitholder’s tax returns.
Unitholders
will likely be subject to state and local taxes in states where they do not live
as a result of an investment in the common units.
In
addition to federal income taxes, unitholders will likely be subject to other
taxes, including foreign, state and local taxes, unincorporated business taxes
and estate inheritance or intangible taxes that are imposed by the various
jurisdictions in which we do business or own property, even if unitholders do
not live in any of those jurisdictions. Unitholders will likely be
required to file foreign, state, and local income tax returns and pay state and
local income taxes in some or all of these jurisdictions. Further,
unitholders may be subject to penalties for failure to comply with those
requirements. We own assets and do business in more than 20 states
including Texas, Louisiana, Mississippi, Alabama, Florida, Arkansas, and
Oklahoma. Many of the states we currently do business in
impose a personal income
tax. It is our unitholders’ responsibility to file all applicable
United States federal, foreign, state, and local tax returns.
We
have subsidiaries that are treated as corporations for federal income tax
purposes and subject to corporate-level income taxes.
We
conduct a portion of our operations through subsidiaries that are, or are
treated as, corporations for federal income tax purposes. We may
elect to conduct additional operations in corporate form in the
future. These corporate subsidiaries will be subject to
corporate-level tax, which will reduce the cash available for distribution to us
and, in turn, to our unitholders. If the IRS were to successfully
assert that these corporate subsidiaries have more tax liability than we
anticipate or legislation was enacted that increased the corporate tax rate, our
cash available for distribution to our unitholders would be further
reduced.
We
prorate our items of income, gain, loss and deduction between transferors and
transferees of our common units each month based upon the ownership of our
common units on the first day of each month, instead of on the basis of the date
a particular common unit is transferred.
We
prorate our items of income, gain, loss, and deduction between transferors and
transferees of our common units each month based upon the ownership of our
common units on the first day of each month, instead of on the basis of the date
a particular unit is transferred. The use of this proration method
may not be permitted under existing Treasury Regulations. If the IRS
were to successfully challenge this method or new Treasury Regulations were
issued, we may be required to change the allocation of items of income, gain,
loss, and deduction among our unitholders.
A
unitholder whose units are loaned to a “short seller” to cover a short sale of
units may be considered as having disposed of those units. If so,
such unitholder would no longer be treated for tax purposes as a partner with
respect to those units during the period of the loan and may recognize gain or
loss from the disposition.
Because a
unitholder whose units are loaned to a “short seller” to cover a short sale of
units may be considered as having disposed of the loaned units, such unitholder
may no longer be treated for tax purposes as a partner with respect to those
units during the period of the loan to the short seller and the unitholder may
recognize gain or loss from such disposition. Moreover, during the
period of the loan to the short seller, any of our income, gain, loss or
deduction with respect to those units may not be reportable by the unitholder
and any cash distributions received by the unitholder as to those units could be
fully taxable as ordinary income. Unitholders desiring to assure
their status as partners and avoid the risk of gain recognition from a loan to a
short seller are urged to modify any applicable brokerage account agreements to
prohibit their brokers from borrowing their units.
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 our 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, under our valuation methods, 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
valuation 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 our 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 our partnership for federal income tax purposes
if there is a sale or exchange of 50% or more of the total interests in our
capital and profits within a twelve-month period. Our termination
would, among other things, result in the closing of our taxable year for all
unitholders, which would result in us filing two tax returns (and unitholders
receiving two Schedule K-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.
It
em 1B. Unresolved Staff Comments
None.
It
em 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 20 of the
Notes to the Consolidated Financial Statements for the future minimum rental
payments. Such information is incorporated herein by
reference.
It
em 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 20 of the Notes to the Consolidated Financial
Statements.)
It
em 4. Submission of Matters to a Vote of Security
Holders
No
matters were submitted to a vote of the security holders during the fiscal year
covered by this report.
It
em 5. Market for Registrant’s Common Equity, Related
Stockholder Matters and Issuer Purchases of Equity Securities
Our
common units are listed on the NYSE Amex LLC (formerly 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)
|
||||||||||
|
2010
|
||||||||||||
|
First
Quarter (through February 19, 2010)
|
$ | 21.00 | $ | 17.94 | $ | 0.3600 | ||||||
|
2009
|
||||||||||||
|
Fourth
Quarter
|
$ | 19.95 | $ | 15.10 | $ | 0.3525 | ||||||
|
Third
Quarter
|
$ | 16.89 | $ | 12.01 | $ | 0.3450 | ||||||
|
Second
Quarter
|
$ | 13.92 | $ | 9.82 | $ | 0.3375 | ||||||
|
First
Quarter
|
$ | 12.60 | $ | 7.57 | $ | 0.3300 | ||||||
|
2008
|
||||||||||||
|
Fourth
Quarter
|
$ | 16.00 | $ | 6.42 | $ | 0.3225 | ||||||
|
Third
Quarter
|
$ | 19.85 | $ | 11.75 | $ | 0.3150 | ||||||
|
Second
Quarter
|
$ | 22.09 | $ | 17.02 | $ | 0.3000 | ||||||
|
First
Quarter
|
$ | 25.00 | $ | 15.07 | $ | 0.2850 | ||||||
At
February 19, 2010, we had 39,585,692 common units outstanding, including
4,028,096 common units held directly or indirectly by Denbury and 11,793,678
common units held by the Davison family. As of December 31, 2009, we
had approximately 20,100 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 are incorporated by reference 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 11 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, 2009.
|
Number
of securities to be issued upon exercise of outstanding options, warrants
and rights
|
Weighted-average
exercise price of outstanding options, warrants and rights
|
Number
of securities remaining available for future issuance under equity
compensation plans (excluding securities reflected in column
(a))
|
|
|
Plan
Category
|
(a)
|
(b)
|
(c)
|
|
Equity
Compensation plans approved by security holders:
|
|||
|
2007
Long-term Incentive Plan (2007 LTIP)
|
123,857
|
(1)
|
832,928
|
(1) Awards
issued under our 2007 LTIP are phantom units for which the grantee will receive
one common unit for each phantom unit upon vesting. There is no
exercise price. Due to the change in control of our general partner,
the outstanding phantom units under our 2007 Long-term Incentive Plan vested on
February 5, 2010. For additional discussion of our 2007 LTIP, see
Note 16 of the Notes to the Consolidated Financial Statements.
Recent
Sales of Unregistered Securities
None.
It
em 6. Selected Financial Data
The table
below includes selected financial and other data for the Partnership for the
years ended December 31, 2009, 2008, 2007, 2006, and 2005
(in thousands, except per unit and
volume data)
.
|
Year
Ended December 31,
|
||||||||||||||||||||
|
2009
|
2008
(1)
|
2007
(1)
|
2006
|
2005
|
||||||||||||||||
|
Income
Statement Data:
|
||||||||||||||||||||
|
Revenues:
|
||||||||||||||||||||
|
Supply
and logistics
(2)
|
$ | 1,226,838 | $ | 1,852,414 | $ | 1,094,189 | $ | 873,268 | $ | 1,038,549 | ||||||||||
|
Refinery
services
|
141,365 | 225,374 | 62,095 | - | - | |||||||||||||||
|
Pipeline
transportation, including natural gas sales
|
50,951 | 46,247 | 27,211 | 29,947 | 28,888 | |||||||||||||||
|
CO
2
marketing
|
16,206 | 17,649 | 16,158 | 15,154 | 11,302 | |||||||||||||||
|
Total
revenues
|
1,435,360 | 2,141,684 | 1,199,653 | 918,369 | 1,078,739 | |||||||||||||||
|
Costs
and expenses:
|
||||||||||||||||||||
|
Supply
and logistics costs
(2)
|
1,198,071 | 1,815,090 | 1,078,859 | 865,902 | 1,034,888 | |||||||||||||||
|
Refinery
services operating costs
|
88,910 | 166,096 | 40,197 | - | - | |||||||||||||||
|
Pipeline
transportation, including natural gas purchases
|
13,024 | 15,224 | 14,176 | 17,521 | 19,084 | |||||||||||||||
|
CO
2
marketing transportation costs
|
5,825 | 6,484 | 5,365 | 4,842 | 3,649 | |||||||||||||||
|
General
and administrative expenses
|
40,413 | 29,500 | 25,920 | 13,573 | 9,656 | |||||||||||||||
|
Depreciation
and amortization
|
62,581 | 71,370 | 38,747 | 7,963 | 6,721 | |||||||||||||||
|
Loss
(gain) from sales of surplus assets
|
160 | 29 | 266 | (16 | ) | (479 | ) | |||||||||||||
|
Impairment
Expense
(3)
|
5,005 | - | 1,498 | - | - | |||||||||||||||
|
Total
costs and expenses
|
1,413,989 | 2,103,793 | 1,205,028 | 909,785 | 1,073,519 | |||||||||||||||
|
Operating
income (loss) from continuing operations
|
21,371 | 37,891 | (5,375 | ) | 8,584 | 5,220 | ||||||||||||||
|
Earnings
from equity in joint ventures
|
1,547 | 509 | 1,270 | 1,131 | 501 | |||||||||||||||
|
Interest
expense, net
|
(13,660 | ) | (12,937 | ) | (10,100 | ) | (1,374 | ) | (2,032 | ) | ||||||||||
|
Income
(loss) from continuing operations before cumulative effect of change in
accounting principle and income taxes
|
9,258 | 25,463 | (14,205 | ) | 8,341 | 3,689 | ||||||||||||||
|
Income
tax (expense) benefit
|
(3,080 | ) | 362 | 654 | 11 | - | ||||||||||||||
|
Income
(loss) from continuing operations before cumulative effect of change in
accounting principle
|
6,178 | 25,825 | (13,551 | ) | 8,352 | 3,689 | ||||||||||||||
|
Income
from discontinued operations
|
- | - | - | - | 312 | |||||||||||||||
|
Cumulative
effect of changes in accounting principle
|
- | - | - | 30 | (586 | ) | ||||||||||||||
|
Net
income (loss)
|
6,178 | 25,825 | (13,551 | ) | 8,382 | 3,415 | ||||||||||||||
|
Net
loss (income) attributable to noncontrolling interests
|
1,885 | 264 | 1 | (1 | ) | - | ||||||||||||||
|
Net
income (loss) attributable to Genesis Energy, L.P.
|
$ | 8,063 | $ | 26,089 | $ | (13,550 | ) | $ | 8,381 | $ | 3,415 | |||||||||
|
Net
income (loss) attributable to Genesis Energy, L.P. per common unit
basic:
|
||||||||||||||||||||
|
Continuing
operations
|
$ | 0.51 | $ | 0.59 | $ | (0.66 | ) | $ | 0.59 | $ | 0.38 | |||||||||
|
Discontinued
operations
|
- | - | - | - | 0.03 | |||||||||||||||
|
Cumulative
effect of change in accounting principle
|
- | - | - | - | (0.06 | ) | ||||||||||||||
|
Net
income (loss)
|
$ | 0.51 | $ | 0.59 | $ | (0.66 | ) | $ | 0.59 | $ | 0.35 | |||||||||
|
Cash
distributions per common unit
|
$ | 1.3650 | $ | 1.2225 | $ | 0.93 | $ | 0.74 | $ | 0.61 | ||||||||||
|
Year
Ended December 31,
|
||||||||||||||||||||
|
2009
|
2008
(1)
|
2007
(1)
|
2006
|
2005
|
||||||||||||||||
|
Balance
Sheet Data (at end of period):
|
||||||||||||||||||||
|
Current
assets
|
$ | 189,244 | $ | 168,127 | $ | 214,240 | $ | 99,992 | $ | 90,449 | ||||||||||
|
Total
assets
|
1,148,127 | 1,178,674 | 908,523 | 191,087 | 181,777 | |||||||||||||||
|
Long-term
liabilities
|
387,766 | 394,940 | 101,351 | 8,991 | 955 | |||||||||||||||
|
Partners'
capital:
|
||||||||||||||||||||
|
Genesis
Energy, L.P.
|
595,877 | 632,658 | 631,804 | 85,662 | 87,689 | |||||||||||||||
|
Noncontrolling
interests
|
23,056 | 24,804 | 570 | 522 | 522 | |||||||||||||||
|
Total
partners' capital
|
618,933 | 657,462 | 632,374 | 86,184 | 88,211 | |||||||||||||||
|
Other
Data:
|
||||||||||||||||||||
|
Maintenance
capital expenditures
(4)
|
4,426 | 4,454 | 3,840 | 967 | 1,543 | |||||||||||||||
|
Volumes
- continuing operations:
|
||||||||||||||||||||
|
Crude
oil pipeline (barrels per day)
|
60,262 | 64,111 | 59,335 | 61,585 | 61,296 | |||||||||||||||
|
CO
2
pipeline (Mcf per day)
(5)
|
154,271 | 160,220 | - | - | - | |||||||||||||||
|
CO
2
sales (Mcf per day)
|
73,328 | 78,058 | 77,309 | 72,841 | 56,823 | |||||||||||||||
|
NaHS
sales (DST)
(6)
|
107,311 | 162,210 | 69,853 | - | - | |||||||||||||||
|
NaOH
sales (DST)
(6)
|
88,959 | 68,647 | 20,946 | - | - | |||||||||||||||
|
|
(1)
O
ur operating
results and financial position have been affected by acquisitions in 2008
and 2007, most notably the Grifco acquisition in July 2008 and the Davison
acquisition, which was completed in July 2007. The results of these
operations are included in our financial results prospectively from the
acquisition date. For additional information regarding these acquisitions,
see Note 3 of the Notes to the 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
2009, we recorded an impairment charge of $5.0 million related to an
investment in the Faustina Project. For additional information
related to this charge, see Note 9 of the Notes to the Consolidated
Financial Statements included under Item 8 of this annual
report. 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)Volume
per day for the period we owned the Free State CO
2
pipeline in 2008.
|
|
|
(6)Volumes
relate to operations acquired in July
2007.
|
It
em 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 2009
|
|
|
·
|
Available
Cash before Reserves
|
|
|
·
|
Results
of Operations
|
|
|
·
|
Significant
Events
|
|
|
·
|
Capital
Resources and Liquidity
|
|
|
·
|
Commitments
and Off-Balance Sheet Arrangements
|
|
|
·
|
Critical
Accounting Policies and Estimates
|
|
|
·
|
Recent
Accounting Pronouncements
|
In the
discussions that follow, we will focus on our revenues, expenses and net income,
as well as two measures that we use to manage the business and to review the
results of our operations. Those two measures are segment margin and
Available Cash before Reserves.
We define
segment margin as revenues less cost of sales, operating expenses (excluding
depreciation and amortization), and segment general and administrative expenses,
plus our equity in distributable cash generated by our joint
ventures. In addition, our segment margin definition excludes the
non-cash effects of our equity-based compensation plans and the unrealized gains
and losses on derivative transactions not designated as hedges for accounting
purposes. Segment margin includes the non-income portion of payments
received under direct financing leases. Segment margin includes all
costs that are directly associated with a business segment including costs such
as general and administrative expenses that are directly incurred by a business
segment and all payments received under direct financing leases. In
order to improve comparability between periods, we exclude from segment margin
the non-cash effects of our equity-based compensation plans which are impacted
by changes in the market price for our common units. 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 before income taxes is included in
our segment disclosures in Note 13 to the Consolidated Financial
Statements.
Available
Cash before Reserves (a non-GAAP measure) is net income as adjusted for specific
items, the most significant of which are 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, the elimination of
gains and losses on asset sales (except those from the sale of surplus assets)
and unrealized gains and losses on derivative transactions not designated as
hedges for accounting purposes, 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 2009
In 2009,
we reported net income attributable to Genesis Energy, L.P. of $8.1 million, or
$0.51 per common unit. Non-cash depreciation, amortization and
impairment totaling $67.6 million and non-cash charges related to compensation
to our senior executive team totaling $14.1 million reduced net income
attributable to Genesis Energy, L.P. during the year. See
additional discussion of our depreciation, amortization and impairment expense
and the charge related to executive compensation in “Results of Operations –
Other Costs and Interest” below.
Increases
in cash flow generally result in increases in Available Cash before Reserves,
from which we pay distributions quarterly to holders of our common units and our
general partner. During 2009, we generated $91 million of Available
Cash before Reserves, and we distributed $60.1 million to holders of our common
units and general partner. Cash provided by operating activities in
2009 was $90.1 million. Our total distributions attributable to 2009
increased 19% over the total distributions attributable to 2008.
Additionally,
on January 14, 2010, we declared our eighteenth consecutive increase in our
quarterly distribution to our common unitholders relative to the fourth quarter
of 2009. This distribution of $0.36 per unit (paid in February 2010)
represents a 9% increase from our distribution of $0.33 per unit for the fourth
quarter of 2008. During the fourth quarter of 2009, we paid a distribution of
$0.3525 per unit related to the third quarter of 2009.
The
current economic recession continues to restrict the availability of credit and
access to capital in our business environment. While we anticipate
that the challenging economic environment will continue for the foreseeable
future, we believe that our current cash balances, future internally-generated
funds and funds available under our credit facility will provide sufficient
resources to meet our current working capital liquidity needs. The
financial performance of our existing businesses, $86 million in cash and
existing debt commitments and no need, other than opportunistically, to access
the capital markets, may allow us to take advantage of acquisition and/or growth
opportunities that may develop.
Our
ability to fund large new projects or make large acquisitions in the near term
may be limited by the current conditions in the credit and equity markets due to
limitations in our ability to issue new debt or equity financing. We
will consider other arrangements to fund large growth projects and acquisitions
such as private equity and joint venture arrangements.
Available
Cash before Reserves
Available
Cash before Reserves for the year ended December 31, 2009 is as follows (in
thousands):
|
Year
Ended
|
||||
|
December 31,
2009
|
||||
|
Net
(loss) income attributable to Genesis Energy, L.P.
|
$ | 8,063 | ||
|
Depreciation,
amortization and impairment
|
67,586 | |||
|
Cash
received from direct financing leases not included in
income
|
3,758 | |||
|
Cash
effects of sales of certain assets
|
873 | |||
|
Effects
of available cash generated by equity method investees not included in
income
|
(495 | ) | ||
|
Cash
effects of equity-based compensation plans
|
(121 | ) | ||
|
Non-cash
tax expense
|
1,914 | |||
|
Earnings
of DG Marine in excess of distributable cash
|
(4,475 | ) | ||
|
Non-cash
equity-based compensation expense
|
18,512 | |||
|
Other
non-cash items, net
|
(203 | ) | ||
|
Maintenance
capital expenditures
|
(4,426 | ) | ||
|
Available
Cash before Reserves
|
$ | 90,986 | ||
We have
reconciled Available Cash before Reserves (a non-GAAP measure) to cash flows
from operating activities (the most comparable GAAP measure) for the year ended
December 31, 2009 in
“Capital
Resources and Liquidity – Non-GAAP Reconciliation”
below. For
the year ended December 31, 2009, net cash provided by operating activities was
$90.1 million.
Results
of Operations
Revenues,
Costs and Expenses and Net Income
Our
revenues for the year ended December 31, 2009 decreased $706 million, or 33%
from 2008. Additionally, our costs and expenses decreased $690
million, or 33%, between the two periods. The majority of our revenues and our
costs are derived from the purchase and sale of crude oil and petroleum
products. The significant decline in our revenues and costs between
2008 and 2009 is primarily attributable to the fluctuations in the market prices
for crude oil and petroleum products. In 2008, prices for West Texas
Intermediate crude oil on the New York Mercantile Exchange averaged $99.65, as
compared to $61.80 in 2009 - a 38% decline. Net income (attributable
to us) declined $18 million, or 69%, between 2009 and 2008. An
increase in non-cash charges included in general and administrative expenses
related to executive compensation and equity-based compensation totaling $16.6
million provided most of the decline in net income. See additional
discussion of these charges in “
Other Costs and Interest
”
below.
Revenues
and costs and expenses in 2008 increased as compared to 2007 primarily as a
result of a 38% increase in market prices for crude oil and the effects of a
full-year of ownership of the Davison family businesses acquired in July
2007. Revenues increased $942 million, or 79%, while costs increased
$899 million, or 75%, between the two periods. Net income
attributable to us increased from a loss of $13.6 million in 2007 to income of
$26.1 million in 2008. The majority of this improvement resulted from
the effect of twelve months of activity from the Davison acquisition in 2008 as
compared to five months in 2007.
Included
below is additional detailed discussion of the results of our operations
focusing on segment margin and other costs including general and administrative
expense, depreciation, amortization and impairment, interest and income
taxes.
Segment
Margin
The
contribution of each of our segments to total segment margin in each of the last
three years was as follows:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Pipeline
transportation
|
$ | 42,162 | $ | 33,149 | $ | 14,170 | ||||||
|
Refinery
services
|
51,844 | 55,784 | 19,713 | |||||||||
|
Supply
and logistics
|
29,052 | 32,448 | 10,646 | |||||||||
|
Industrial
gases
|
11,432 | 13,504 | 13,038 | |||||||||
|
Total
segment margin
|
$ | 134,490 | $ | 134,885 | $ | 57,567 | ||||||
Pipeline
Transportation Segment
We
operate three common carrier crude oil pipeline systems and a CO
2
pipeline
in a four state area. We refer to these pipelines as our Mississippi
System, Jay System, Texas System and Free State Pipeline. Volumes
shipped on these systems for the last three years are as follows (barrels or Mcf
per day):
|
Pipeline
System
|
2009
|
2008
|
2007
|
|||||||||
|
Mississippi-Bbls/day
|
24,092 | 25,288 | 21,680 | |||||||||
|
Jay
- Bbls/day
|
10,523 | 13,428 | 13,309 | |||||||||
|
Texas
- Bbls/day
|
25,647 | 25,395 | 24,346 | |||||||||
|
Free
State - Mcf/day
|
154,271 | 160,220 |
(1)
|
- | ||||||||
(1) Daily
average for the period we owned the pipeline in 2008.
The
Mississippi System begins in Soso, Mississippi and extends to Liberty,
Mississippi. At Liberty, shippers can transfer the crude oil to a
connection with Capline, a pipeline system that moves crude oil from the Gulf
Coast to refineries in the Midwest. In order to handle expected
future increases in production volumes in the area surrounding the Mississippi
System, we have made capital expenditures for tank, station and pipeline
improvements over the last five years and we will continue to make further
improvements.
Our
Mississippi System is adjacent to several existing and prospective oil
fields. Additional development of these fields using CO
2
based
tertiary recovery operations could create an opportunity for us to add to our
existing pipeline infrastructure.
The Jay
Pipeline system in Florida and Alabama ships crude oil from mature producing
fields in the area as well as production from new wells drilled in the
area. The increase in crude oil prices in 2007 and 2008 led to
interest in further development of the mature fields. While crude oil
price declines in late 2008 led a producer to shut-in production from some
mature fields, the increase in prices at the end of 2009 resulted in a re-start
of the production from those fields. As a result, volumes shipped on the Jay
System in the fourth quarter of 2009 averaged 12,766 barrels per day, an
increase of 2,243 barrels per day from the average for 2009.
The new
production in the area 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 increases
in our cash flows from the Jay System.
As we
have consistently been able to increase our pipeline tariffs as needed and due
to the new production in the area surrounding our Jay System, we do not believe
that a decline in volumes or revenues from sales of pipeline loss allowance
volumes will affect the recoverability of the net investment that remains for
the Jay System.
Volumes
on our Texas System averaged 25,647 barrels per day during 2009. 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. We lease tankage in Webster on the Texas
System of approximately 165,000 barrels. We have a tank rental
reimbursement agreement with the primary shipper on our Texas System to
reimburse us for the expense of leasing 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
entered into a twenty-year transportation services agreement (through May 2028)
to deliver CO
2
on the
Free State pipeline for use in in tertiary recovery operations in east
Mississippi. Under the terms of the transportation services
agreement, we are responsible for owning, operating, maintaining and making
improvements to the pipeline. Denbury currently has rights to
exclusive use of the pipeline and is required to use the pipeline to supply
CO
2
to
its current and certain of its other tertiary operations in east
Mississippi. Variations in Denbury’s CO2 tertiary recovery activities
create the fluctuations in the volumes transported on the Free State
pipeline. The transportation services agreement provides for a $0.1
million per month minimum payment plus a tariff based on throughput. Denbury has
two renewal options, each for five years on similar terms.
We
operate a CO
2
pipeline
in Mississippi to transport CO
2
to
Brookhaven oil field. Denbury has the exclusive right to use this
CO
2
pipeline. This arrangement has been accounted for as a direct
financing lease.
We also
have a twenty-year financing lease (through 2028) with Denbury initially valued
at $175 million related to Denbury’s North East Jackson Dome (NEJD) Pipeline
System. Denbury makes fixed quarterly base rent payments to us of
$5.2 million per quarter or approximately $20.7 million per year.
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 for our pipeline transportation segment were as follows.
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Pipeline
transportation revenues, excluding natural gas
|
$ | 48,603 | $ | 41,097 | $ | 22,755 | ||||||
|
Natural
gas tariffs and sales, net of gas purchases
|
278 | 232 | 334 | |||||||||
|
Pipeline
operating costs, excluding non-cash charges for equity-based
compensation
|
(10,477 | ) | (10,529 | ) | (9,488 | ) | ||||||
|
Non-income
payments under direct financing leases
|
3,758 | 2,349 | 569 | |||||||||
|
Segment
margin
|
$ | 42,162 | $ | 33,149 | $ | 14,170 | ||||||
Year
Ended December 31, 2009 Compared with Year Ended December 31, 2008
Pipeline
segment margin increased $9.0 million in 2009 as compared to
2008. This increase is primarily attributable to the following
factors:
|
|
·
|
An
increase in revenues from CO
2
financing leases and tariffs of $10.5 million and a related increase in
payments from the same financing leases of $1.4 million not included as
income (non-income payments under direct financing
leases).
|
|
|
·
|
Tariff
rate increases of approximately 7.6% on our Jay and Mississippi pipelines
that went into effect July 1, 2009. The rate increases
increased segment margin between the two periods by approximately $1.9
million.
|
|
|
·
|
Partially
offsetting the increase in segment margin was a decrease in revenues from
sales of pipeline loss allowance volumes of $4.1
million,
|
|
|
·
|
A
decline in volumes transported on our crude oil pipelines between the two
periods decreased segment margin by $1.0
million.
|
Revenues
for 2008 only included results from the NEJD and Free State CO
2
pipelines
for a seven-month period while 2009 included results for a twelve-month
period. The average volume transported on the Free State pipeline for
2009 was 154 MMcf per day, with the transportation fees and the minimum payments
totaling $7.3 million and $1.2 million, respectively. Transportation
fees and the minimum payments for the seven months in 2008 were $4.4 million and
$0.7 million, respectively, with an average transportation volume of 160 MMcf
per day.
As is
common in the industry, our crude oil tariffs incorporate a loss allowance
factor that is intended to, among other things, offset losses due to
evaporation, measurement and other losses in transit. We value the
variance of allowance volumes to actual losses at the average market value at
the time the variance occurred and the result is recorded as either an increase
or decrease to tariff revenues. The decline in market prices for
crude oil reduced the value of our pipeline loss allowance volumes and,
accordingly, our loss allowance revenues. Average crude oil market
prices decreased approximately $38 per barrel between the two
periods. In addition, pipeline loss allowance volumes decreased by
approximately 10,000 barrels between the annual periods. Based on
historic volumes, a change in crude oil market prices of $10 per barrel has the
effect of decreasing or increasing our pipeline loss allowance revenues by
approximately $0.1 million per month.
The
decreased crude oil pipeline volumes were principally due to a producer
connected to our Jay System shutting in production at the end of 2008 due to the
decline in crude oil prices in the latter half of 2008, resulting in a decline
on the Jay System in average daily volume of 2,905 barrels per
day The tariff on the Mississippi System is an incentive tariff, such
that the average tariff per barrel decreases as the volumes increase; therefore
the effect of the decline in the volumes of 1,196 barrels per day on that system
was mitigated by the relatively low incremental tariff rate.
Year
Ended December 31, 2008 Compared with Year Ended December 31, 2007
Pipeline
segment margin increased $19.0 million in 2008 as compared to
2007. This increase is primarily attributable to the following
factors:
|
|
·
|
An
increase in revenues from the lease of the NEJD pipeline beginning in May
2008 added $12.1 million to segment
margin;
|
|
|
·
|
an
increase in revenues from the Free State pipeline beginning in May 2008
added a total of $5.1 million to CO
2
tariff revenues, with the transportation fee related to 34.3 MMcf totaling
$4.4 million and the minimum monthly payments totaling $0.7
million;
|
|
|
·
|
an
increase in revenues from crude oil tariffs and direct financing leases of
$1.4 million; and
|
|
|
·
|
an
increase in revenues from sales of pipeline loss allowance volumes of $1.7
million, resulting from an increase in the average annual crude oil market
prices of $26.73 per barrel, offset by a decline in allowance volumes of
approximately 15,000 barrels.
|
|
|
·
|
Partially
offsetting the increase in segment margin was an increase of $1.0 million
in pipeline operating costs.
|
Tariff
and direct financing lease revenues from our crude oil pipelines increased
primarily due to volume increases on all three pipeline systems totaling 4,776
barrels per day. These volume increases occurred despite the brief disruptions
in operations caused by Hurricanes Gustav and Ike which affected power supplies
on the Gulf Coast.
The
overall impact of an annual tariff increase on July 1, 2008 combined with the
volume increase on the Mississippi System resulted in improved tariff revenues
from this system of $0.6 million. As a result of the annual tariff
increase on July 1, 2008, average tariffs on the Jay System increased by
approximately $0.06 per barrel between the two periods. Combined with
the 119 barrels per day increase in average daily volumes, the Jay System tariff
revenues increased $0.4 million. The impact of volume increases on
the Texas System on revenues is not very significant due to the relatively low
tariffs on that system. Approximately 75% of the 2008 volume on that
system was shipped on a tariff of $0.31 per barrel.
Pipeline
operating costs increased $1.0 million, with approximately $0.4 million of that
amount due to an increase in IMP testing and repairs, $0.2 million related to
the Free State pipeline acquired in May 2008 and $0.1 million related to
increased electricity costs. Fluctuations in the cost of our IMP
program are a function of the length and age of the segments of the pipeline
being tested each year and the type of test being
performed. Electricity costs in 2008 were higher due to market
increases in the cost of power. The remaining $0.3 million of
increased pipeline operating costs were related to various operational and
maintenance items.
Refinery
Services Segment
Operating
results from our refinery services segment were as follows:
|
Year
Ended
|
Five-months
Ended
|
|||||||||||
|
December 31,
|
December 31,
|
|||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Volumes
sold:
|
||||||||||||
|
NaHS
volumes (Dry short tons "DST")
|
107,311 | 162,210 | 69,853 | |||||||||
|
NaOH
volumes (DST)
|
88,959 | 68,647 | 20,946 | |||||||||
|
Total
|
196,270 | 230,857 | 90,799 | |||||||||
|
NaHS
revenues
|
$ | 97,962 | $ | 167,715 | $ | 43,326 | ||||||
|
NaOH
revenues
|
38,773 | 53,673 | 9,173 | |||||||||
|
Other
revenues
|
10,505 | 12,483 | 13,082 | |||||||||
|
Total
external segment revenues
|
$ | 147,240 | $ | 233,871 | $ | 65,581 | ||||||
|
Segment
margin
|
$ | 51,844 | $ | 55,784 | $ | 19,713 | ||||||
|
Average
index price for NaOH per DST
(1)
|
$ | 424 | $ | 702 | $ | 390 | ||||||
|
Raw
material and processing costs as % of segment revenues
|
44 | % | 41 | % | 49 | % | ||||||
|
Delivery
costs as a % of segment revenues
|
12 | % | 8 | % | 17 | % | ||||||
|
|
(1)
|
Source: Harriman
Chemsult Ltd.
|
Year
Ended December 31, 2009 Compared with Year Ended December 31, 2008
Segment
margin for our refinery services segment decreased $3.9 million between 2009 and
2008. The significant components of this change were as
follows:
|
|
·
|
NaHS
volumes declined 34%. Macroeconomic conditions have negatively
impacted the demand for NaHS, primarily in mining and industrial
activities. Since the second quarter of 2009, market prices and
demand for copper and molybdenum have improved and demand for NaHS has
increased, with sales of NaHS in the fourth quarter of 2009 totaling
31,967 DST, an increase of more than 6,800 DST over the average of the
prior three quarters sales volumes. Similarly, future
improvements in industrial activities including the paper and pulp and
tanning industries may improve NaHS
demand.
|
|
|
·
|
NaOH
(or caustic soda) sales volumes increased 30%. NaOH is a key
component in the provision of our services for which we receive the
by-product NaHS. We are a very large consumer of caustic soda,
and our economies of scale and logistics capabilities allow us to
effectively market caustic soda to third parties. With the
decline in NaHS production during 2009, we focused on expanding our
activities as a NaOH supplier.
|
|
|
·
|
Average
index prices for caustic soda were somewhat volatile in 2008, ranging from
an average index price of approximately $450 per dry short ton (DST)
during the first quarter of 2008 to a high of $950 per DST in the fourth
quarter of 2008. Since that time market prices of caustic
soda have decreased to approximately $230 per DST. This
volatility affects both the cost of caustic soda used to provide our
services as well as the price at which we sell NaHS and caustic
soda.
|
|
|
·
|
Raw
material and processing costs related to providing our refinery services
and supplying caustic soda as a percentage of our segment margin increased
3% between periods. The key component in the provision of our
refinery services is caustic soda. In addition, as discussed
above, we also market caustic soda. As the market price of
caustic soda has fluctuated in 2008 and 2009, we have had to aggressively
manage our acquisition costs to minimize purchasing caustic soda for use
in our operations in a period of falling market prices. We have
generally been successful in this management, as reflected by the
relatively small percentage increase in costs despite the significant
decline in caustic prices. We have also taken steps to reduce
processing costs and to manage our logistics costs related to our caustic
soda purchases.
|
Year
Ended December 31, 2008 Compared with Year Ended December 31, 2007
Segment
margin from our refinery services for 2008 was $55.8 million. Segment
margin from our refinery services for the five months we owned this business in
2007 was $19.7 million. Annualizing the five-month results from 2007
and comparing those results to the 2008 segment margin would indicate that
segment margin increased by approximately $8.5 million between the
periods. Improved management of production and operating costs, as a
percentage of revenues, was a significant contributor to this indicated
increase.
Supply
and Logistics Segment
Our
supply and logistics segment is focused on utilizing our knowledge of the crude
oil and petroleum markets and our logistics capabilities from our terminals,
trucks and barges to provide suppliers and customers with a full suite of
services. These services include:
|
|
·
|
purchasing
and/or transporting crude oil from the wellhead to markets for ultimate
use in refining;
|
|
|
·
|
supplying
petroleum products (primarily fuel oil, asphalt, diesel and gasoline) to
wholesale markets and some end-users such as paper mills and
utilities;
|
|
|
·
|
purchasing
products from refiners, transporting the products to one of our terminals
and blending the products to a quality that meets the requirements of our
customers; and
|
|
|
·
|
utilizing
our fleet of trucks and trailers and barges to take advantage of
logistical opportunities primarily in the Gulf Coast states and inland
waterways.
|
We also
use our terminal facilities to take advantage of contango market conditions for
crude oil gathering and marketing, and to capitalize on regional opportunities
which arise from time to time for both crude oil and petroleum
products.
Many U.S.
refineries have distinct configurations and product slates that require crude
oil with specific characteristics, such as gravity, sulfur content and metals
content. The refineries evaluate the costs to obtain, transport and
process their preferred feedstocks. Despite crude oil being
considered a somewhat homogenous commodity, many refiners are very particular
about the quality of crude oil feedstock they process. That
particularity provides us with opportunities to help the refineries in our areas
of operation identify crude oil sources meeting their requirements, and to
purchase the crude oil and transport it to the refineries for
sale. The imbalances and inefficiencies relative to meeting the
refiners’ requirements can provide opportunities for us to utilize our
purchasing and logistical skills to meet their demands and take advantage of
regional differences. The pricing in the majority of our purchase
contracts contain a market price component, unfixed bonuses that are based on
several other market factors and a deduction to cover the cost of transporting
the crude oil and to provide us with a margin. Contracts sometimes contain a
grade differential which considers the chemical composition of the crude oil and
its appeal to different customers. Typically the pricing in a
contract to sell crude oil will consist of the market price components and the
grade differentials. The margin on individual transactions is then
dependent on our ability to manage our transportation costs and to capitalize on
grade differentials.
When
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 storage capacity we own for use in this strategy is approximately
420,000 barrels, although maintenance activities on our pipelines can impact the
availability of a portion of this storage capacity. We generally
account for this inventory and the related derivative hedge as a fair value
hedge under the accounting guidance. See Note 18 of the Notes to the
Consolidated Financial Statements.
In our
petroleum products marketing operations, we supply primarily 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
“heavier” petroleum products that are the residual fuels from gasoline
production, transporting them to one of our terminals and blending them to a
quality that meets the requirements of our customers. The
opportunities to provide this service cannot be predicted, but their
contribution to margin as a percentage of their revenues tend to be higher than
the same percentage attributable to our recurring operations. We
utilize our fleet of 270 trucks and 270 trailers and DG Marine’s twenty
“hot-oil” barges in combination with our 1.6 million barrels of existing leased
and owned storage to service our refining customers and to store and blend the
intermediate and finished refined products.
Operating
results from continuing operations for our supply and logistics segment were as
follows.
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Supply
and logistics revenue
|
$ | 1,226,838 | $ | 1,852,414 | $ | 1,094,189 | ||||||
|
Crude
oil and products costs, excluding unrealized gains and losses from
derivative transactions
|
(1,115,809 | ) | (1,736,637 | ) | (1,041,738 | ) | ||||||
|
Operating
and segment general and administrative costs,excluding non-cash charges
for stock-based compensation and other non-cash expenses
|
(81,977 | ) | (83,329 | ) | (41,805 | ) | ||||||
|
Segment
margin
|
$ | 29,052 | $ | 32,448 | $ | 10,646 | ||||||
|
Volumes
of crude oil and petroleum products (mbbls)
|
17,563 | 17,410 | 14,246 | |||||||||
Year
Ended December 31, 2009 Compared with Year Ended December 31, 2008
As
discussed above in “Revenues, Costs and Expenses and Net Income,” the average
market prices of crude oil declined by approximately $38 per barrel, or
approximately 38% between the two periods. Similarly, market prices
for petroleum products declined significantly between 2008 and
2009. Fluctuations in these prices, however, have a limited impact on
our segment margin.
The key
factors affecting the change in segment margin between 2009 and 2008 were as
follows:
|
|
·
|
Segment
margin generated by DG Marine’s inland marine barge operations, which
increased segment margin by $5.6
million;
|
|
|
·
|
Crude
oil contango market conditions, which increased segment margin by $2.2
million; and
|
|
|
·
|
Reduction
in opportunities to purchase and blend crude oil and products, which
reduced segment margin by $11.1
million.
|
The
inland marine transportation operations of Grifco Transportation, acquired by DG
Marine in mid-July of 2008, contributed $5.6 million more to segment margin in
2009 as compared to 2008, primarily as a result of owning these operations for
twelve months in 2009 as compared to approximately six months in
2008. These operations provided us with an additional capability to
provide transportation services of petroleum products by barge. As
part of the acquisition, DG Marine acquired six tows (a tow consists of a push
boat and two barges.) A total of four additional tows added in the
fourth quarter of 2008 and first half of 2009 generated the segment margin
increase despite declines in average charter rates for the tows over the same
period.
During
2009, crude oil markets were in contango (oil prices for future deliveries are
higher than for current deliveries), providing an opportunity for us to purchase
and store crude oil as inventory for delivery in future months. The
crude oil markets were not in contango during most of 2008. During
2009, we held an average of approximately 174,000 barrels of crude oil per month
in our storage tanks and hedged this volume with futures contracts on the
NYMEX. We are accounting for the effects of this inventory position
and related derivative contracts as a fair value hedge under accounting
guidance. The effect on segment margin for the amount excluded from
effectiveness testing related to this fair value hedge was a $2.2 million gain
in 2009.
Offsetting
these improvements in segment margin was a decrease in the margins from our
crude oil gathering and petroleum products marketing operations. In
2009, we experienced some reductions in volumes as a result of crude oil
producers’ choices to reduce operating expenses or postpone development
expenditures that could have maintained or enhanced their existing production
levels. As a consequence of the reductions in volumes, our segment
margin from crude oil gathering declined between the annual periods by $2.7
million. Volatile price changes in the petroleum products markets and
robust refinery utilization in 2008 created blending and sales opportunities
with expanded margins in comparison to historical rates. Relatively
flat petroleum prices and reduced refinery utilization in 2009 narrowed the
economics of our blending opportunities and reduced sales margins to more
historical rates. Somewhat offsetting these margin declines were the
additional opportunities to handle volumes from the heavy end of the refined
barrel due to our access to additional leased heavy products storage capacity
and to barge transportation capabilities through DG Marine. However,
the net result of these factors was a reduction of our segment margin of $8.5
million from petroleum products and related activities.
Year
Ended December 31, 2008 Compared with Year Ended December 31, 2007
In 2008,
our supply and logistics segment margin included a full year of contribution
from the assets acquired in July 2007 from the Davison family, as compared to
only five months in 2007. This additional seven months of activity in
2008 was the primary factor in the increase in segment margin.
The
dramatic rise in commodity prices in the first nine months of 2008 provided
significant opportunities to us to take advantage of purchasing and blending of
“off-spec” products. The average NYMEX price for crude oil rose from
$95.98 per barrel at December 31, 2007 to a high of $145.29 per barrel in July
2008, and then declined to $44.60 per barrel at December 31,
2008. Grade differentials for crude oil widened significantly during
this period as refiners sought to meet consumer demand for gasoline and
diesel. This widening of grade differentials provided us with
opportunities to acquire crude oil with a higher specific gravity and sulfur
content (heavy or sour crude oil) at significant discounts to market prices for
light sweet crude oil and sell it to refiners at prices providing significantly
greater margin to us than sales of light sweet crude oil.
The
absolute market price for crude oil also impacts the price at which we recognize
volumetric gains and losses that are inherent in the handling and transportation
of any liquid product. In 2008 our average monthly volumetric gains were
approximately 2,000 barrels.
In the
first half of 2007, crude oil markets were in contango, providing an opportunity
for us to increase segment margin. This opportunity did not exist in
most of 2008.
The
demand for gasoline by consumers during most of 2008 also led refiners to focus
on producing the “light” end of the refined barrel. Some refiners
were willing to sell the heavy end of the refined barrel, in the form of fuel
oil or asphalt, as well as product not meeting their specifications for use in
making gasoline, at discounts to market prices in order to free up capacity at
their refineries to meet gasoline demand. Our ability to utilize our
logistics equipment to transport product from the refiner’s facilities to one of
our terminals increased the opportunity to acquire the product at a
discount.
Our
operating and segment general and administrative (G&A) costs increased by
$41.5 million in 2008 as compared to 2007. The costs of operating the
logistical equipment and terminals acquired in the Davison acquisition for an
additional seven months in 2008 accounted for approximately $30.2 million of
this difference. Our inland marine transportation operations acquired
in July 2008 added approximately $8.4 million to our costs in
2008. The remaining increase in costs of $2.9 million is attributable
to the crude oil portion of our supply and logistics operations. The
most significant components of our operating and segment G&A costs consist
of fuel for our fleet of trucks, maintenance of our trucks, terminals and
barges, and personnel costs to operate our equipment. In 2008, fuel
costs for our trucks increased significantly as result of market prices for
diesel fuel.
Industrial
Gases Segment
Our
industrial gases segment includes the results of our CO
2
sales to
industrial customers and our share of the available cash generated by our 50%
joint ventures, T&P Syngas and Sandhill.
Operating
Results
Operating
results for our industrial gases segment were as follows.
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Revenues
from CO
2
marketing
|
$ | 16,206 | $ | 17,649 | $ | 16,158 | ||||||
|
CO
2
transportation and other costs
|
(5,825 | ) | (6,484 | ) | (5,365 | ) | ||||||
|
Available
cash generated by equity investees
|
1,051 | 2,339 | 2,245 | |||||||||
|
Segment
margin
|
$ | 11,432 | $ | 13,504 | $ | 13,038 | ||||||
|
Volumes
per day:
|
||||||||||||
|
CO
2
marketing - Mcf
|
73,328 | 78,058 | 77,309 | |||||||||
CO
2
–
Industrial Customers
We supply
CO
2
to
industrial customers under seven long-term CO
2
sales
contracts. The terms of our contracts with the industrial CO
2
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. At December 31, 2009,
we have no liabilities to customers for gas paid for but not taken.
Our seven
industrial contracts expire at various dates beginning in 2011 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 2009, we expect some seasonality in our sales
of CO
2
. The
dominant months for beverage carbonation and freezing food are from April to
October, when warm weather increases demand for beverages and the approaching
holidays increase demand for frozen foods. The table below depicts
these seasonal fluctuations. The average daily sales (in Mcfs) of
CO
2
for each quarter in 2009 and 2008 under these contracts were as
follows:
|
Quarter
|
2009
|
2008
|
||||||
|
First
|
69,833 | 73,062 | ||||||
|
Second
|
70,621 | 79,968 | ||||||
|
Third
|
80,520 | 83,816 | ||||||
|
Fourth
|
72,233 | 75,164 | ||||||
Segment
margin decreased between 2009 and 2008 due to a decline in volumes and a slight
decrease in the average sales price of CO
2
to our
customer. Volumes declined 6% between the periods as customers
reduced purchases. The average sales price of CO
2
decreased
$0.01 per Mcf, or 2%, due to variations in the volumes sold among contracts with
different pricing terms. The increasing margins from the industrial
gases segment between 2007 and 2008 were the result of an increase in volumes
and an increase in the average revenue per Mcf sold of 8% from 2007 to
2008. Inflation adjustments in the contracts and variations in the
volumes sold under each contract cause the changes in average revenue per
Mcf.
Transportation
costs for the CO
2
remained
consistent as a percentage of revenues at approximately 36% to
37%. The transportation rate we pay Denbury is adjusted annually for
inflation in a manner similar to the sales prices for the CO
2
. We
also recorded a charge for approximately $0.3 million and $0.9 million in 2009
and 2008, respectively, related to a commission on one of the industrial gas
sales contracts. We expect this commission to continue in future
years at a cost of approximately $0.3 million annually.
Equity
Method Joint Ventures
Our share
of the available cash before reserves generated by equity investments in each
year primarily resulted from our investment in T&P Syngas. Our
share of the available cash before reserves generated by T&P Syngas for
2009, 2008, and 2007 was $0.9 million, $2.2 million and $1.9 million,
respectively. In the third quarter of 2009, T&P Syngas performed
a scheduled turnaround at its facility that decreased its revenues and increased
maintenance expenses. Additionally, T&P Syngas incurred expenses
related to improving its treatment of waste water. These activities
were completed during the third quarter and the expenses were paid from funds
generated by T&P Syngas, reducing the amounts available to be distributed to
the partners in T&P Syngas. In 2010, we do not expect to perform
a turnaround, which should result in additional cash being distributed to the
partners as compared to 2009.
Other
Costs and Interest
General and administrative
expenses
were as follows.
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
General
and administrative expenses not separately identified
below
|
$ | 20,277 | $ | 25,131 | $ | 16,760 | ||||||
|
Bonus
plan expense
|
3,900 | 4,763 | 2,033 | |||||||||
|
Equity-based
compensation plans (credit) expense
|
2,132 | (394 | ) | 1,593 | ||||||||
|
Compensation
expense related to management team
|
14,104 | - | 3,434 | |||||||||
|
Management
team transition costs
|
- | - | 2,100 | |||||||||
|
Total
general and administrative expenses
|
$ | 40,413 | $ | 29,500 | $ | 25,920 | ||||||
Our
general and administrative costs increased substantially between 2007 and 2008
as a result of the acquisitions we made mid-year in 2008 and
2007. Additional personnel in our financial, human resources and
other functions to support our operations added to these costs. As we
grew, we incurred increased legal, audit, tax and other consulting and
professional fees, and additional director fees and
expenses. In 2009, we reduced expenses primarily in the areas
of professional fees and services.
The
amounts paid under our bonus plan are a function of both the Available Cash
before Reserves that we generate in a year and the improvement in our safety
record, and are approved by our Compensation Committee of our Board of
Directors. As a result of our performance in 2009, the pool available
for bonuses was determined to be $0.9 million less than 2008. Between
2008 and 2007, our bonus pool increased by $2.7 million due to the tripling of
our personnel count in mid 2007. The bonus plan for employees is described in
Item 11, “Executive Compensation” below.
We record
equity-based compensation expense for phantom units issued under our long-term
incentive plan and for our stock appreciation rights (SAR) plan. (See
additional discussion in Item 11, “Executive Compensation” below and Note 16 to
the Consolidated Financial Statements.) The fair value of phantom
units issued under our long-term incentive plan is calculated at the grant date
and charged to expense over the vesting period of the phantom
units. Unlike the accounting for the SAR plan, the total expense to
be recorded is determined at the time of the award and does not change except to
the extent that phantom unit awards do not vest due to employee
terminations. 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. We determine
the fair value of the SARs at the end of each reporting 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 exercises the SARs, creates additional expense. Due to
fluctuations in the market price for our common units, expense for outstanding
and exercised SARs has varied significantly between the periods.
Our
senior management team was hired in August 2006 and finalized a compensation
package in December 2008. Although the terms of these arrangements
were not agreed to and completed at December 31, 2007, 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. Upon completion of the terms of the
compensation arrangements including the requirements for vesting, we determined
that no expense was required to be recorded in 2008. We recorded
compensation expense of $14.1 million related to our senior management team in
2009. Although this compensation is to ultimately come from our
general partner, we have recorded the expense in our Consolidated Statements of
Operations in general and administrative expenses 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. See additional discussion
of the compensation arrangements with our senior management team in Item 11,
“Executive Compensation.”
Additionally,
we recorded transition costs primarily in the form of severance costs when
members of our management team changed in December 2007. 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.
Depreciation, amortization
and impairment expense was as follows:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Depreciation
on Genesis assets
|
$ | 17,945 | $ | 17,331 | $ | 8,909 | ||||||
|
Depreciation
of acquired DG Marine property and equipment
|
7,263 | 3,084 | - | |||||||||
|
Amortization
on acquired Davison intangible assets
|
32,647 | 46,326 | 25,350 | |||||||||
|
Amortization
on acquired DG Marine intangible assets
|
452 | 92 | - | |||||||||
|
Amortization
of CO
2
volumetric production payments
|
4,274 | 4,537 | 4,488 | |||||||||
|
Impairment
expense
|
5,005 | - | 1,498 | |||||||||
|
Total
depreciation, amortization and impairment expense
|
$ | 67,586 | $ | 71,370 | $ | 40,245 | ||||||
Depreciation,
amortization and impairment increased between 2007 and 2008 due primarily to the
depreciation and amortization expense recognized on the fixed assets and
intangible assets acquired from the Davison family in July 2007 and the DG
Marine acquisition in July 2008. Depreciation of DG Marine property
and equipment also increased in 2009 as a result of the addition of four barges
and a push boat to the fleet.
Our
intangible assets 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 through 2010 than in
years subsequent to that time. See Note 10 of the Notes to the Consolidated
Financial Statements for information on the amount of amortization we expect to
record in each of the next five years.
Amortization
of our CO
2
volumetric
payments is based on the units-of-production method. We acquired
three volumetric production payments totaling 280 Mcf of CO
2
from
Denbury between 2003 and 2005. Amortization is based on volumes sold
in relation to the volumes acquired. Amortization of CO
2
volumetric
payments decreased in 2009 as a result of a slight decrease in the volume of
CO
2
sold.
In 2009,
we recorded a $5.0 million impairment charge related to our investment in the
Faustina Project. The Faustina Project is a petroleum coke to ammonia
project in which we first made an investment in 2006. As a result of
a review of the financing alternatives available for the project to use as
construction financing and a determination not to continue making investments in
the project beginning in 2010, we determined that the likelihood of a recovery
of our investment was remote and the fair value of the investment was
zero. For additional information related to this charge, see Note 9
of the Notes to the Consolidated Financial Statements.
In 2007
and 2006, our natural gas pipeline activities were impacted by production
difficulties of a producer attached to the system. Due to declines we
experienced in the results from our natural gas pipelines, we reviewed these
assets in 2007 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.
Interest expense, net
was as follows:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Interest
expense, including commitment fees, excluding DG Marine
|
$ | 8,148 | $ | 10,738 | $ | 10,103 | ||||||
|
Amortization
of facility fees, excluding DG Marine facility
|
662 | 664 | 441 | |||||||||
|
Interest
expense and commitment fees - DG Marine
|
4,446 | 2,269 | - | |||||||||
|
Capitalized
interest
|
(112 | ) | (276 | ) | (59 | ) | ||||||
|
Write-off
of DG Marine facility fees and other fees
|
586 | - | - | |||||||||
|
Interest
income
|
(70 | ) | (458 | ) | (385 | ) | ||||||
|
Net
interest expense
|
$ | 13,660 | $ | 12,937 | $ | 10,100 | ||||||
The
average interest rate on our debt was 2.06% in 2009, approximately 2.2% lower
than the average rate in 2008. Our average outstanding debt balance,
excluding the DG Marine credit facility, increased $114.0 million to $339
million in 2009 over the average outstanding debt balance in 2008, primarily due
to the CO
2
pipeline
dropdown transactions in May 2008 and the DG Marine acquisition in July
2008. The increase in outstanding debt during the year
partially offset the effects of the lower interest rates, with the result of an
overall decrease for the year for interest and commitment fees on our credit
facility of $2.6 million.
DG Marine
incurred interest expense in 2009 of $4.4 million under its credit
facility. Additionally, DG Marine recorded accretion of the
discount on the seller-financed portion of the acquisition cost of the Grifco
assets. (See Note 3 of the Notes to the Consolidated Financial
Statements.) 2009 included a full year of these charges, resulting in
an increase in net interest expense between 2009 and 2008 of $2.2
million.
Excluding
interest and commitment fees on the DG Marine credit facility, net interest
expense increased $0.6 million from 2007 to 2008. This increase in
interest resulted from the borrowings in July 2007 to fund the Davison
acquisition and the CO
2
pipeline
dropdown transactions in May 2008. Our average outstanding balance of debt was
$225 million during 2008, an increase of $107 million over 2007. Our average
interest rate during 2008 was 4.26%, a decrease of 3.52% from 2007.
Income
taxes
. A portion of the operations we acquired in the Davison
transaction are owned by wholly-owned corporate subsidiaries that are taxable as
corporations. As a result, a substantial portion of the income tax
expense we record relates to the operations of those corporations, and will vary
from period to period as a percentage of our income before taxes based on the
percentage of our income or loss that is derived from those
corporations. The balance of the income tax expense we record relates
to state taxes imposed on our operations that are treated as income taxes under
generally accepted accounting principles. In 2009, we recorded income
tax expense of $3.1 million. In 2008 and 2007, we recorded income tax
benefits totaling $0.4 million and $0.7 million,
respectively. The current income taxes we expect to pay for
2009 are approximately $1.2 million, and we provided a deferred tax benefit of
$0.2 million related to temporary differences between the relevant basis of our
assets and liabilities for financial reporting and tax purposes.
Liquidity
and Capital Resources
Capital
Resources/Sources of Cash
Although
credit and access to capital continue to be negatively impacted by current
economic conditions in our business environment, recent market trends have
indicated improvements in bank lending capacity and long-term interest
rates. We anticipate that our short-term working capital needs will
be met through our current cash balances, future internally-generated funds and
funds available under our credit facility. Existing capacity in our
credit facility and $4.1 million of cash on hand, as well as the absence of any
need to access the capital markets, may allow us to take advantage of attractive
acquisition and/or growth opportunities that develop.
For the
long-term, we continue to pursue a growth strategy that requires significant
capital. We expect our long-term 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.
We
continue to monitor the credit markets and the economic outlook to determine the
extent of the impact on our business environment. While some increase
in commodity prices for copper occurred during 2009 increasing demand for NaHS
from the levels in the first quarter of 2009, continuing weak demand in the
United States for fuel has impacted refiners to whom we sell crude oil and has
reduced the availability of petroleum products for our marketing activities due
to reduced refining operating levels. Difficulties for companies in
the mining, paper and pulp products and leather industries have reduced demand
by producers of these goods for the NaHS used in their processes. We
continue to adjust to the effects of these macro-economic factors in our
operating levels and financial decisions.
Our
Consolidated Balance Sheet at December 31, 2009 includes total long-term debt of
$366.9 million, consisting of $46.9 million outstanding under the non-recourse
DG Marine credit facility and $320 million outstanding under our credit
facility. Outstanding letters of credit under our credit facility at
December 31, 2009 were $5.2 million. Our borrowing base under our
$500 million credit facility is a function of our EBITDA (earnings before
interest, taxes, depreciation and amortization), as defined in our credit
agreement for our most recent four calendar quarters.
Our
credit facility has provisions that allow us to increase our borrowing base for
material acquisitions. Upon the completion of four full quarters of
operations including the acquired operations, the EBITDA multiple used to
determine our borrowing base is reduced from 4.75 times to 4.25
times. In mid-August 2009, upon reporting to our lenders our fourth
full quarter of operations including the pipeline transactions that occurred in
May 2008, our borrowing base was calculated using our last four quarters of
EBITDA with a 4.25 multiplier; therefore, our borrowing base at
December 31, 2009 was $407 million. This borrowing base resulted in
approximately $82 million of remaining credit as of December 31, 2009 in
addition to cash on hand and cash that we have temporarily invested in crude oil
and petroleum products inventories. We believe that this level of
credit will provide us sufficient liquidity to operate our
business. We have committed capital available under our credit
facility up to $500 million that we can access for material acquisitions that
meet criteria specified in our credit agreement with the calculation of our
borrowing base using the higher multiple and an agreed-upon amount of pro forma
EBITDA associated with the acquisition.
DG Marine
had $46.9 million of loans outstanding under its $54 million credit
facility. As of December 31, 2009, DG Marine had completed and paid
for all amounts related to the capital expenditure projects related to the
expansion of its fleet.
During
2009, as refineries have reduced production capacity, demand for transportation
services of heavy-end fuel oils by inland barges has weakened, putting pressure
on the rates DG Marine can charge for its services. In response, DG Marine
amended its credit facility in November 2009 to (i) adjust the definition of
interest expense for purposes of the interest coverage ratio to exclude non-cash
interest expense and interest under the subordinated loan agreement between DG
Marine and Genesis; (ii) permit Genesis to guaranty up to $7.5 million of the
outstanding balance under the DG Marine credit facility; (iii) reduce the
maximum amount of the DG Marine credit facility from $90 million to $54 million
due to the completion of its fleet expansion projects; and (iv) to provide a
debt structure that would allow for additional credit support in certain
circumstances. At December 31, 2009, Genesis had loans outstanding to
DG Marine for the total amount available under a $25 million subordinated loan
agreement to DG Marine. The proceeds of the loan were used to reduce
the amount outstanding under the DG Marine credit facility. Additionally, at
December 31, 2009, Genesis had provided a $7.5 million guaranty to the lenders
under the DG Marine credit facility.
Uses
of Cash
Our cash
requirements include funding day-to-day operations, maintenance and expansion
capital projects, debt service, 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.
Cash Flows from Operations.
We utilize the cash flows we generate from our operations to fund our working
capital needs. Excess funds that are generated are used to repay
borrowings from our credit facilities and to fund capital
expenditures. Our operating cash flows can be impacted by changes in
items of working capital, primarily variances in the timing of payment of
accounts payable and accrued liabilities related to capital
expenditures.
Debt and Other Financing
Activities.
Our sources of cash are primarily from operations
and our credit facilities. Our net repayments under our credit
facility and the DG Marine credit facility totaled $8.4 million as we utilized
excess cash generated from operations to temporarily reduce debt
balances. We also paid the remaining $6.0 million of seller-financing
related to the acquisition from Grifco of the DG Marine assets. We
paid distributions totaling $60.1 million to our limited partners and our
general partner during 2009. See the details of distributions paid in
“Distributions” below.
Investing
. We
utilized cash flows for capital expenditures. The most significant
investing activities in 2009 were expenditures by DG Marine of $15.7 million for
additional barges and related costs. As of December 31, 2009, DG Marine had
twenty barges and ten push boats. DG Marine’s capital expenditures
were funded through cash that was generated from operations and by borrowings
under its credit facility and the Subordinated Loan Agreement with
Genesis.
We also
completed an expansion of our Jay System that extends the pipeline to producers
operating in southern Alabama. That expansion consisted of
approximately 33 miles of pipeline and gathering connections to approximately 35
wells and includes storage capacity of 20,000 barrels. Including the
acquisition of linefill in our supply and logistics segment, we expended $2.7
million on this project in 2009.
Other
improvements in our pipeline operations totaling $1.3 million included
improvements to segments of our Mississippi System. Capital
expenditures at our refinery services locations included upgrades to control
equipment and other site improvements.
In our
supply and logistics segment, we expended approximately $3.7 million to add tank
capacity for fuel oil at owned and leased locations. We also added
new field office infrastructure in Alabama and Mississippi at a cost of
approximately $0.5 million. Our expenditures are summarized in the
table below.
Capital
Expenditures, and Business and Asset Acquisitions
A summary
of our expenditures for fixed assets, businesses and other asset acquisitions in
the three years ended December 31, 2009, 2008, and 2007 is as
follows:
|
Years
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Capital
expenditures for property, plant and equipment:
|
||||||||||||
|
Maintenance
capital expenditures:
|
||||||||||||
|
Pipeline
transportation assets
|
1,281 | 719 | 2,880 | |||||||||
|
Supply
and logistics assets
|
1,667 | 729 | 440 | |||||||||
|
Refinery
services assets
|
1,246 | 1,881 | 469 | |||||||||
|
Administrative
and other assets
|
232 | 1,125 | 51 | |||||||||
|
Total
maintenance capital expenditures
|
4,426 | 4,454 | 3,840 | |||||||||
|
Growth
capital expenditures:
|
||||||||||||
|
Pipeline
transportation assets
|
1,762 | 7,589 | 3,712 | |||||||||
|
Supply
and logistics assets
|
19,099 | 22,659 | 650 | |||||||||
|
Refinery
services assets
|
1,326 | 3,609 | 979 | |||||||||
|
Total
growth capital expenditures
|
22,187 | 33,857 | 5,341 | |||||||||
|
Total
|
26,613 | 38,311 | 9,181 | |||||||||
|
Capital
expenditures for business combinations and asset
purchases:
|
||||||||||||
|
DG
Marine acquisition
|
$ | - | $ | 94,072 | $ | - | ||||||
|
Free
State Pipeline acquisition, including transaction costs
|
- | 76,193 | - | |||||||||
|
NEJD
Pipeline transaction, including transaction costs
|
- | 177,699 | - | |||||||||
|
Davison
acquisition
|
- | - | 631,476 | |||||||||
|
Port
Hudson acquisition
|
- | - | 8,103 | |||||||||
|
Acquisition
of intangible assets
|
2,500 | - | - | |||||||||
|
Total
|
2,500 | 347,964 | 639,579 | |||||||||
|
Capital
expenditures attributable to unconsolidated affiliates:
|
||||||||||||
|
Faustina
project
|
83 | 2,397 | 1,104 | |||||||||
|
Total
|
83 | 2,397 | 1,104 | |||||||||
|
Total
capital expenditures
|
$ | 29,196 | $ | 388,672 | $ | 649,864 | ||||||
During
2010, we expect to expend approximately $4.9 million for maintenance capital
projects in progress or planned. Those expenditures are expected to
include approximately $1.0 million of improvements in our refinery services
business, $0.7million in our crude oil pipeline operations, $1.5 million related
to improvements at our terminals and the remainder on projects related to our
truck transportation operations, including $0.6 million for replacement
vehicles. In future years we expect to spend $2 million to $3 million
per year on vehicle replacements.
We will
also upgrade and integrate our existing information technology systems during
2010 in order to be positioned for further growth. We anticipate that
we will expend approximately $9.0 million on this project during the
year.
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
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
eighteen quarters, including the distribution paid for the fourth quarter of
2009, as shown in the table below (in thousands, except per unit
amounts). Each quarter, the Board of Directors of our general partner
determines the distribution amount per unit based upon various factors such as
our operating performance, available cash, future cash requirements and the
economic environment. As a result, the historical trend of
distribution increases may not be a good indicator of future
increases.
|
Distribution For
|
Date Paid
|
Per
Unit Amount
|
Limited
Partner Interests Amount
|
General
Partner Interest Amount
|
General
Partner Incentive Distribution Amount
|
Total
Amount
|
||||||||||||||||
|
Fourth
quarter 2007
|
February
2008
|
$ | 0.2850 | $ | 10,902 | $ | 222 | $ | 245 | $ | 11,369 | |||||||||||
|
First
quarter 2008
|
May
2008
|
$ | 0.3000 | $ | 11,476 | $ | 234 | $ | 429 | $ | 12,139 | |||||||||||
|
Second
quarter 2008
|
August
2008
|
$ | 0.3150 | $ | 12,427 | $ | 254 | $ | 633 | $ | 13,314 | |||||||||||
|
Third
quarter 2008
|
November
2008
|
$ | 0.3225 | $ | 12,723 | $ | 260 | $ | 728 | $ | 13,711 | |||||||||||
|
Fourth
quarter 2008
|
February
2009
|
$ | 0.3300 | $ | 13,021 | $ | 266 | $ | 823 | $ | 14,110 | |||||||||||
|
First
quarter 2009
|
May
2009
|
$ | 0.3375 | $ | 13,317 | $ | 271 | $ | 1,125 | $ | 14,713 | |||||||||||
|
Second
quarter 2009
|
August
2009
|
$ | 0.3450 | $ | 13,621 | $ | 278 | $ | 1,427 | $ | 15,326 | |||||||||||
|
Third
quarter 2009
|
November
2009
|
$ | 0.3525 | $ | 13,918 | $ | 284 | $ | 1,729 | $ | 15,931 | |||||||||||
|
Fourth
quarter 2009
|
February
2010
(1)
|
$ | 0.3600 | $ | 14,251 | $ | 291 | $ | 2,037 | $ | 16,579 | |||||||||||
(1) This
distribution was paid on February 12, 2010 to our general partner and
unitholders of record as of February 5, 2010.
Our
credit facility also includes a restriction on the amount of distributions we
can pay in any quarter. At December 31, 2009, our restricted net
assets (as defined in Rule 4-03 (e)(3) of Regulation S-X) were $492.1
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.
Non-GAAP
Reconciliation
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 liquidity measure)
to cash flow from operating activities (the GAAP measure) for the year ended
December 31, 2009, is as follows (in thousands):
|
Year
Ended
|
||||
|
December 31,
2009
|
||||
|
Cash
flows from operating activities
|
$ | 90,079 | ||
|
Adjustments
to reconcile operating cash flows to Available Cash:
|
||||
|
Maintenance
capital expenditures
|
(4,426 | ) | ||
|
Proceeds
from sales of certain assets
|
873 | |||
|
Amortization
of credit facility issuance fees
|
(2,503 | ) | ||
|
Effects
of available cash generated by equity method investees not included in
cash flows from operating activities
|
101 | |||
|
Earnings
of DG Marine in excess of distributable cash
|
(4,475 | ) | ||
|
Other
items affecting available cash
|
1,768 | |||
|
Net
effect of changes in operating accounts not included in calculation of
Available Cash
|
9,569 | |||
|
Available
Cash before Reserves
|
$ | 90,986 | ||
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 and
petroleum products. The table below summarizes our obligations and
commitments at December 31, 2009.
|
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)
|
$ | - | $ | 366,900 | $ | - | $ | - | $ | 366,900 | ||||||||||
|
Estimated
interest payable on long-term debt
(2)
|
17,581 | 13,850 | - | - | 31,431 | |||||||||||||||
|
Operating
lease obligations
|
9,555 | 14,239 | 5,417 | 26,600 | 55,811 | |||||||||||||||
|
Unconditional
purchase obligations
(3)
|
80,490 | - | - | - | 80,490 | |||||||||||||||
|
Other
Cash Commitments:
|
||||||||||||||||||||
|
Asset
retirement obligations
(4)
|
- | - | - | 13,777 | 13,777 | |||||||||||||||
|
Liabilities
associated with unrecognized tax benefits and associated
interest
(5)
|
4,332 | - | - | - | 4,332 | |||||||||||||||
|
Total
|
$ | 111,958 | $ | 394,989 | $ | 5,417 | $ | 40,377 | $ | 552,741 | ||||||||||
|
(1)
|
Our
credit facility allows us to repay and re-borrow funds at any time through
the maturity date of November 15, 2011. The DG Marine credit
facility allows it to repay and re-borrow funds at any time through the
maturity date of July 18,
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, 2009 remained outstanding through the final
maturity dates of July 18, 2011 and November 15, 2011 and interest rates
remained at the December 31, 2009 market levels through the final maturity
dates.
|
|
(3)
|
Unconditional
purchase obligations include agreements to purchase goods and services
that are enforceable and legally binding and specify all significant
terms. Contracts to purchase crude oil and petroleum products
are generally at market-based prices. For purposes of this
table, estimated volumes and market prices at December 31, 2009, 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.
|
|
(4)
|
Represents
the estimated future asset retirement obligations on an undiscounted
basis. The present discounted asset retirement obligation is
$4.8 million and is further discussed in Note 6 to the Consolidated
Financial Statements.
|
|
(5)
|
The
estimated liabilities associated with unrecognized tax benefits
and related interest 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.
|
We have
guaranteed 50% of the $2.65 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.
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.
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 change as new events occur, as more experience is acquired,
as additional information is obtained and as the business environment in which
we operate changes. Significant accounting policies that we employ
are presented in the Notes to 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, equity plan
compensation accruals and contingent and environmental
liabilities. We discuss these policies below.
Fair
Value of Assets and Liabilities Acquired and Identification of Associated
Goodwill and Intangible Assets.
In
conjunction with each acquisition we make, we must allocate the cost of the
acquired entity to the assets and liabilities assumed based on their estimated
fair values at the date of acquisition. As additional information becomes
available, we may adjust the original estimates within a short time period
subsequent to the acquisition. In addition, we are required to recognize
intangible assets separately from goodwill. Determining the fair value of assets
and liabilities acquired, as well as intangible assets that relate to such items
as customer relationships, contracts, trade names, and non-compete agreements
involves professional judgment and is ultimately based on acquisition models and
management’s assessment of the value of the assets acquired, and to the extent
available, third party assessments. 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 Grifco acquisition in 2008 and
the Davison and Port Hudson acquisitions in 2007, we performed allocations of
the purchase price. See Note 3 of the Notes to the Consolidated
Financial Statements.
Depreciation
and Amortization of Long-Lived Assets and Intangibles
In order
to calculate depreciation and amortization we must estimate the useful lives of
our fixed assets at the time the assets are placed in service. We
compute depreciation using the straight-line method based on these estimated
useful lives. The actual period over which we will use the asset may differ from
the assumptions we have made about the estimated useful life. We
adjust the remaining useful life as we become aware of such
circumstances.
Intangible
assets with finite useful lives are required to be amortized over their
respective estimated useful lives. If an intangible asset has a
finite useful life, but the precise length of that life is not known, that
intangible asset shall be amortized over the best estimate of its useful
life. At a minimum, we will assess the useful lives and residual
values of all intangible assets on an annual basis to determine if adjustments
are required. We are recording amortization of our customer and
supplier relationships, licensing agreements and trade names based on the period
over which the asset is expected to contribute to our future cash
flows. Generally, the contribution of these assets to our cash flows
is expected to decline over time, such that greater value is attributable to the
periods shortly after the acquisition was made. Our favorable lease
and other intangible assets are being amortized on a straight-line basis over
their expected useful lives.
Impairment
of Long-Lived Assets including Intangibles and Goodwill
When
events or changes in circumstances indicate that the carrying amount of a fixed
asset or intangible asset may not be recoverable, we review our assets for
impairment. We compare the carrying value of the fixed asset to the estimated
undiscounted future cash flows expected to be generated from that
asset. Estimates of future net cash flows include estimating
future volumes, future margins or tariff rates, future operating costs and other
estimates and assumptions consistent with our business plans. If we
determine that an asset’s unamortized cost may not be recoverable due to
impairment; we may be required to reduce the carrying value and the subsequent
useful life of the asset. Any such write-down of the value and unfavorable
change in the useful life of an intangible asset would increase costs and
expenses at that time.
Goodwill
represents the excess of the purchase prices we paid for certain businesses over
their respective fair values and is primarily associated with the Davison
acquisition in 2007. We do not amortize goodwill; however, we test our goodwill
(at the reporting unit level) for impairment on October 1 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 impairment
test 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, (iii) appropriate discount
rates, and (iv) estimates of the cash flow multiples to apply in
estimating the market value of our reporting units. If the fair value of the
reporting unit (including its inherent goodwill) is less than its carrying
value, a charge to earnings is required to reduce the carrying value of goodwill
to its implied fair value. At December 31, 2009, the carrying value of our
goodwill was $325.0 million. We have not recorded any goodwill impairment
charges during any of the periods included in this annual report.
At
December 31, 2009, we estimated that the fair value of our supply and logistics
and refinery services reporting units exceeded the carrying value of each unit’s
net assets by approximately $50 million and $80 million,
respectively.
Due to
the recent disruptions in the credit markets and macroeconomic conditions, we
will continue to monitor the market to determine if a triggering event occurs
that would indicate that the fair value of a reporting unit is less than its
carrying value. If we determine that a triggering event has occurred,
we will perform an interim goodwill impairment analysis.
For
additional information regarding our goodwill, see Notes 3 and 10 of the Notes
to the Consolidated Financial Statements.
Asset
Retirement Obligations
With
regards to some of our assets, primarily related to our pipeline operations
segment, we 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 and to
decommission barges when we take them out of service. 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 6 of the Notes to our Consolidated Financial
Statements for further discussion regarding our asset retirement
obligations.
Equity
Compensation Plan Accruals
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 our SAR plan,
grantees receive cash for the difference between the market value of our common
units and the strike price of the award at the time of exercise. We
estimate the fair value of SAR awards at each balance sheet date using the
Black-Scholes option pricing model. The Black-Scholes valuation model requires
the input of somewhat subjective assumptions, including expected stock price
volatility and expected term. Other assumptions required for estimating fair
value with the Black-Scholes model are the expected risk-free interest rate and
our expected distribution yield. The risk-free interest rates used are the U.S.
Treasury yield for bonds matching the expected term of the option on the date of
grant. 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 equity-based compensation expense on a straight-line basis over
the requisite service period for the awards. The expense we recognize is net of
estimated forfeitures. We estimate our forfeiture rate at each balance sheet
date based on prior experience. As of December 31, 2009, there was $0.9 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 approximately one year. We also record compensation cost
for changes in the estimated liability for vested SARs. The liability
recorded for vested SARs fluctuates with the market price of our common
units. See Note 16 of the Notes to our Consolidated Financial
Statements for further discussion regarding our SAR plan.
For
phantom unit awards granted under our 2007 Long-Term Incentive Plan, the total
compensation expense recognized over the service period is determined by the
grant date fair value of our common units that become
earned. Uncertainties involved in the estimate of the compensation
cost we record for our phantom units relate to the assumptions regarding the
continued employment of personnel who have been awarded phantom
units. As a result of the change in control of our general partner in
February 2010 when Denbury sold its interest in our general partner to Quintana,
the outstanding phantom units at December 31, 2009 vested. We will
record $0.5 million of compensation expense in the first quarter of 2010 related
to this accelerated vesting.
On
December 31, 2008, our general partner completed compensation arrangements with
our senior executive team. See Item 11 – Executive Compensation - The
Class B Membership Interest in our General Partner. The Class B
Membership Interests awarded to our senior executives are accounted for as
liability awards under accounting guidance related to equity-based
compensation. As such, the fair value of the compensation cost
we record for these awards is recomputed at each measurement date and the
expense recorded is adjusted based on that fair value. Management’s
estimates of the fair value of these awards are based on assumptions regarding a
number of future events, including estimates of the Available Cash before
Reserves we will generate each quarter through the final vesting date of
December 31, 2012, estimates of the future amount of incentive distributions we
will pay to our general partner, and assumptions about appropriate discount
rates. Additionally the determination of fair value is affected by
the distribution yield of a group of publicly-traded entities that are the
general partners in publicly-traded master limited partnerships, a factor over
which we have no control. At December 31, 2009, management estimated
that the fair value of the Class B Membership Awards and the related deferred
compensation awards granted to our Senior Executives on that date was
approximately $30.5 million. Compensation expense of $3.4 million was
recorded in the fourth quarter of 2007 related to the previous arrangements
between our general partner and our Senior Executives. Compensation expense of
$14.1 million was recorded in 2009 related to these awards. This
expense related to the awards is recorded on an accelerated basis to align with
the requisite service period of the award. Changes in our assumptions
change the amount of compensation cost we record. Changes in these
assumptions do not, however, affect our Available Cash before Reserves, as the
cash cost of the Class B Membership Interests will be borne by
Denbury.
As a
result of the change in control of our general partner in February 2010 when
Denbury sold its interest in our general partner to Quintana, our senior
executives vested in the Class B Membership Awards. The ultimate
settlement value of these awards was approximately $15.4 million. As
a result we will record a reduction in the expense related to these awards in
the first quarter of 2010 of approximately $2.1 million.
Liability
and Contingency Accruals
We accrue
reserves for contingent liabilities including environmental remediation and
potential legal claims. When our assessment indicates that it is
probable that a liability has occurred and the amount of the liability can be
reasonably estimated, we make accruals. We base our estimates on all
known facts at the time and our assessment of the ultimate outcome, including
consultation with external experts and counsel. We revise these
estimates as additional information is obtained or resolution is
achieved.
We also
make estimates related to future payments for environmental costs to remediate
existing conditions attributable to past operations. Environmental
costs include costs for studies and testing as well as remediation and
restoration. We sometimes make these estimates with the assistance of
third parties involved in monitoring the remediation effort.
At
December 31, 2009, we are not aware of any contingencies or liabilities that
will have a material effect on our financial position, results of operations, or
cash flows.
Recent Accounting
Pronouncements
.
Implemented
in 2009
Accounting
Standards Codification
In June
2009, the Financial Accounting Standards Board (FASB) issued Statement of
Financial Accounting Standards No. 168, “The FASB Accounting Standards
Codification and the Hierarchy of Generally Accepted Accounting Principles – a
replacement of FASB Statement No. 162,” (The Codification). The
Codification establishes the FASB Accounting Standards Codification (ASC) as the
source of authoritative U.S. generally accepted accounting principles (GAAP)
recognized by the FASB to be applied by nongovernmental entities. The
Codification reorganizes GAAP pronouncements by topic and modifies the GAAP
hierarchy to include only two levels: authoritative and
non-authoritative. All of the content in the Codification carries the
same level of authority. This statement was effective for financial
statements issued for interim and annual periods ending after September 15,
2009. We adopted the Codification on September 30,
2009. Thus, subsequent references to GAAP in our Consolidated
Financial Statements will refer exclusively to the Codification.
Recognized
and Non-Recognized Subsequent Events
In May
2009, the FASB issued new guidance for accounting for subsequent
events. The new guidance establishes the accounting for and
disclosures of events that occur after the balance sheet date but before
financial statements are issued or are available to be issued. It
requires the disclosure of the date through which an entity has evaluated
subsequent events and the basis for that date, that is, whether that date
represents the date the financial statements were issued or were available to be
issued. See “Subsequent Events” included in “Note 1 – Organization”
for the related disclosure. The new guidance was applied prospectively beginning
in the second quarter of 2009 and did not have a material impact on our
Consolidated Financial Statements.
Disclosures
about Fair Value of Financial Instruments
In April
2009, the FASB issued new guidance regarding interim disclosures about the fair
value of financial instruments. The new guidance requires fair value
disclosures on an interim basis for financial instruments that are not reflected
in the Consolidated Balance Sheets at fair value. Previously, the fair values of
those financial instruments were only disclosed on an annual basis. We adopted
the new guidance for our quarter ended June 30, 2009, and there was no material
impact on our Consolidated Financial Statements.
Business
Combinations
In
December 2007, the FASB issued revised guidance for the accounting of business
combinations. The revised guidance retains the purchase method of
accounting used in business combinations but replaces superseded guidance 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 revised guidance requires disclosures to
enable users of the financial statements to evaluate the nature and financial
effects of the business combination. The revised guidance applies to
acquisitions we make after December 31, 2008. The impact to us will
be dependent on the nature of the business combination.
Noncontrolling
Interests in Consolidated Financial Statements
In
December 2007, the FASB issued guidance regarding noncontrolling interests in
consolidated financial statements. The new guidance establishes accounting and
reporting standards for noncontrolling interests, which were 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. The new guidance 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. The provisions of the new guidance were effective for
fiscal years beginning after December 15, 2008. On January 1, 2009,
we adopted the new guidance which changed the presentation of the interests in
Genesis Crude Oil, L.P. held by our general partner and the interests in DG
Marine held by our joint venture partner in our Consolidated Financial
Statements. Amounts for prior periods have been changed to be
consistent with the presentation required by the new guidance.
Derivative
Instruments and Hedging Activities
In
March 2008, the FASB issued new guidance regarding disclosures about derivative
instruments and hedging activities. The new guidance requires enhanced
disclosures about our derivative and hedging activities. This guidance was
effective for financial statements issued for fiscal years and interim periods
beginning after November 15, 2008. We adopted the guidance on January 1, 2009
and have included the enhanced disclosures in Note 18.
Application
of the Two-Class Method to Master Limited Partnerships
In March
2008, the FASB issued new guidance regarding the application of the two-class
method to Master Limited Partnerships. Under this guidance, the
computation of earnings per unit will be affected by the incentive distribution
rights (“IDRs”) we are contractually obligated to distribute at the end of the
each reporting period. In periods when earnings are in excess of cash
distributions, we will reduce net income or loss for the current reporting
period (for purposes of calculating earnings or loss per unit only) by the
amount of available cash that will be distributed to our limited partners and
general partner for its general partner interest and incentive distribution
rights for the reporting period, and the remainder will be allocated to the
limited partner and general partner in accordance with their ownership
interests. When cash distributions exceed current-period earnings,
net income or loss (for purposes of calculating earnings or loss per unit only)
will be reduced (or increased) by cash distributions, and the resulting excess
of distributions over earnings will be allocated to the general partner and
limited partner based on their respective sharing of losses. The new
guidance was effective for fiscal years beginning after December 15, 2008, and
interim periods within those fiscal years. We adopted this guidance
on January 1, 2009 and have reflected the calculation of earnings per unit for
the year ended December 31, 2009, 2008 and 2007 in accordance with its
provisions. See Note 12 of the Notes to the Consolidated Financial
Statements.
Measuring
Liabilities and Fair Value
In August
2009, the FASB issued guidance that provides clarification to the valuation
techniques required to measure the fair value of liabilities. The guidance also
provides clarification around required inputs to the fair value measurement of a
liability and definition of a Level 1 liability. The guidance was effective for
interim and annual periods beginning after August 2009. We adopted this standard
beginning with our financial statements for the year ended December 31, 2009.
The adoption of this standard did not have a material effect on our financial
statements.
Implemented
January 1, 2010
Consolidation
of Variable Interest Entities (“VIEs”)
In June
2009, the FASB issued authoritative guidance to amend the manner in which
entities evaluate whether consolidation is required for VIEs. The
model for determining which enterprise has a controlling financial interest and
is the primary beneficiary of a VIE has changed significantly under the new
guidance. Previously, variable interest holders had to determine
whether they had a controlling interest in a VIE based on a quantitative
analysis of the expected gains and/or losses of the entity. In
contrast, the new guidance requires an enterprise with a variable interest in a
VIE to qualitatively assess whether it has a controlling interest in the entity,
and if so, whether it is the primary beneficiary. Furthermore, this
guidance requires that companies continually evaluate VIEs for consolidation,
rather than assessing based upon the occurrence of triggering
events. This revised guidance also requires enhanced disclosures
about how a company’s involvement with a VIE affects its financial statements
and exposure to risks. This guidance was effective for us beginning
January 1, 2010. We are currently assessing the impact this guidance
may have on our consolidated financial statements.
It
em 7a. Quantitative and Qualitative Disclosures
About Market Risk
We are
exposed to various market risks, primarily related to volatility in crude oil
and petroleum products prices, NaHS and NaOH prices, and interest rates. Our
policy is to purchase only commodity products for which we have a market, and to
structure our sales contracts so that price fluctuations for those products do
not materially affect the segment margin we receive. We do not
acquire and hold futures contracts or other derivative products for the purpose
of speculating on price changes.
Our
primary price risk relates to the effect of crude oil and petroleum products
price fluctuations on our inventories and the fluctuations each month in grade
and location differentials and their effect on future contractual
commitments. Our risk management policies are designed to monitor our
physical volumes, grades, and delivery schedules to ensure our hedging
activities address the market risks that are inherent in our gathering and
marketing activities.
We
utilize NYMEX commodity based futures contracts and option contracts to hedge
our exposure to these market price fluctuations as needed. All of our
open commodity price risk derivatives at December 31, 2009 were categorized as
non-trading. On December 31, 2009, we had entered into NYMEX future contracts
that will settle between February 2010 and August 2010 and NYMEX options
contracts that will settle during February and March 2010. This
accounting treatment is discussed further in Note 18 to our Consolidated
Financial Statements.
The table
below presents information about our open derivative contracts at December 31,
2009. 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, 2009 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)
|
451 | 111 | ||||||
|
Weighted
average price per bbl
|
$ | 78.18 | $ | 77.93 | ||||
|
Contract
value (in thousands)
|
$ | 35,257 | 8,650 | |||||
|
Mark-to-market
change (in thousands)
|
735 | 202 | ||||||
|
Market
settlement value (in thousands)
|
$ | 35,992 | $ | 8,852 | ||||
|
Heating
Oil:
|
||||||||
|
Contract
volumes (1,000 bbls)
|
94 | 43 | ||||||
|
Weighted
average price per gal
|
$ | 1.92 | $ | 2.04 | ||||
|
Contract
value (in thousands)
|
$ | 7,591 | 3,688 | |||||
|
Mark-to-market
change (in thousands)
|
766 | 133 | ||||||
|
Market
settlement value (in thousands)
|
$ | 8,357 | $ | 3,821 | ||||
|
RBOB
Gasoline:
|
||||||||
|
Contract
volumes (1,000 bbls)
|
14 | |||||||
|
Weighted
average price per gal
|
$ | 1.91 | ||||||
|
Contract
value (in thousands)
|
$ | 1,121 | ||||||
|
Mark-to-market
change (in thousands)
|
86 | |||||||
|
Market
settlement value (in thousands)
|
$ | 1,207 | $ | - | ||||
|
#6
Fuel Oil:
|
||||||||
|
Contract
volumes (1,000 bbls)
|
75 | |||||||
|
Weighted
average price per bbl
|
$ | 68.06 | ||||||
|
Contract
value (in thousands)
|
$ | 5,105 | ||||||
|
Mark-to-market
change (in thousands)
|
326 | |||||||
|
Market
settlement value (in thousands)
|
$ | 5,431 | $ | - | ||||
|
NYMEX Option Contracts:
|
||||||||
|
Crude
Oil- Written Calls
|
||||||||
|
Contract
volumes (1,000 bbls)
|
73 | |||||||
|
Weighted
average premium received/paid
|
$ | 2.79 | ||||||
|
Contract
value (in thousands)
|
$ | 204 | ||||||
|
Mark-to-market
change (in thousands)
|
135 | |||||||
|
Market
settlement value (in thousands)
|
$ | 339 | $ | - | ||||
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 and the DG Marine credit facility. Our debt bears interest
at the LIBOR Rate or Prime Rate, at our option, plus the applicable
margin. We have not, historically hedged our interest
rates. On December 31, 2009, we had $320.0 million of debt
outstanding under our credit facility and $46.9 million outstanding under the DG
Marine credit facility. DG Marine hedged a portion of its debt
through July 2011.
It
em 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 99.
It
em 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure
None.
It
em 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 assurance of the timely
recording, processing, summarizing and reporting of information, and in
accumulation and communication to management on a timely basis material
information relating to us (including our consolidated subsidiaries) required to
be disclosed in this annual report.
There
were no changes during our last fiscal quarter that materially affected, or are
reasonably likely to materially affect, our internal control over financial
reporting.
Management’s
Report on Internal Control over Financial Reporting
Management
of the Partnership is responsible for establishing and maintaining effective
internal control over financial reporting as defined in Rules 13a-15(f) under
the Securities Exchange Act of 1934. The Partnership’s internal
control over financial reporting is designed to provide reasonable assurance to
the Partnership’s management and board of directors regarding the preparation
and fair presentation of published financial statements.
Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation
of effectiveness to future periods are subject to the risk that controls may
become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
Management
assessed the effectiveness of the Partnership’s internal control over financial
reporting as of December 31, 2009. 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, 2009, 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, 2009. 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, LLC 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, 2009, based on criteria
established in
Internal
Control — Integrated Framework
issued by the Committee of Sponsoring
Organizations of the Treadway Commission. The Partnership’s
management is responsible for 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, 2009, 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, 2009 of
the Partnership and our report dated February 24, 2010 expressed an unqualified
opinion on those financial statements and financial statement
schedule.
/s/ DELOITTE
& TOUCHE LLP
Houston,
Texas
February
24, 2010
It
em 9B. Other Information
None.
It
em 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. 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 5, 2010
our general partner has eleven directors. Quintana has the right to designate
and appoint six members to the board of directors of our general partner, at
least two of which designees must be independent. On February 5,
2010, Quintana appointed four members to the board of directors. The
Quintana appointees are Robert C. Sturdivant, Donald L. Evans, Corbin J.
Robertson III and William K. Robertson. The members of the Davison
family have the right to designate and appoint up to three directors, one of
whom must be independent, as long as members of the Davison family hold at least
75% of the interest in our general partner that they acquired on February 5,
2010 (the “Effective Date”). If members of the Davison family hold
less than 75% but more than 50% of the ownership interest in our general partner
that they held on the Effective Date, they have the right to appoint two
directors and if they hold less than 50%, they have the right appoint one
director. The members of the Davison family designated and appointed
James E. Davison and James E. Davison, Jr. to continue to serve as directors of
our general partner. They waived their right to appoint a third
director until a position on the board of directors is
available. Another investor in our general partner, EIV Capital Fund
LP, which has the right to designate one director of our general partner as long
as it holds at least 75% of the ownership interest in our general partner that
its held as of the Effective Date, also waived its right to appoint a director
until a position on the board of directors is available. Mr. Sims
will remain as one of our directors so long as he remains or chief executive
officer. Susan O. Rheney, Martin G. White, J. Conley Stone and David C. Baggett
continued as directors of our general partner after the change in control on
February 5. 2010.
The
independence standards established by the NYSE Amex LLC (formerly the American
Stock Exchange) require us to have at least three independent directors on the
Board. NYSE Amex LLC does not require a listed limited partnership
like us to have a majority of independent directors on the Board of our general
partner or to establish a compensation committee or a nominating
committee. Although we currently have a compensation committee, it
does not satisfy the independence standards established by NYSE Amex LLC, 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
Martin G. White and Susan O. Rheney, both of whom are non-employee directors of
our general partner. The Compensation Committee adopted a written
Compensation Committee charter that is available on our website.
In
addition, our general partner has an audit committee composed of directors who
meet the independence and experience standards established by NYSE Amex LLC and
the Securities Exchange Act of 1934, as amended. Susan O. Rheney,
David C. Baggett and Martin G. White serve as the members of the audit
committee. The audit committee assists the board in its oversight of
the quality and integrity of our financial statements and our compliance with
legal and regulatory requirements and partnership policies and controls. The
audit committee has the following responsibilities:
|
|
·
|
has
the sole authority to retain and terminate our independent registered
public accounting firm, approve all auditing services and related fees and
the terms thereof, and pre-approve any non-audit services to be rendered
by our independent registered public accounting
firm;
|
|
|
·
|
is
responsible for confirming the independence and objectivity of our
independent registered public accounting
firm;
|
|
|
·
|
can
help us resolve conflicts of interest;
and
|
|
|
·
|
oversees
our anonymous complaint procedure established for our
employees.
|
Our
independent registered public accounting firm is given unrestricted access to
the audit committee. The Board believes that Susan O. Rheney
qualifies as an audit committee financial expert as such term is used in the
rules and regulations of the SEC. The audit committee adopted a
written Audit Committee Charter in August 2003. The full text of the
Audit Committee Charter is available on our website.
In
addition, the members of our Audit Committee may review specific matters that
the board believes may involve conflicts of interest. When requested
to by our general partner, the audit committee determines if the resolution of
the conflict of interest is fair and reasonable to us. The members of the audit
committee may not be officers or employees of our general partner or directors,
officers, or employees of its affiliates, and must meet the independence and
experience standards established by the NYSE Amex LLC 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
|
||
|
Robert
C. Sturdivant
|
64
|
Director
and Chairman of the Board
|
||
|
Grant
E. Sims
|
54
|
Director
and Chief Executive Officer
|
||
|
David
C. Baggett
|
48
|
Director
|
||
|
James
E. Davison
|
72
|
Director
|
||
|
James
E. Davison, Jr.
|
43
|
Director
|
||
|
Donald
L. Evans
|
63
|
Director
|
||
|
Susan
O. Rheney
|
50
|
Director
|
||
|
Corbin
J. Robertson III
|
39
|
Director
|
||
|
William
K. Robertson
|
34
|
Director
|
||
|
J.
Conley Stone
|
78
|
Director
|
||
|
Martin
G. White
|
64
|
Director
|
||
|
Robert
V. Deere
|
55
|
Chief
Financial Officer
|
||
|
Steven
R. Nathanson
|
54
|
President,
Refinery Services Division
|
||
|
Ross
A. Benavides
|
56
|
Senior
Vice President, General Counsel and Secretary
|
||
|
Karen
N. Pape
|
51
|
Senior
Vice President and Controller
|
Robert C.
Sturdivant was named a director of our general partner by Quintana on February
5, 2010. Mr. Sturdivant currently serves as Vice President – Finance
and Managing Director – Risk Management of certain Quintana affiliates, and has
served in various roles with Quintana and its affiliates since
1974. Mr. Sturdivant represents Quintana’s interests as a director on
the boards of several private entities.
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.
David C.
Baggett has served as a director of our general partner since March
2008. Mr. Baggett is the founder and managing partner of Opportune
LLP, a financial consulting firm formed in June 2005. From April 2003
until June 2005 he was a private investor. From October 1998 until
April 2003, he held various positions at American Plumbing and Mechanical,
including President, Chief Operating Officer, Chief Financial Officer and board
member.
James E.
Davison
has served
as a director of our general partner since July 2007. Mr. Davison served as
chairman of the board of Davison Transport, Inc. for over 30 years. He also
serves as President of Terminal Storage, Inc. Mr. Davison has over forty years
experience in the energy-related transportation and refinery services
businesses.
James E.
Davison, Jr
.
has served
as a director of our general partner since July 2007. Mr. Davison is also a
director of Community Trust Bank and serves on its executive, audit, finance and
compensation committees. Mr. Davison is the son of James E.
Davison.
Donald L.
Evans was named a director of our general partner on February 5, 2010, by
Quintana. Mr. Evans has served as President of The Don Evans
Group, Ltd. since 2005 and served as the 34th Secretary of the U.S. Department
of Commerce from 2001 to 2005. Since 2007, Mr. Evans has also served
as the non-executive chairman of the board of directors of Energy Future
Holdings Corp., a provider of electricity and related services.
Susan O.
Rheney has served as a director of our general partner since March
2002. Ms. Rheney is a private investor and formerly was a principal
of The Sterling Group, L.P., a private financial and investment organization,
from 1992 to 2000. Ms. Rheney serves on the board of directors, audit
committee and finance committee of CenterPoint Energy, Inc., an energy delivery
company headquartered in Texas.
Corbin J.
Robertson III was named a director of our general partner on February 5, 2010,
by Quintana. Mr. Robertson has served as Managing Director, Coal and
Downstream for Quintana since 2006, and is a principal in that
organization. Prior to joining Quintana, Mr. Robertson was a Managing
Director of Spring Street Partners, a hedge fund focused on undervalued small
cap securities, a position he held from 2002 to 2007. Prior to joining Spring
Street, Mr. Robertson worked for three years as a Vice President of Sandefer
Capital Partners LLC, a private investment partnership focused on energy related
investments, and two years as a management consultant for Deloitte and Touche
LLP.
William
K. Robertson was named a director our general partner by Quintana on February 5,
2010. Mr. Robertson has served as a Managing Director for Quintana
since 2005, Managing Director, Midstream and Power since 2008 and is a principal
in that organization. Prior to joining Quintana, Mr. Robertson worked
in private investments with The CapStreet Group, LLC, and prior to that in the
energy and power investment banking department of Merrill, Lynch, Pierce, Fenner
& Smith Inc. Mr. Robertson is the brother of Corbin J. Robertson
III.
J. Conley
Stone has served as a director of our general partner since January
1997. From 1987 to his retirement in 1995, he served as President,
Chief Executive Officer, Chief Operating Officer and Director of Plantation Pipe
Line Company, a common carrier liquid petroleum products pipeline
transporter.
Martin G.
White has served as a director of our general partner since March
2008. Mr. White retired in 2006 from Occidental Chemical Corporation
(OxyChem) after most recently serving as Vice President of OxyChem’s joint
venture, OxyVinyls, a position he held since the formation of OxyVinyls in May
1999.
Robert V.
Deere has served as Chief Financial Officer of our general partner since October
2008. Mr. Deere served as Vice President, Accounting and Reporting at
Royal Dutch Shell (Shell) from 2003 through 2008, and in positions of increasing
responsibility with Shell for five years prior to that appointment.
Steven
R. Nathanson became an executive officer of our general partner in February
2010, and has served as President of our refinery services subsidiary, TDC,
L.L.C. since 2002.
Ross A.
Benavides has served as General Counsel and Secretary of our general partner
since December 1999. He previously also held the position of Chief
Financial Officer from October 1998 until October 2008.
Karen N.
Pape has served as Senior Vice President and Controller of our general partner
since July 2007, and served as Vice President and Controller from May 2002 until
July 2007. Ms. Pape served as Controller and as Director of Finance
and Administration of our general partner from 1996 to 2002.
Code
of Ethics
We have
adopted a code of ethics that is applicable to, among others, the principal
financial officer and the principal accounting officer. The Genesis
Energy Financial Employee Code of Professional Conduct is posted at our website,
where we intend to report any changes or waivers.
Section
16(a) Beneficial Ownership Reporting Compliance
Section
16(a) of the Securities Exchange Act of 1934 requires the officers and directors
of our general partner and persons who own more than ten percent of a registered
class of our equity securities to file reports of ownership and changes in
ownership with the SEC and the NYSE Amex LLC. Based solely on our
review of the copies of such reports received by us, or written representations
from certain reporting persons to us, we are aware of no filings that were not
timely made.
It
em 11. Executive Compensation
We are
managed by our general partner, who employs our executive officers and
employees. Under the terms of our partnership agreement, we are
required to reimburse our general partner for expenses relating to managing our
operations, including salaries and bonuses of employees employed on our behalf,
as well as the costs of providing benefits to such persons under employee
benefit plans and for the costs of health and life insurance. Our
general partner agreed that it would not seek reimbursement for compensation
pursuant to the Class B Membership Interest Awards and deferred compensation
awards discussed below. See "Certain Relationships and Related
Transactions."
The
Compensation Discussion and Analysis below discusses our compensation process,
objectives and philosophy through December 31, 2009, as determined by the
compensation committee of our Board. Among other things, it is
designed to provide a fair understanding of the compensation to our named
executive officers, or NEOs, for 2009. On February 5, 2010, Quintana
acquired a controlling interest in our general partner from
Denbury. At that time, three Denbury officers resigned from our Board
and Quintana appointed four new directors. In connection with that
change in control, the directors appointed by the Quintana-Controlled Owner
Group authorized, as was their prerogative, certain actions, including issuing
specified Series B unit awards to certain key employees, amending certain
employment agreements and terminating our president. Those actions,
each of which is described in more detail in the last paragraph of this Item 11
entitled “Compensation Changes Subsequent to December 31, 2009”, are not covered
by the Compensation Discussion and Analysis report below. As of the
date of this report, our general partner has not changed its compensation
process, objectives or philosophies, although the reconstituted Board has the
right to do so at any time, without notice.
Compensation
Discussion and Analysis
Compensation
Committee.
During 2009, the compensation committee of our
Board, or the Committee, consisted of the chairman of the board of directors and
two independent directors. The Committee is responsible for making
recommendations to the Board regarding compensation policies, incentive
compensation policies and employee benefit plans, and recommends awards
thereunder. The Committee recommends specific compensation levels for
our named executive officers, or NEOs. The Committee also administers our Stock
Appreciation Rights Plan, 2007 Long-Term Incentive Plan, Bonus Plan, and
Severance Protection Plan. Our Board has adopted a Compensation Committee
Charter setting forth the Committee’s purpose and responsibilities.
Board Process
.
Following
the end of the year, management reviews the compensation of all employees of our
general partner, and, based on their review, the results of the Partnership as a
whole, and the internal recommendations of supervisory personnel, makes a
proposal to the Committee. Final review of this recommendation is
made by the Committee and the Board in the first quarter. Depending
on the magnitude of the anticipated changes, there may also be additional
Committee meetings and discussions with management in advance of that
meeting.
Committee and Board
Approval.
The Committee approves compensation and long-term
awards for executive officers, taking into consideration the recommendation of
the Senior Executives (defined below) with regard to compensation for the Other
Executives (defined below). The Committee also reviews and approves
our overall compensation programs for all employees, taking into consideration
the recommendation of management described above, and any significant changes to
these programs. The Committee administers all of our compensation
plans (other than our 401(k) plan, health and other fringe benefit plans),
including our Bonus Plan, 2007 Long-Term Incentive Compensation Plan, and Stock
Appreciation Rights Plan, under which all of our long-term equity awards are
granted. The Board considers, reviews and ratifies the compensation
package based on a recommendation from the Committee. Following
approval of the entire compensation program in the first quarter of each year,
any applicable salary increases and/or long-term incentive are made or
awarded. Bonuses are paid in March.
Executive
Officers
. Our NEOs are Grant E. Sims, our chief executive
officer, Robert V. Deere, our chief financial officer, Ross A. Benavides, our
senior vice president and general counsel, Karen N. Pape, our senior vice
president and controller, and our former president and chief operating officer,
Joseph A. Blount, Jr. Messrs. Sims, Blount and Deere are referred to in this
annual report as our Senior Executives and Mr. Benavides and Ms. Pape are
referred to as our Other Executives.
Compensation
Objectives and Philosophy
. Our compensation programs are
designed by the Committee to attract, retain, and motivate key personnel who
possess the skills and qualities necessary to perform effectively in an MLP in
the industries in which we operate. We pay base salaries at a level
that we feel are appropriate for the skills and qualities of the individual
employees based on their past performance and current responsibilities with the
Partnership. The other components of employees’ compensation are
consistent among employee groups and generally are proportional to base
salary. We reward employees primarily for the effort and results of
the Partnership as a whole, the results of the business segment, and for
individual performance.
On
December 31, 2008, we finalized the compensation arrangements (including
underlying documentation) for our Senior Executives. These
arrangements were designed to incentivize our Senior Executives to create value
for our common unitholders by maintaining and increasing (over time) the
distribution rate we pay on our common units.
As
described in more detail below, we believe that the combination of base
salaries, cash bonuses, Long-Term Incentive Plans and the Class B Membership
Interests provided an appropriate balance of short-term and long-term
incentives, cash and non-cash based compensation, and an alignment of the
incentives for our executives and employees with the interests of our common
unitholders and Denbury, the owner of the majority of our general
partner. Our Bonus Plan is driven by the generation of available
cash, which is an important metric of value for our unitholders, before reserves
and bonuses, and our safety record. Our Stock Appreciation Rights
Plan and 2007 Long Term Incentive Plan are linked primarily to the appreciation
in our common unit price. The Class B Membership Interests had the
potential to provide participation in our incentive distribution rights to our
Senior Executives, as well as redemption of those rights in specified
circumstances, including most events involving their termination of employment
and a change in control of our general partner. The level of
participation by our Senior Executives in the Class B Membership Interests was
largely driven by the generation of available cash as well as the level of
distributions we pay to our common unitholders and general partner.
Components
of our Compensation Program. Two distinct compensation programs apply
to our employees. The first applies to our Senior Executives, the
second applies to our Other Executives and to certain other
employees. The elements of the compensation program for our Senior
Executives consist of:
|
|
·
|
base
salaries,
|
|
|
·
|
an
ability to earn a increasing share of the cash distributions attributable
to the incentive distribution rights (IDRs) held by our general partner,
referred to as the Class B Membership Interests below,
and
|
|
|
·
|
other
compensation (including reimbursement for certain self-employment taxes
and other costs borne by the executive as a result of their status as
members of our general partner).
|
The
elements of our Company-wide compensation program that applies to the Other
Executives and to certain other employees (excluding the Senior Executives)
consist of:
|
|
·
|
base
salaries,
|
|
|
·
|
annual
cash bonuses (performance-based cash incentive
compensation),
|
|
|
·
|
a
Stock Appreciation Rights Plan (however additional awards to our Other
Executives ceased in 2009),
|
|
|
·
|
our
2007 Long Term Incentive Plans (phantom units and distribution equivalent
rights),
|
|
|
·
|
a
Severance Protection Plan, and
|
|
|
·
|
other
compensation (including contributions to the 401(k) plan and annual term
life insurance premiums).
|
The Other
Executives’ compensation programs are generally available to other members of
our management team.
Base
Salaries.
Senior
Executives
. During 2009, each of our Senior Executives,
Messrs. Sims, Blount and Deere, had an employment agreement with our general
partner under which he will receive an annual salary of $340,000, $300,000, and
$369,600, respectively, subject to certain upward adjustments. The
employment agreements provide that each senior executive’s annual salary rate
will be increased by (i) $30,000 if our market capitalization is at least $1.0
billion for any 90-consecutive-day period, and (ii) an additional amount equal
to 10% of his then effective base salary each time our market capitalization
increases by an additional $300 million. See additional disclosure in
the Employment Agreements section below.
Other
Executives.
The Committee seeks to establish and maintain base
salaries for our Other Executives at a competitive level based on several
factors. These factors include our objectives, the nature and
responsibility of the position (considering our size and complexity), the
expertise of the individual executive, and the recommendation of the Senior
Executives. In making recommendations, the Committee exercises
subjective judgment using no specific weights for these factors. Base
salaries are the primary part of the compensation package whereby a distinction
is made for individual performance of the Other Executives.
For 2009,
the Other Executives, Mr. Benavides and Ms. Pape, received a
salary increase of three percent to a base salary of $234,300, and a salary
increase of thirteen percent to a base salary of $225,000,
respectively. For 2009, all employees other than the Senior
Executives and Other Executives received average salary increases of
approximately three percent.
The
Class B Membership Interest in Our General Partner.
Senior
Executives.
As part of finalizing the compensation
arrangements for our Senior Executives in December 2008, our general partner
awarded them an equity interest in our general partner as long-term incentive
compensation. These Class B Membership Interests compensated the holders thereof
by providing rewards based on increased shares of the cash distributions
attributable to our incentive distribution rights (or IDRs) to the extent we
increase Cash Available Before Reserves, or CABR (defined below) (from which we
pay distributions on our common units) above specified
targets. CABR generally means Available Cash before Reserves,
as defined in Item 7 – “Management’s Discussion and Analysis” above, less
Available Cash before Reserves generated from specific transactions with our
general partner and its affiliates (including Denbury Resources Inc.) The Class
B Membership Interests did not provide any Senior Executive with a direct
interest in any assets (including our IDRs) owned by our general
partner.
These
arrangements were intended to incentivize our Senior Executives to create value
for our common unitholders and general partner by maintaining and increasing
(over time) the distribution rate to them. Each holder of a Class B
Membership Interest is entitled (a) to receive from our general partner
quarterly cash distributions in an amount equal to a varying percentage of the
incentive distributions we make to our general partner, and (b) upon the
occurrence of specified events and circumstances, to receive from our general
partner a payment of cash (or, in certain circumstances, common units owned by
our general partner) in redemption of such Class B Membership
Interests.
In
accordance with its terms, our Class B Membership Interest was redeemed in
connection with the change in control of our general partner. The
following discussion provides additional details regarding our Class B
Membership Interest, which remained outstanding until its redemption on February
5, 2010. See additional discussion below in “Compensation Changes
Subsequent to December 31, 2009”.
Our Board
made the following awards of Class B Membership Interests:
|
Senior
Executive
|
Class
B Membership Interest Percentage
|
Potential
IDR Percentage
|
||||||
|
Grant
E. Sims
|
38.7 | % | 7.74 | % | ||||
|
Joseph
A. Blount, Jr.
|
33.3 | 6.66 | ||||||
|
Robert
V. Deere
|
14.0 | 2.80 | ||||||
|
Total
Awarded
|
86.0 | % | 17.20 | % | ||||
Our
general partner was not obligated to award the remaining 14.0% of the unissued
Class B Membership Interests.
The
potential IDR percentage was subject to the effects of vesting and future levels
of available cash and distributions to our common unitholders and general
partner, as discussed below, in determining the portion of the general partner’s
IDRs distributable to them.
The
amount of the quarterly cash distribution, a Class B Membership Interest holder
was entitled to receive from our general partner varied depending on the amount
of cash we distributed in respect of our IDRs and the amount by which the growth
in Cash Available before Reserves, or CABR, per common unit for an annual period
ending with the current quarter exceeded specified base levels. CABR
generally means Available Cash before Reserves, as defined in Item 7 –
“Management’s Discussion and Analysis” above, less Available Cash before
Reserves generated from specific transactions with our general partner and
related Denbury affiliates. In other words, all other things being
equal, if our Available Cash before Reserves increased on a per unit basis
(other than from specific transactions with our general partner and its
affiliates) above specified base levels and our distribution rate on our common
units increased above specified thresholds such that our incentive distributions
to our general partner increased, each Senior Executive would have been entitled
to receive distributions from our general partner that constituted a larger
share of our general partner’s IDR distributions.
Each
holder was entitled to receive a quarterly distribution in an amount equal to
the product of (i) the IDR distributions made by us to our general partner and
attributable to the applicable quarter, (ii) that Senior Executive’s Class B
Membership Interest percentage and (iii) the percentage associated with the
growth in CABR per common unit actually achieved for an annual period ending
with the current quarter over specified base levels. The CABR per
unit base levels, as well as the related target percentages, are set forth
below. Based on the CABR per unit for the quarterly periods in 2009, the
percentages associated with our CABR per unit ranged from 10% to 14% for Messrs.
Sims and Blount and zero for Mr. Deere. For purposes of determining
the applicable base percentage for a relevant quarter, Messrs. Sims’ and
Blount’s base levels per unit were $0.925, and Mr. Deere’s base level per unit
was $1.975.
Our
Senior Executives received the following distributions from our general partner
during 2009 with respect to the quarters indicated:
|
Senior
Executive
|
Fourth
Quarter 2008 Distribution Amount
|
First
Quarter 2009 Distribution Amount
|
Second
Quarter 2009 Distribution Amount
|
Third
Quarter 2009 Distribution Amount
|
Total
2009 Distribution Amount
|
|||||||||||||||
|
Grant
E. Sims
|
$ | 44,595 | $ | 60,944 | $ | 55,241 | $ | 66,930 | $ | 227,710 | ||||||||||
|
Joseph
A. Blount, Jr.
|
38,373 | 52,440 | 47,533 | 57,591 | 195,937 | |||||||||||||||
|
Robert
V. Deere
|
- | - | - | - | - | |||||||||||||||
|
Total
|
$ | 82,968 | $ | 113,384 | $ | 102,774 | $ | 124,521 | $ | 423,647 | ||||||||||
As an
example, the distributions in the table above with respect to the third quarter
of 2009 were calculated as follows (in thousands, except per unit
amounts):
|
Total
|
||||
|
Available
Cash before Reserves generated for the four quarters
|
$ | 91,525 | ||
|
Less: Adjustment
to Available Cash before Reserves relating to specific transactions with
our general partner and its affiliates
|
22,902 | |||
|
CABR
for the four quarters
|
$ | 68,623 | ||
|
Weighted
average units outstanding, including implied general partner units
(1)
|
39,102 | |||
|
Adjusted
CABR at September 30, 2009 per adjusted unit
(2)
|
$ | 1.755 | ||
|
Base
amount for Messrs. Sims and Blount
|
0.925 | |||
|
Excess
of CABR per Unit over base amount
|
$ | 0.830 | ||
|
Applicable
Percentage for Messrs. Sims and Blount for the quarter
|
10 | % | ||
(1) Adjusted
units outstanding is calculated separately for each quarter in the annual period
and applied to the CABR for the respective quarter. The calculation
excludes common units issued to our general partner and its affiliates resulting
from any transaction between us and our general partner and its affiliates after
March 31, 2008.
(2) This
amount represents the sum of the individual quarterly calculations in the annual
period.
The
distribution that Mr. Sims received for the quarter was calculated as the
product of (i) $1,729,474 (which is the amount of IDR distributions
attributable to that quarter that we actually paid to our general
partner), (ii) the CABR-related percentage of 10%, and (iii) Mr. Sims
Class B Membership Interest of 38.7%. The calculation of Mr. Blount’s
distribution amount was similar to that of Mr. Sims utilizing his Class B
Membership Interest of 33.3%. Mr. Deere was not entitled to a
distribution for the quarter because the adjusted CABR per adjusted unit did not
exceed his base amount of $1.975.
In
addition, our general partner agreed to redeem each Senior Executive’s equity
interest for cash (or, in specified circumstances, for common units owned by our
general partner) in certain circumstances including most events involving
termination of that Senior Executive’s employment with our general partner or
when a change of control occurs. The amount of the redemption payment
depended on the nature of the triggering event (i.e. termination with or without
cause or good reason or due to death, disability or a change of control) and/or
the time at which the triggering event occurred. In general, each Senior
Executive was be entitled to receive a redemption amount if our general partner
did not terminate his employment for cause, which redemption amount was subject
to vesting as described below.
The
redemption amount for each executive was an amount equal to the vested portion
of the excess, if any, of (a) the then current value of the general partner’s
future IDRs multiplied by the product of (i) the relevant member’s Class B
Membership Interest percentage and (ii) his then effective CABR-related
percentage over (b) $1,007,229 for Mr. Sims, $866,685 for Mr. Blount, and zero
for Mr. Deere. The determined value of our IDRs was the present value
of the annualized cash flows attributable to the IDRs at the time of the
triggering event discounted at an annual interest rate equal to the average of
the annualized yield of a group of specified publicly-traded entities which are
general partners of publicly traded master limited partnerships. The
vesting percentage of each executive was the percentage, in general, determined
as of the relevant valuation date, indicated below:
|
(i)
|
termination for cause: |
0%
|
|||
|
(ii)
|
after a change of control; upon such Class B Member’s termination for good reason; or upon a termination during the period beginning six months prior to and ending on a change of control other than termination by our general partner for cause or termination by the Class B Member without good reason: |
100%
|
|||
|
(iii)
|
if the Class B Member voluntarily terminates his employment other than for good reason, if termination occurs: | ||||
|
(a)
|
prior
to the 1
st
anniversary of the Class B Member’s award:
|
0%
|
|||
|
(b)
|
on
or after the 1
st
anniversary, and prior to the 2
nd
anniversary, of the Class B Member’s award:
|
25%
|
|||
|
(c)
|
on
or after the 2
nd
anniversary, and prior to the 3
rd
anniversary, of the Class B Member’s award:
|
50%
|
|||
|
(d)
|
on
or after the 3
rd
anniversary, and prior to the 4
th
anniversary, of the Class B Member’s award:
|
75%
|
|||
|
(e)
|
after
the 4
th
anniversary of the Class B Member’s award:
|
100%
|
On
December 31, 2009, the redemption amount for each Class B Member was
25%.
Our
general partner agreed that it would not seek reimbursement (on behalf of itself
or its affiliates) under our partnership agreement for the costs of these Senior
Executive compensation arrangements to the extent relating to their ownership of
Class B Membership Interests (including current cash distributions and
redemption payments made by our general partner in respect thereof) and the
deferred compensation amounts. Our general partner was reimbursed for
the costs of these Senior Executive compensation arrangements to the extent
relating to the employment agreements (including base salary and fringe
benefits) and cash bonuses, if any, which costs will be borne by
us.
Although
our general partner will not seek reimbursement for the costs of the Class B
Membership Interests and deferred compensation plan arrangements, we recorded
non-cash expense during 2009. The Class B Membership Interests
awarded to our senior executives were accounted for as liability awards under
accounting guidance for equity-based compensation. As such, the fair
value of the compensation cost we recorded for these awards was recomputed at
each measurement date and the expense we recorded was adjusted based on that
fair value. Management’s estimates of the fair value of these awards
were based on assumptions regarding a number of future events, including
estimates of the Available Cash before Reserves we would generate each quarter
through the final vesting date of December 31, 2012, estimates of the future
amount of incentive distributions we would pay to our general partner, and
assumptions about appropriate discount rates. Additionally the
determination of fair value was affected by the distribution yield of a group of
publicly-traded entities that are the general partners in publicly-traded master
limited partnerships, a factor over which we have no control. At
December 31, 2009, management estimated that the fair value of the Class B
Membership Awards and the related deferred compensation awards granted to our
Senior Executives on that date was approximately $30.5 million. During 2009,
compensation expense of $14.1 million was recorded related to these
awards.
As a
result of the change in control of our general partner on February 5, 2010, the
Class B Membership Interests were redeemed. See additional discussion below in
“Executive Compensation – Change in Control and Other Termination Payments” and
Note 23 to the Consolidated Financial Statements.
Other
Executives.
Only our Senior Executives may hold Class B
Membership Interests.
Bonuses
and Deferred Compensation Awards.
Senior
Executives.
Our general partner adopted an unfunded,
nonqualified deferred compensation plan and made awards under that plan to
Messrs. Sims and Blount in a maximum amount of $1,007,229 and $866,685,
respectively. These awards were paid on February 5, 2010 and the plan
was terminated, in connection with the change in control of our general
partner. See Note 23 of the Notes to the Consolidated Financial
Statements.
Bonus Plan for Other
Executives and other employees.
In January 2009, the Committee
of the Board of our general partner approved a bonus program, referred to below
as the “Bonus Plan,” for all employees of our general partner that is applicable
to 2009. The Senior Executives were excluded from participation in
the Bonus Plan in 2009. The Bonus Plan is paid at the discretion of
our Board based on the recommendation of the Committee, and can be amended or
changed at any time. Since the determination of whether bonuses will
be paid each year and in what amounts is determined by the Committee on a
company-wide basis, the Other Executives only receive bonuses if other employees
receive bonuses.
The Bonus
Plan is based primarily on the amount of money we generate for distributions to
our unitholders, and is measured on a calendar-year basis. For 2009,
two metrics are used to determine the general bonus pool – the level of
Available Cash before Reserves (before subtracting bonus expense and related
employer tax burdens) that we generate and our company-wide safety record
improvement. The level of Available Cash before Reserves generated for the year
as a percentage of a target set by our Committee is weighted ninety percent and
the achieved level of the targeted improvement in our safety record is weighted
ten percent. The sum of the weighted percentage achievement of these
targets is multiplied by the eligible compensation and the target percentages
established by our Committee for the various levels of our employees to
determine the maximum general bonus pool.
The
general bonus pool will be distributed as follows:
|
|
·
|
Each
eligible employee will be eligible to receive a bonus after the end of the
year up to a specified percentage of their eligible earnings under the
plan. Certain compensation, such as awards under our Stock
Appreciation Rights plan, car allowances and relocation expenses, will be
excluded from the calculation. Each employee must be a regular,
full-time active employee, not on probation, at the time the bonus is paid
in order to be eligible to receive a bonus. The date of payment
of the bonuses is at the discretion of management, but is expected to be
before March 15 each year.
|
|
|
·
|
There
are five levels of participation in the Bonus Plan. Employees in each
level will be eligible for a bonus each year in accordance with the
following table. The determination of what level applies to
each employee will be made by the Committee based on the recommendation of
the Senior Executives.
|
|
|
·
|
The
percentage of adjusted eligible earnings paid as a bonus will be a
function of the general bonus pool available and the employee’s
Participation Level in the Bonus Plan. The bonus amount each
employee will be eligible to receive will be determined in accordance with
the table shown below. The bonus may be adjusted up or down to
reflect business unit contribution and individual
performance. These adjustments are discretionary and will be
determined by the Senior Executives with approval by the
Committee.
|
|
Bonus
Targets
|
Job
Classifications
|
|
0 -
10%
|
Operations
and administrative clerical personnel
|
|
0 -
20%
|
Professional/supervisory
personnel
|
|
0 -
25%
|
Senior
professionals/management personnel
|
|
0 -
50%
|
Senior
management/executive personnel
|
|
0 -
100%
|
Key
executive personnel, including the Other
Executives
|
A
separate marketing bonus pool is available for compensating certain marketing
personnel that is based on the contribution of that group to Available Cash
before Reserves. A minimum level of contribution to Available Cash
before Reserves is required before any amounts are allocated to the marketing
bonus pool. Our Other Executives do not participate in this
pool.
The Bonus
Plan is designed to enhance our financial performance by rewarding employees for
achieving financial performance and safety objectives. Since
Available Cash before Reserves is an important factor in determining the amount
of distributions to our unitholders and is a significant factor in the market’s
perception of the value of common units of an MLP, we believe the Bonus Plan is
designed to reward employees on a basis that is aligned with the interests of
the unitholders. We believe that this generates a bonus that
represents a meaningful level of compensation for the employee population and
that encourages employees to operate as a unified team to generate results that
are aligned with the interests of the unitholders. By including
safety improvement in the calculation of the Bonus Pool, we encourage our
employees to focus on the impact their job performance has on the environment in
which we operate.
For 2009,
the Committee established a target of approximately $92 million for Available
Cash before Reserves and before bonus expense and related employer tax burdens
and subject to certain other adjustments, with a hurdle rate of
105%. We achieved 88% of the target for 2009. We achieved
our safety incident rate goal for 2009. As a result, the Bonus Pool
for 2009 bonuses to be paid in March 2010 was calculated as 90% of 88% divided
by 105%, or 79%. In accordance with the Bonus Plan, the total pool available for
bonuses for 2009 was approximately $4.3 million. Management intends
to recommend to the Committee that a total of $3.9 million be paid as bonuses
for 2009, which represents approximately thirteen percent of total eligible
compensation. The bonus recommendations for
2009 will be reviewed by the Committee in March 2010.
Long-Term
Incentive Compensation and Stock Appreciation Rights.
The 2007 Long-Term Incentive
Compensation Plan (2007 LTIP)
.
Senior
Executives
. Our Senior Executives are not eligible and do not
participate in our 2007 LTIP.
Non-Employee Directors,
Other Executives and other Employees.
Our unitholders approved
a Long-Term Incentive Plan on December 18, 2007 which provides for awards of
Phantom Units and Distribution Equivalent Rights to our non-employee directors
and employees. Phantom units are notional units representing unfunded
and unsecured promises to deliver a common unit to the participant should
specified vesting requirements be met. Distribution Equivalent Rights
are rights to receive an amount of cash equal to all or a portion of the cash
distributions made by us during a specified period. The 2007 LTIP is
administered by the Committee. Subject to adjustment as provided in
the 2007 LTIP, awards with respect to up to an aggregate of 1,000,000 units may
be granted under the 2007 LTIP.
The 2007
LTIP is intended to provide a means whereby employees and directors providing
services to us may develop a sense of proprietorship and personal involvement in
our development and financial success through the award of phantom units, and/or
distribution equivalent rights; and the 2007 LTIP allows for various forms of
equity or equity-based awards, providing flexible incentives to employees and
directors.
The
Committee (at its discretion) will designate participants in the 2007 LTIP,
determine the types of awards to grant to participants, determine the number of
units to be covered by any award, and determine the conditions and terms of any
award including vesting, settlement and forfeiture conditions. The
2007 LTIP may be amended or terminated at any time by the Board or the
Committee; however, any material amendment, such as a material increase in the
number of units available under the 2007 LTIP or a change in the types of awards
available under the 2007 LTIP, will also require the approval of our
unitholders. The Committee is also authorized to make adjustments to
the terms and conditions of and the criteria included in awards under the plan
in specified circumstances. The 2007 LTIP is effective until December
18, 2017 or, if earlier, the time which all available units under the 2007 LTIP
have been delivered to participants or the time of termination of the plan by
the Board or the Committee.
In
February 2009, the Committee approved awards granting phantom units with a total
value (assuming a market price of $13 per common unit) as of February 26, 2009
of $0.6 million (47,601 phantom units) to 17 employees of our general
partner. Grants were made to Mr. Benavides and Ms. Pape with values
in amounts of $113,800 (8,750 phantom units) and $100,000 (7,692 phantom units)
respectively, or approximately 50 percent of their base salaries. The
amounts awarded were entirely discretionary and were based on the recommendation
of the Senior Executives to the Committee.
Additionally,
the Committee awarded each non-employee director an award of 3,500 phantom units
on February 26, 2009.
As a
result of the change in control of our general partner, all outstanding phantom
units vested on February 5, 2010. See Note 23 of the Notes to the
Consolidated Financial Statements.
Stock Appreciation Rights
Plan.
Other Executives and
employees.
In December 2003, the Board approved a Stock
Appreciation Rights plan or SAR plan. Under the terms of this plan,
regular, full-time active employees and the members of the Board, excluding the
Senior Executives, are eligible to participate in the plan. The plan
is administered by the Committee, which determines, in its full discretion, the
number of rights to award, the grant date of the rights and the formula for
allocating rights to the participants and the strike price of the rights
awarded.
Beginning
in 2009, rights were awarded to our professional/supervisory personnel, senior
professional/managerial personnel and senior management/executive
personnel. Our Senior Executives and key executive personnel,
including our Other Executives, as well as our directors, do not receive awards
under the Stock Appreciation Rights plan nor do our operations and
administrative clerical personnel.
In
February 2009, awards of rights were made totaling 500,983
units. Prior to 2009, the exercise price of the annual awards of
rights had been the average of the closing market price of our units for the ten
days prior to the date of the grant. This methodology has been used
by the Committee for annual grants so that the exercise price is not unduly
influenced by trading of our units on one particular date. The volume
of units that trade each day is frequently small, such that one or a few small
trades can have a significant influence on the price. Additionally,
we may see unusual trading occur in the late months of the year at prices that
do not necessarily correspond to the latest market prices. For 2009,
we adjusted the exercise price to $13.00 (rather than $10.69 which was the
result of the prior method of determining the exercise price) to reflect a more
accurate representation of the unit value in the market environment existing at
the award date. This methodology is subject to change for any grant
in the future. Additional details describing the operation of the SAR
plan are included below.
Other Compensation and
Benefits.
Severance
Benefits
. We believe that companies should provide reasonable
severance benefits to employees. With respect to our Other
Executives, these severance benefits should reflect the fact that it may be
difficult for employees to find comparable employment within a short period of
time. Although we typically pay severance when we terminate any
employee unless such termination is for “cause”, we do not have any pre-defined
severance benefits for our Other Executives, except in the case of a change in
control, a plan adopted in June 2005. This plan is described
under “Change of Control” below.
Other Benefits.
Each
Senior Executive is entitled to vacation, medical and health coverage, and
similar fringe benefits received by the Other Executives provided, however, that
none of our Senior Executives will be eligible to participate in our general
partner’s Stock Appreciation Rights Plan, Severance Protection Plan, or 2007
Long-Term Incentive Plan. Our Senior Executives and Other Executives
participate in our benefit plans on the same terms as our other
employees. These plans include medical, dental, disability and life
insurance, and matching and profit-sharing contributions to our 401(k)
plan. We match up to 100 percent of the first three percent that the
participant contributes to the 401(k) plan and 50 percent of the next three
percent contributed. Additionally, we make a contribution to our
401(k) plan in the amount of three percent as a profit-sharing contribution to
our 401(k) for each eligible employee. As reflected in the Summary
Compensation Table, the cost to Genesis of the 401(k) matching contributions and
profit-sharing contributions and term life premiums aggregated $73,626 in 2009
for our Senior Executives and Other Executives. As a result of their
status as Class B Members in our general partner, our Senior Executives were
reimbursed for the additional benefit costs and taxes they paid or will owe
individually related to certain benefits they receive from us including medical,
dental, disability and life insurance, and matching and profit-sharing
contributions to our 401(k) plan, as well as self-employment
taxes. These reimbursements in 2009 totaled $43,554, $45,224 and
$44,366 for Messrs. Sims, Blount and Deere, respectively.
Our only
retirement benefits are our 401(k) plan and a retirement vesting provision
included in our Stock Appreciation Rights Plan. We do not have any pension plans
or post-retirement medical benefits.
Compensation
Committee Report
The
information contained in this report shall not be deemed to be soliciting
material or filed with the SEC or subject to the liabilities of Section 18 of
the Exchange Act, except to the extent that we specifically incorporate it by
reference into a document filed under the Securities Act of the Exchange
Act.
The
Compensation Committee has reviewed and discussed with management the
Compensation Discussion and Analysis included above. Based on the
review and discussions, the Compensation Committee approved that the
Compensation Discussion and Analysis be included in this Form 10-K.
This
report is submitted by the Compensation Committee.
Susan O.
Rheney
Martin G.
White
Executive
Compensation
2009
SUMMARY COMPENSATION TABLE
The
following table summarizes certain information regarding the compensation paid
or accrued by Genesis during 2009 to those persons who served as NEOs at the end
of 2009.
|
2009
Summary Compensation Table
|
||||||||||||||||||||||||||||||
|
Name
& Principal Position
|
Year
|
Salary
($)
|
Bonus
(1) ($)
|
Stock
Awards (2) ($)
|
Option
Awards (3) ($)
|
Non-Equity
Incentive Plan Compen- sation (4) ($)
|
All
Other Compen- sation (5) ($)
|
Total
($)
|
||||||||||||||||||||||
|
Grant
E. Sims
|
2009
|
340,000 | - | 7,267,894 | - | - | 50,904 | 7,658,798 | ||||||||||||||||||||||
|
Chief
Executive Officer
|
2008
|
310,000 | 107,751 | - | - | - | 9,834 | 427,585 | ||||||||||||||||||||||
|
(Principal
Executive Officer)
|
2007
|
310,000 | - | - | - | - | 1,838,476 | 2,148,476 | ||||||||||||||||||||||
|
Joseph A. Blount, Jr.
(6)
|
2009
|
300,000 | - | 6,240,141 | - | - | 63,599 | 6,603,740 | ||||||||||||||||||||||
|
Former
President & Chief
|
2008
|
270,000 | 97,599 | - | - | - | 19,936 | 387,535 | ||||||||||||||||||||||
|
Operating
Officer
|
2007
|
270,000 | - | - | - | - | 1,618,984 | 1,888,984 | ||||||||||||||||||||||
|
Robert V. Deere
(7)
|
2009
|
369,600 | - | 596,165 | - | - | 51,716 | 1,017,481 | ||||||||||||||||||||||
|
Chief
Financial Officer
|
2008
|
89,557 | - | - | - | - | 621 | 90,178 | ||||||||||||||||||||||
|
(Principal
Financial Officer)
|
||||||||||||||||||||||||||||||
|
Ross
A. Benavides
|
2009
|
234,000 | - | 102,120 | 186,611 | - | 20,313 | 543,044 | ||||||||||||||||||||||
|
Senior
Vice President and
|
2008
|
227,500 | 170,000 | 65,638 | (215,195 | ) | - | 19,584 | 267,527 | |||||||||||||||||||||
|
General
Counsel
|
2007
|
211,000 | 68,250 | 2,511 | 100,448 | 111,581 | 16,680 | 510,470 | ||||||||||||||||||||||
|
Karen
N. Pape
|
2009
|
225,000 | - | 90,416 | 143,924 | - | 20,238 | 479,578 | ||||||||||||||||||||||
|
Senior
Vice President &
|
2008
|
200,000 | 180,000 | 58,341 | (164,728 | ) | - | 19,356 | 292,969 | |||||||||||||||||||||
|
Controller
|
2007
|
184,000 | 52,500 | 2,232 | 77,139 | 94,577 | 16,680 | 427,128 | ||||||||||||||||||||||
|
(PrincipalAccounting
Officer)
|
||||||||||||||||||||||||||||||
|
|
(1)
|
Amounts
in this column for Mr. Sims and Mr. Blount represent the amount that was
paid as a bonus at the time of execution of their employment
agreements. Amounts in this column for Mr. Benavides and Ms.
Pape for 2008 represent bonuses paid in March 2009 relative to 2008 under
our bonus program that was effective for 2009 and 2008. Amounts
in this column for Mr. Benavides and Ms. Pape in 2007 represent the amount
that was paid as a retention bonus in September 2007. Bonuses
for 2009 will not be determined until March
2010.
|
|
|
(2)
|
Amounts
in this column for Messrs. Sims, Blount and Deere represent the expense
related to the Class B Membership Interests and deferred compensation that
are included in the determination of net income for the period under the
accounting guidance for equity-based compensation. Amounts in
this column for Mr. Benavides and Ms. Pape represent the amounts, before
consideration of expected forfeiture rate, that are included in the
determination of net income for the period under accounting guidance for
awards of phantom units under our 2007 LTIP. The forfeiture
rate that was applied to these awards at December 31, 2009, 2008 and 2007
was zero. See additional information on the assumptions
utilized in the valuation of these awards under accounting guidance in
Note 16 to the Consolidated Financial
Statements.
|
|
|
(3)
|
Amounts
in this column represent the amounts, before consideration of expected
forfeiture rate, that are included in the determination of net income for
each period under accounting guidance for awards under our Stock
Appreciation Rights plan. The forfeiture rate that was applied
to these amounts in each year was 10%. Because of the decline
in our common unit market price and the effects of that decline on the
fair value of outstanding stock appreciation rights, we recorded a
reduction in the liability for these awards in 2008. These
reductions are reflected as negative amounts in the table
above. See additional information on the assumptions utilized
in the valuation of these awards under accounting guidance in Note 16 to
the Consolidated Financial
Statements.
|
|
|
(4)
|
Amounts
in this column represent the amount paid to the Named Executive Officer as
an award under the bonus plan that was effective in
2007. Messrs. Sims and Blount did participate in the bonus plan
in 2007.
|
|
|
(5)
|
Information
on the amounts included in this column is included in the table
below.
|
|
|
(6)
|
Mr.
Sims and Mr. Blount were employed by our general partner effective August
6, 2006. Mr. Blount terminated effective February 10,
2010.
|
|
|
(7)
|
Mr.
Deere was employed by our general partner effective October 6,
2008.
|
|
Name
|
Year
|
401(k)
Matching Contributions (a)
|
401(k)
Profit-Sharing Contributions (b)
|
Insurance
Premiums (c)
|
Other
Compensation (d)
|
Totals
|
||||||||||||||||
|
Grant
E. Sims
|
2009
|
$ | - | $ | 7,350 | $ | - | $ | 43,554 | $ | 50,904 | |||||||||||
|
2008
|
$ | - | $ | 7,350 | $ | 2,484 | $ | - | $ | 9,834 | ||||||||||||
|
2007
|
$ | - | $ | 6,600 | $ | 180 | $ | 1,831,696 | $ | 1,838,476 | ||||||||||||
|
Joseph
A. Blount, Jr.
|
2009
|
$ | 11,025 | $ | 7,350 | $ | - | $ | 45,224 | $ | 63,599 | |||||||||||
|
2008
|
$ | 10,350 | $ | 7,350 | $ | 2,236 | $ | - | $ | 19,936 | ||||||||||||
|
2007
|
$ | 9,900 | $ | 6,600 | $ | 180 | $ | 1,602,304 | $ | 1,618,984 | ||||||||||||
|
Robert
V. Deere
|
2009
|
$ | - | $ | 7,350 | $ | - | $ | 44,366 | $ | 51,716 | |||||||||||
|
2008
|
$ | - | $ | - | $ | 621 | $ | - | $ | 621 | ||||||||||||
|
Ross
A. Benavides
|
2009
|
$ | 11,025 | $ | 7,350 | $ | 1,938 | $ | - | $ | 20,313 | |||||||||||
|
2008
|
$ | 10,350 | $ | 7,350 | $ | 1,884 | $ | - | $ | 19,584 | ||||||||||||
|
2007
|
$ | 9,900 | $ | 6,600 | $ | 180 | $ | - | $ | 16,680 | ||||||||||||
|
Karen
N. Pape
|
2009
|
$ | 11,025 | $ | 7,350 | $ | 1,863 | $ | - | $ | 20,238 | |||||||||||
|
2008
|
$ | 10,350 | $ | 7,350 | $ | 1,656 | $ | - | $ | 19,356 | ||||||||||||
|
2007
|
$ | 9,900 | $ | 6,600 | $ | 180 | $ | - | $ | 16,680 | ||||||||||||
Amounts
in this table represent:
|
|
(a)
|
Matching
contributions by Genesis to our 401(k) plan on each NEO’s
behalf.
|
|
|
(b)
|
Profit-sharing
contributions by Genesis to our 401(k) plan on each NEO’s
behalf.
|
|
|
(c)
|
Term
life insurance premiums paid by Genesis on each NEO’s
behalf.
|
|
|
(d)
|
For
2009, amount represents reimbursement for estimate of additional benefit
costs and taxes of NEO related to his status as a Class B Membership in
our general partner. For 2007, amount represents an amount for
the estimated value of the compensation earned in 2007 under the proposed
arrangements between the Senior Executive and our general partner that
existed at that time.
|
Employment
Agreements.
On
December 31, 2008, each of our Senior Executives, Messrs. Sims, Blount and
Deere, entered into an employment agreement with our general partner under which
he would receive an annual salary of $340,000, $300,000, and $369,600,
respectively, subject to certain upward adjustments. The agreements
provided that each senior executive’s annual salary rate would be increased by
(i) $30,000 if our market capitalization is at least $1.0 billion for any
90-consecutive-day period, and (ii) an additional amount equal to 10% of his
then effective base salary each time our market capitalization increases by an
additional $300 million.
Under his
employment agreement, each Senior Executive would be entitled to specified
severance benefits under certain circumstances. No Senior Executive
would be entitled to severance benefits if our general partner terminates him
for cause. Each Senior Executive (or family) would be entitled to
continued health benefits for 18 months after his termination and to the payment
of his base salary through December 31, 2012 if he dies, if he is terminated due
to a disability or if he terminates his employment for good
reason. If our general partner terminates a Senior Executive (other
than for cause) within two years after a change of control, he would be entitled
to continued health benefits for 18 months after his termination and to the
payment of his base salary through the later of December 31, 2012 or three years
from his date of termination.
Each
employment agreement contains customary non-solicitation and non-competition
provisions that prohibit our Senior Executives from competing with us after
termination, including working for, supervising, assisting, or participating in
any competing business (as defined in the employment agreements) in
any capacity in the states of Louisiana, Mississippi, and Texas during the term
of the employment agreement and for a period of two years after
termination if the employment agreement is terminated for cause or without good
reason, and for a period of one year after termination if the employment
agreement is terminated other than by our general partner for cause or by the
Senior Executive without good reason
Change in Control and Other
Termination Payments
.
Senior
Executives. Based upon a hypothetical termination date of December
31, 2009, the change in control termination benefits for our Senior Executives
would have been as follows:
| Grant E. | Joseph A. | Robert V. | ||||||||||
|
Sims
|
Blount,
Jr.
|
Deere
|
||||||||||
|
Severance
payment pursuant to employment agreement
|
$ | 1,020,000 | $ | 900,000 | $ | 1,108,800 | ||||||
|
Healthcare
and other insurance benefits
|
17,434 | 20,416 | 20,495 | |||||||||
|
Class
B Membership Interest and deferred compensation
(1)
|
6,587,831 | 5,668,599 | 2,383,195 | |||||||||
|
Total
|
$ | 7,625,265 | $ | 6,589,015 | $ | 3,512,490 | ||||||
|
|
(1)
|
Upon
termination due to a change in control, each Senior Executive was entitled
to his deferred compensation amount, if any, and redemption of his Class B
Membership Interest. Such payment would be paid no later than
sixty days after our general partner receives its distribution payment
from us for the quarter ended September 30, 2010, and would have been
based on the IDR payment for such quarter. Additionally each
Senior Executive would have been entitled to continue to receive a share
of the quarterly IDR payment our general partner receives from us through
the quarter ended September 30, 2010. These amounts were
computed assuming that each Senior Executive’s CABR-related percentage was
no less than 16%, utilizing the same management assumptions that were used
to determine the fair value of the awards at December 31, 2009
. Additionally our estimate of the redemption of the Class B
Membership Interests assumes that the distribution yield of a group of
publicly-traded entities that are the general partners in publicly-traded
master limited partnerships will be the same as the average at December
31, 2009.
|
Based
upon a hypothetical termination date of December 31, 2009, the termination
benefits for our Senior Executives for voluntary termination or termination for
cause would be zero. Based upon a hypothetical termination date of
December 31, 2009, the termination benefits for our Senior Executives for
termination without cause or for good reason, including death or disability
would have been:
|
Grant
E.
|
Joseph
A.
|
Robert
V.
|
||||||||||
|
Sims
|
Blount,
Jr.
|
Deere
|
||||||||||
|
Severance
payment pursuant to employment agreement
|
$ | 1,020,000 | $ | 900,000 | $ | 1,108,800 | ||||||
|
Healthcare
and other insurance benefits
|
17,434 | 20,416 | 20,495 | |||||||||
|
Class
B Membership Interest and deferred compensation
(1)
|
5,718,314 | 4,920,410 | - | |||||||||
|
Total
|
$ | 6,755,748 | $ | 5,840,826 | $ | 1,129,295 | ||||||
|
|
(1)
|
As
with a termination for a change in control, termination without cause or
for good reason would have entitled each Senior Executive to his deferred
compensation amount, if any, and redemption of his Class B Membership
Interest. The termination payment would be paid no later than
sixty days after our general partner receives its distribution payment
from us for the quarter ended September 30, 2010, and would have been
based on the IDR payment for such quarter. Additionally each
Senior Executive would have been entitled to continue to receive a share
of the quarterly IDR payment our general partner receives from us through
the quarter ended September 30, 2010. The difference from a
termination for a change in control is that these amounts would have been
computed utilizing each Senior Executive’s CABR-related percentage at the
date of termination. The amounts in this table were calculated
similarly to the amounts for a change in control, except the CABR-related
percentages were 10% for Messrs. Sims and Blount and zero for Mr. Deere at
December 31, 2009.
|
Our
general partner was required to redeem the individual Class B Membership
Interests under our general partner’s existing limited liability company
agreement as a result of the change of control effected by the sale of our
general partner to the Quintana-Controlled Owner Group. Our senior
executives and Denbury agreed to amend our general partner’s existing limited
liability company agreement to provide for the conversion of the Class B
Membership Interests into Series A units in the general partner at the time of
the change in control, rather than for the redemption of the Class B Membership
Interests upon a change of control, and/or to confirm the amount each executive
would receive upon redemption. Pursuant to a Class B Agreement dated
February 5, 2010 among Mr. Sims, Denbury, and our general partner, a portion of
Mr. Sims’ individual Class B Membership Interest in our general partner was
converted into Series A units in our general partner following the change in
control and his remaining Class B Membership Interest was redeemed for $221,868
in cash. Mr. Deere also entered into a Class B Agreement dated
February 5, 2010 pursuant to which a portion of his individual Class B
Membership Interest was converted into Series A units in our general partner
following the change in control and his remaining Class B Membership Interest
was redeemed for $431,684 in cash. Mr. Blount received a payment for
his Class B Membership Interest totaling $4.9 million.
Other
Executives. Based upon a hypothetical termination date of December 31, 2009, the
change in control termination benefits for our Other Executives would have been
as follows (based on the closing price for our units of $18.90 at that
time):
|
Ross
A.
|
Karen
N.
|
|||||||
|
Benavides
|
Pape
|
|||||||
|
Severance
plan payment
|
$ | 1,059,375 | $ | 1,023,750 | ||||
|
Healthcare
and other insurance benefits
|
14,480 | 14,311 | ||||||
|
Fair
market value of stock appreciation rights
|
177,418 | 135,702 | ||||||
|
Fair
market value of phantom units
|
338,801 | 299,527 | ||||||
|
Total
|
$ | 1,590,074 | $ | 1,473,290 | ||||
It is our
belief that the interests of unitholders will best be served if the interests of
our Other Executives are aligned with theirs. Providing change of
control benefits should eliminate, or at least reduce, the reluctance of
management to pursue potential change of control transactions that may be in the
best interests of our unitholders.
We have
two benefits for our employees and Other Executives in the event of a change of
control: (i) our cash Severance Protection Plan, and (ii) vesting of
SARs. Under the terms of our Severance Protection Plan, an employee
is entitled to receive a severance payment if a change of control occurs and the
employee is terminated within two years of that change (i.e. a “double trigger”
award). The Severance Protection Plan will not apply to any employee
who is terminated for cause or by an employee’s own decision for other than good
reason (e.g., material change of job status or a required move of more than 25
miles). If entitled to severance payments under the terms of the
Severance Protection Plan, Mr. Benavides and Ms. Pape will receive three times
the sum of their annual salary and the average of their bonus amounts in the
last twenty-four months, certain other members of management will receive two
times the sum of their annual salary and the average of their bonus amounts in
the last twenty-four months, and all other employees will receive between
one-third to one and one-half times the sum of their annual salary and the
average of their bonus amounts in the last twenty-four months depending upon
their salary level and length of service with us. All employees will
also receive medical and dental reimbursement benefits for one-half the number
of months for which they receive severance benefits.
A change
in control is defined in the Severance Protection Plan. Generally, a
change in control is a change in the control of Denbury, a disposition by
Denbury of more than 50% of our general partner, or a transaction involving the
disposition of substantially all of our assets. The sale by Denbury
of our general partner was a change in control under the Severance Protection
Plan.
The
Severance Protection Plan also provides that if our Other Executives are subject
to the “parachute payment” excise tax under IRC Section 4999, then we will pay
the employee under the severance plan an additional amount to “gross up” the
severance payment so that the employee will receive the full amount due under
the terms of the severance plan after payment of the excise tax.
If a
participant in our SAR Plan is terminated within one year of a change in
control, all SARs would immediately vest.
Other
Compensation
Long
Term Incentive Plan
As
discussed in the Compensation Discussion and Analysis, our unitholders approved
the Genesis Energy, Inc. 2007 Long Term Incentive Plan, or 2007 LTIP, on
December 18, 2007 which provides for awards of Phantom Units and Distribution
Equivalent Rights to non-employee directors and employees of Genesis Energy,
LLC, our general partner. Phantom Units are notional units
representing unfunded and unsecured promises to deliver a common unit to the
participant should specified vesting requirements be
met. Distribution Equivalent Rights are rights to receive an amount
of cash equal to all or a portion of the cash distributions made by us during a
specified period. The 2007 LTIP will be administered by the
Committee. Subject to adjustment as provided in the 2007 LTIP, awards
with respect to up to an aggregate of 1,000,000 units may be granted under the
2007 LTIP.
The
Committee (at its discretion) will designate participants in the 2007 LTIP,
determine the types of awards to grant to participants, determine the number of
units to be covered by any award, and determine the conditions and terms of any
award including vesting, settlement and forfeiture conditions. The
2007 LTIP may be amended or terminated at any time by the Board or the
Committee; however, any material amendment, such as a material increase in the
number of units available under the 2007 LTIP or a change in the types of awards
available under the 2007 LTIP, will also require the approval of our
unitholders. The Committee is also authorized to make adjustments in
the terms and conditions of and the criteria included in awards under the plan
in specified circumstances. The 2007 LTIP is effective until December
18, 2017 or, if earlier, the time which all available units under the 2007 LTIP
have been delivered to participants or the time of termination of the plan by
the Board or the Committee.
Stock
Appreciation Rights Plan
As
discussed in the Compensation Discussion and Analysis, we have a Stock
Appreciation Rights plan, or SAR, for our employees. Our Senior
Executives do not participate in this plan and, beginning in 2009, our Other
Executives, certain key employees and the Board will no longer receive awards
under this plan. Under the terms of this plan, certain employees are
eligible to participate in the plan. The plan is administered by the
Committee, which determines, in its full discretion, the number of rights to
award, the grant date of the rights, the vesting period of the rights awarded
and the formula for allocating rights to the participants and the strike price
of the rights awarded. Each right is equivalent to one common
unit. The rights have a term of 10 years from the date of
grant. If the right has not been exercised at the end of the ten year
term and the participant has not terminated employment with us, the right will
be deemed exercised as of the date of the right’s expiration and a cash payment
will be made as described below.
Upon
vesting, the participant may exercise his rights to receive a cash payment equal
to the difference between the average of the closing market price of our common
units for the ten days preceding the date of exercise over the strike price of
the right being exercised. The cash payment to the participant will
be net of any applicable withholding taxes required by law. If the
Committee determines, in its full discretion, that it would cause significant
financial harm to us to make cash payments to participants who have exercised
rights under the plan, then the Committee may authorize deferral of the cash
payments until a later date.
Termination
for any reason other than death, disability or normal retirement (as these terms
are defined in the plan) will result in the forfeiture of any non-vested
rights. Upon death, disability or normal retirement, all rights will
become fully vested. If a participant is terminated for any reason
within one year after the effective date of a change in control (as defined in
the plan) all rights will become fully vested.
Bonus
Program
As
discussed in the Compensation Disclosure and Analysis, we have a bonus program
for all eligible employees of our general partner, with the exception of our
Senior Executives. This program provides for our Other Executives to
receive bonuses annually at the discretion of our Board based on the
recommendation of the Committee. A bonus pool is determined based on
our achieving certain levels of Available Cash before Reserves and bonus expense
and the improvement in our safety record. Each eligible employee will be
eligible to receive a bonus; however, the actual amounts paid will be determined
by the Senior Executives with the approval of the Committee. The
total paid for 2008 bonuses was $4.5 million.
GRANTS OF
PLAN BASED AWARDS IN FISCAL YEAR 2009
The
following tables show the non-equity incentive plan awards granted to the Other
Executives for 2009 and the outstanding SARs and phantom units awards at
December 31, 2009 that were issued to our Other
Executives. Information on rights granted to non-employee directors
is included in the section entitled Director Compensation.
|
Grants
of Plan-Based Awards in Fiscal Year 2009
|
||||||||||||||||||
|
All
Other Stock Awards: Number of Shares of Stock or Units (#)
(1)
|
Exercise
or Base Price of Option Awards ($/Sh)
|
Market
Price of Common Units on Award Date
(2)
|
Grant
Date Fair Value of Stock and Option Awards
(3)
|
|||||||||||||||
|
Name
|
Grant
Date
|
|||||||||||||||||
|
Ross
A. Benavides
|
2/26/2009
|
8,750 | $ | - | $ | 7.59 | $ | 66,440 | ||||||||||
|
Karen
N. Pape
|
2/26/2009
|
7,692 | $ | - | $ | 7.59 | $ | 58,408 | ||||||||||
|
|
(1)
|
Represents
the number of phantom units awarded to the NEO on February 26,
2009.
|
|
|
(2)
|
Represents
the closing market price of our common units on the date of the phantom
unit award.
|
|
|
(3)
|
The
amounts in this column represent the fair value of the award on the date
of the grant, February 26, 2009, as calculated in accordance with
accounting guidance for equity-based
compensation.
|
OUTSTANDING
EQUITY AWARDS AT 2009 FISCAL YEAR-END
The
following table presents information regarding the outstanding equity awards to
our Other Executives at December 31, 2009.
|
Outstanding
Equity Awards at 2009 Fiscal Year-End
|
|||||||||||||||||||||||||
|
Stock
Appreciation Rights
|
Stock
Awards
|
||||||||||||||||||||||||
|
Name
|
Number
of Securities Underlying Stock Appreciation Rights (#)
Exercisable
|
Number
of Securities Underlying Unexercised Stock Appreciation Rights (#)
Unexercisable (1)
|
Stock
Appreciation Rights Exercise Price ($)
|
Stock
Appreciation Rights Expiration Date
|
Number
of Phantom Units That Have Not Vested (#) (2)
|
Market
Value of Phantom Units That Have Not Vested ($)
|
Fair
Value of Class B Membership Interests That Have Not Vested
(3)
|
||||||||||||||||||
|
Grant
E. Sims
|
$ | 15,573,193 | |||||||||||||||||||||||
|
Joseph
A. Blount, Jr.
|
$ | 13,400,189 | |||||||||||||||||||||||
|
Robert
V. Deere
|
$ | 1,145,854 | |||||||||||||||||||||||
|
Ross
A. Benavides
|
15,889 | $ | 9.26 |
12/31/2013
|
|||||||||||||||||||||
| 3,777 | $ | 12.48 |
12/31/2014
|
||||||||||||||||||||||
| 4,015 | $ | 11.17 |
12/31/2015
|
||||||||||||||||||||||
| 1,003 | $ | 16.95 |
8/29/2016
|
||||||||||||||||||||||
| 5,270 | $ | 19.57 |
12/29/2016
|
||||||||||||||||||||||
| 5,448 | $ | 20.92 |
2/14/2018
|
||||||||||||||||||||||
| 9,176 | $ | 173,426 | |||||||||||||||||||||||
| 8,750 | $ | 165,375 | |||||||||||||||||||||||
|
Karen
N. Pape
|
12,153 | $ | 9.26 |
12/31/2013
|
|||||||||||||||||||||
| 2,889 | $ | 12.48 |
12/31/2014
|
||||||||||||||||||||||
| 3,071 | $ | 11.17 |
12/31/2015
|
||||||||||||||||||||||
| 767 | $ | 16.95 |
8/29/2016
|
||||||||||||||||||||||
| 4,254 | $ | 19.57 |
12/29/2016
|
||||||||||||||||||||||
| 4,790 | $ | 20.92 |
2/14/2018
|
||||||||||||||||||||||
| 8,156 | $ | 154,148 | |||||||||||||||||||||||
| 7,692 | $ | 145,379 | |||||||||||||||||||||||
|
|
(1)
|
The
unexercisable rights of each named executive officer vest on the following
dates in the order they are listed: January 1, 2010, January 1,
2010, December 31, 2010 and February 14,
2012.
|
|
|
(2)
|
The
first phantom unit award listed for each NEO vest on December 18,
2010. One third of the second award listed for each NEO vest
annually on February 26 beginning in 2010. As a result of the
change in control of our general partner, all outstanding phantom units
vested on February 5, 2010.
|
|
|
(3)
|
Amount
represents management’s estimate of the fair value of the Class B
Membership award and deferred compensation award granted on December 31,
2008 to the NEO. See a description of these awards at “The
Class B Membership Interest in Our General Partner” above in “Compensation
Discussion and Analysis.” This fair value was estimated under
the accounting guidance for equity-based
compensation.
|
DIRECTOR
COMPENSATION FOR FISCAL YEAR 2009
The table
below reflects compensation for the directors. Directors who are employees of
our general partner, like Mr. Sims, do not receive compensation for service as a
director. During 2009, compensation for the independent and Davison
directors consisted of an annual fee of $40,000. The Audit Committee
Chairman received an additional annual fee of $10,000. Audit
Committee members received an additional annual fee of $2,500. We
paid Denbury fees totaling $140,000 for providing certain of its executives as
directors of Genesis. Additionally, directors received a fee
for attendance at meetings of $2,000 for each meeting attended in person and
$1,000 for meetings attended telephonically. This fee was applicable
to meetings of the Board and committee meetings, however only one meeting fee
could be earned per day. Meeting fees for the four executives
provided by Denbury as directors totaling $45,000 were paid to
Denbury.
|
Director
Compensation in Fiscal 2009
|
||||||||||||||||
|
Name
|
Fees
Earned or Paid in Cash ($)
(1)
|
Stock
Awards ($)
(2)
|
Option
Awards ($)
(3)
|
Total
|
||||||||||||
|
Mark
C. Allen
(4)
|
$ | 51,000 | $ | 45,836 | $ | 11,557 | $ | 108,393 | ||||||||
|
David
C. Baggett, Jr.
|
$ | 67,500 | $ | 45,836 | $ | - | $ | 113,336 | ||||||||
|
James
E. Davison
|
$ | 53,000 | $ | 45,836 | $ | 1,202 | $ | 100,038 | ||||||||
|
James
E. Davison, Jr.
|
$ | 53,000 | $ | 45,836 | $ | 1,202 | $ | 100,038 | ||||||||
|
Ronald
T. Evans
(4)
|
$ | 53,000 | $ | 45,836 | $ | 30,144 | $ | 128,980 | ||||||||
|
Susan
O. Rheney
|
$ | 77,000 | $ | 45,836 | $ | 39,134 | $ | 161,970 | ||||||||
|
Gareth
Roberts
(4)
|
$ | 29,000 | $ | 19,525 | $ | (4,660 | ) | $ | 43,865 | |||||||
|
Phil
Rykhoek
(4)
|
$ | 52,000 | $ | 45,836 | $ | 26,767 | $ | 124,603 | ||||||||
|
J.
Conley Stone
|
$ | 53,000 | $ | 45,836 | $ | 18,323 | $ | 117,159 | ||||||||
|
Martin
G. White
|
$ | 68,500 | $ | 45,836 | $ | - | $ | 114,336 | ||||||||
|
|
(1)
|
Amounts
include annual retainer fees and fees for attending
meetings.
|
|
|
(2)
|
Amounts
in this column represent the amounts, before consideration of expected
forfeiture rate, that are included in the determination of net income for
the period under generally accepted accounting principles for awards of
phantom units under our 2007 LTIP. The forfeiture rate that was
applied to the phantom unit awards at December 31, 2009 was
zero. Each director received an award of 3,500 phantom units on
February 26, 2009. The grant date fair value of these awards
was $8.88 per phantom unit.
|
|
|
(3)
|
Amounts
in this column represent the amounts, before consideration of expected
forfeiture rate, that are included in the determination of net income for
the period under generally accepted accounting principles for awards of
stock appreciation rights. The forfeiture rate that was applied
to these stock appreciation rights at December 31, 2009 was ten
percent. Under our stock appreciation rights plan, the director
will receive cash upon exercise of the
right.
|
|
|
(4)
|
Fees
were paid in cash for these directors to Denbury. The phantom
unit and stock appreciation rights awards are individual awards of the
named director. Mr. Roberts resigned as a director of our
general partner in June 2009, and his stock appreciation rights were
forfeited or expired
unexercised.
|
OUTSTANDING
EQUITY AWARDS AT 2009 FISCAL YEAR END
The
outstanding awards of stock appreciation rights to the directors of our general
partner are shown in the table below.
|
Oustanding
Equity Awards at 2009 Fiscal Year-End to Directors
|
|||||||||||||||||||||
|
Stock
Appreciation Rights
|
Stock
Awards
|
||||||||||||||||||||
|
Name
|
Number
of Securities Underlying Stock Appreciation Rights (#)
Exercisable
|
Number
of Securities Underlying Unexercised Stock Appreciation Rights (#)
Unexercisable
|
Stock
Appreciation Rights Exercise Price ($)
|
Stock
Appreciation Rights Expiration Date
|
Number
of Phantom Units That Have Not Vested (#)
(1)
|
Market
Value of Phantom Units That Have Not Vested ($)
(2)
|
|||||||||||||||
|
Mark
C. Allen
(3)
|
966 | 322 | $ | 15.77 |
9/29/2016
|
||||||||||||||||
| 1,000 | $ | 19.57 |
12/29/2016
|
||||||||||||||||||
| 1,000 | $ | 20.92 |
2/14/2018
|
||||||||||||||||||
| 3,500 | 66,150 | ||||||||||||||||||||
|
David
C. Baggett
|
3,500 | 66,150 | |||||||||||||||||||
|
James
E. Davison
(4)
|
1,000 | $ | 20.92 |
2/14/2018
|
|||||||||||||||||
| 3,500 | 66,150 | ||||||||||||||||||||
|
James
E. Davison, Jr.
(4)
|
1,000 | $ | 20.92 |
2/14/2018
|
|||||||||||||||||
| 3,500 | 66,150 | ||||||||||||||||||||
|
Ronald
T. Evans
(3)
|
2,576 | $ | 9.26 |
12/31/2013
|
|||||||||||||||||
| 612 | $ | 12.48 |
12/31/2014
|
||||||||||||||||||
| 651 | $ | 11.17 |
12/31/2015
|
||||||||||||||||||
| 1,000 | $ | 19.57 |
12/29/2016
|
||||||||||||||||||
| 1,000 | $ | 20.92 |
2/14/2018
|
||||||||||||||||||
| 3,500 | 66,150 | ||||||||||||||||||||
|
Susan
O. Rheney
(5)
|
3,435 | $ | 9.26 |
12/31/2013
|
|||||||||||||||||
| 816 | $ | 12.48 |
12/31/2014
|
||||||||||||||||||
| 868 | $ | 11.17 |
12/31/2015
|
||||||||||||||||||
| 1,000 | $ | 19.57 |
12/29/2016
|
||||||||||||||||||
| 1,000 | $ | 20.92 |
2/14/2018
|
||||||||||||||||||
| 3,500 | 66,150 | ||||||||||||||||||||
|
Phil
Rykhoek
(3)
|
2,576 | $ | 11.00 |
8/25/2014
|
|||||||||||||||||
| 612 | $ | 12.48 |
12/31/2014
|
||||||||||||||||||
| 651 | $ | 11.17 |
12/31/2015
|
||||||||||||||||||
| 1,000 | $ | 19.57 |
12/29/2016
|
||||||||||||||||||
| 1,000 | $ | 20.92 |
2/14/2018
|
||||||||||||||||||
| 3,500 | 66,150 | ||||||||||||||||||||
|
J.
Conley Stone
(5)
|
773 | $ | 9.26 |
12/31/2013
|
|||||||||||||||||
| 735 | $ | 12.48 |
12/31/2014
|
||||||||||||||||||
| 781 | $ | 11.17 |
12/31/2015
|
||||||||||||||||||
| 1,000 | $ | 19.57 |
12/29/2016
|
||||||||||||||||||
| 1,000 | $ | 20.92 |
2/14/2018
|
||||||||||||||||||
| 3,500 | 66,150 | ||||||||||||||||||||
|
Martin
G. White
|
3,500 | 66,150 | |||||||||||||||||||
|
|
(1)
|
These
phantom units vest on February 26, 2010 or with a change in control of our
general partner. A change in control occurred on February 5,
2010.
|
|
|
(2)
|
The
market value of the phantom units that have not vested was determined by
multiplying the number of phantom units by the closing price of our common
units on December 31, 2009 of
$18.90.
|
|
|
(3)
|
Due
to the resignation of this director on February 5, 2010, all unexercisable
stock appreciation rights were forfeited on that date. The
director has until May 5, 2010 to exercise his vested
rights. After that date, the director forfeits any exercisable
rights.
|
|
|
(4)
|
The
unexercisable stock appreciation rights of this director vest on February
14, 2012.
|
|
|
(5)
|
The
unexercisable stock appreciation rights of this director vest on the
following dates in the order they are listed: January 1,
2011 and February 14, 2012.
|
Compensation
Committee Interlocks and Insider Participation
None of
the members of the Compensation Committee has at any time been an officer or
employee of our general partner or us. None of our executive officers
serves, or in the past year has served, as a member of the board of directors or
compensation committee of any entity that has one or more of its executive
officers serving on our Compensation Committee.
Compensation
Changes Subsequent to December 31, 2009
On
February 5, 2010, Mr. Sims, Mr. Deere and Ms. Pape, along with other members of
our senior management team entered into restricted unit agreements with our
general partner that provide for these individuals to receive Series B units in
our general partner. The Series A units in our general partner were
issued to the Quintana-Controlled Investor Group.
An
aggregate of 767 Series B units were issued. The Series B units in
our general partner vest in tranches, with one-fourth of the Series B units
vesting each year until fully-vested. The restricted unit agreements
contain provisions providing for unvested units becoming fully-vested under
certain circumstances including a change in control of our general
partner. Holders of Series B units, upon vesting, have the right to
receive a share, of the quarterly incentive distributions paid to our general
partner, subject to the rights of the holders of Series A units in our general
partner to receive distributions up to certain threshold amounts
first.
On
February 5, 2010, Messrs. Sims and Deere each also entered into a waiver
agreement which amended the terms of their respective employment
agreements waiving certain change of control and severance payment rights and
agreed to a form of employment agreement and related release that our general
partner may require each to execute in the future.
The
employment of Mr. Blount was terminated effective February 10,
2010. In connection with such termination, Mr. Blount will receive a
severance package consisting of payment of his base salary for a period of 36
months, and health and welfare benefits for a period of 18 months.
It
em 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 February19, 2010, 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
|
||||||
|
Title
of Class
|
Name
and Address of Beneficial Owner
|
Number
of Units
|
Percent
of Class
|
|||
|
Genesis
Energy, L.P.
|
David
C. Baggett, Jr.
|
5,800
|
*
|
|||
|
Common
Units
|
James
E. Davison
(1)
(2)
|
2,881,338
|
7.3
|
|||
|
James
E. Davison, Jr.
(3)
(4)
|
3,160,567
|
8.0
|
||||
|
Susan
O. Rheney
|
6,500
|
*
|
||||
|
Grant
E. Sims
(5)
|
6,000
|
*
|
||||
|
J.
Conley Stone
|
7,800
|
*
|
||||
|
Martin
G. White
|
7,900
|
*
|
||||
|
Steven
R. Nathanson
|
129,907
|
0.3
|
||||
|
Ross
A. Benavides
|
22,173
|
0.1
|
||||
|
Karen
N. Pape
|
14,745
|
*
|
||||
|
All
directors and executive officers as a group (15 in total)
|
6,242,730
|
15.7
|
||||
|
Todd
A. Davison
(6)
|
2,876,236
|
7.3
|
||||
|
Steven
K. Davison
(7)
|
2,875,537
|
7.3
|
||||
|
Terminal
Service, Inc.
(8)
|
1,010,835
|
2.6
|
||||
|
Denbury
Gathering & Marketing Inc.and Denbury Onshore LLC
(9)
|
4,028,096
|
10.2
|
||||
|
5100
Tennyson Parkway
|
||||||
|
Plano,
Texas 75024
|
||||||
|
Swank
Capital, LLC, Swank Energy Income Advisors,L.P. and Mr. Jerry V. Swank
(10)
|
2,101,344
|
5.3
|
||||
|
3300
Oak Lawn Ave., Suite 650
|
||||||
|
Dallas,
Texas 75219
|
||||||
|
Neuberger
Berman, Inc.
(11)
|
2,002,598
|
5.1
|
||||
|
605
Third Avenue
|
||||||
|
New
York, NY 10158
|
||||||
|
|
(1)
|
James
E. Davison is the sole stockholder of Davison Terminal Service, Inc.,
which directly owns 1,010,835 units. Additionally, Mr. Davison
owns a six percent interest in our general
partner.
|
|
|
(2)
|
We
have been granted a lien on 331,754 of these units to secure the Davison
unitholders indemnification obligations to us under the terms of our
acquisition of the Davison
businesses.
|
|
|
(3)
|
James
E. Davison, Jr. owns a six percent interest in our general
partner
|
|
|
(4)
|
We
have been granted a lien on 338,056 of these units to secure the Davison
unitholders indemnification obligations to us under the terms of our
acquisition of the Davison businesses. Mr. Davison pledged
700,000 of these units as collateral for a loan from a
bank.
|
|
|
(5)
|
1,000
of these common units are held by Mr. Sims’ father. Mr. Sims
disclaims beneficial ownership of these units. Effective
February 5, 2010, Mr. Sims is also a 6.5 percent owner in our general
partner.
|
|
|
(6)
|
Todd
A. Davison is the son of James E. Davison and the brother of James E.
Davison, Jr., and a six percent owner in our general
partner. Additionally, Mr. Davison provides services in our
supply and logistics division. The mailing address for Mr. Davison is 2000
Farmerville Hwy., Ruston, LA 71270. We have been granted
a lien on 338,056 of these units to secure the Davison unitholders
indemnification obligations to us under the terms of our acquisition of
the Davison businesses.
|
|
|
(7)
|
Steven
K. Davison is the son of James E. Davison and the brother of James E.
Davison, Jr. and Todd A. Davison, and a six percent owner in our general
partner. Mr. Davison also provides services to us in our supply
and logistics division. The mailing address for Mr. Davison is
207 W. Alabama, Ruston, LA 71270. We have been granted a lien
on 338,056 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 by James E. Davison. The mailing address of
this entity is PO Box 607, Ruston, LA
71273.
|
|
|
(9)
|
Denbury
Gathering and Marketing Inc.is the former owner of our general
partner. Denbury Gathering and Marketing Inc. and Denbury
Onshore Inc. are wholly-owned subsidiaries of Denbury Resources
Inc. Until January 29, 2010, 2,829,055 of these common units
were held by our general partner. The units were transferred to
Denbury Gathering & Marketing Inc. at that
time.
|
|
|
(10)
|
Information
based on Schedule 13G filed with the SEC on February 16,
2010. 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.
|
|
|
(11)
|
Information
based on Schedule 13G filed with the SEC on February 17,
2010.
|
Except as
noted, each unitholder in the above table is believed to have sole voting and
investment power with respect to the units beneficially held, subject to
applicable community property laws.
The
mailing address for Genesis Energy, LLC and all officers and directors is 919
Milam, Suite 2100, Houston, Texas, 77002.
Beneficial
Ownership of General Partner Interest
Genesis
Energy, LLC owns all of our 2% general partner interest and all of our incentive
distribution rights. Genesis Energy, LLC is controlled
by Quintana. Quintana has advised us that it has not
pledged any of its interest in our general partner under any agreements or
arrangements.
It
em 13. Certain Relationships and Related
Transactions, and Director Independence
Our
General Partner
Genesis
Energy, LLC, our general partner owns a 2% general partner interest in us and
all incentive distribution rights. Our general partner also manages
our operations and employs all of our employees.
Distributions
and Payments to Our General Partner and its Affiliates
The
following table summarizes the distributions and payments made or to be made by
us to our general partner and its affiliates in connection with our ongoing
operations and in the event of a liquidation, including payments made for the
year ended December 31, 2009.
Operational
Stage
|
Distributions
of available cash to our general partner and its
affiliates
|
|
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.
|
|
During
2009, our general partner received a total of $10.1 million from us as
distributions, with $3.9 million attributable to its limited partner
units, $1.1 million for its general partner interest, and $5.1 million
related to its incentive distribution rights.
|
||
|
|
|
|
|
Payments
to our general partner and its affiliates
|
|
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
2009, these reimbursements totaled $50.4 million. As of
December 31, 2009, we owed our general partner $2.1 million related to
these services.
|
|
|
|
|
|
Withdrawal
or removal of our general partner
|
|
Our
partnership agreement provides that, with the approval of at least a
majority of our limited partners, our general partner also may be removed
without cause. Any limited partner interests held by our
general partner and its affiliates would be excluded from such a
vote.
|
|
If
our general partner withdraws or is removed, its general partner interest
and its incentive distribution rights will either be sold to the new
general partner for cash or converted into common units, in each case for
an amount equal to the fair market value of those
interests.
|
|
Liquidation
Stage
|
||
|
|
|
|
|
Liquidation
|
|
Upon
our liquidation, the partners, including our general partner, will be
entitled to receive liquidating distributions according to their
particular capital account
balances.
|
Review
or Special Approval of Material Transactions with Related Persons
Before we
consider entering into a material transaction with our general partner or any of
its affiliates, we determine whether the proposed transaction (1) would comply
with the requirements under our credit facility, (2) would comply with
substantive law, (3) would comply with our partnership agreement, and (4) would
be fair to us and our limited partners. In addition, our general
partner’s board of directors may seek “Special Approval” (as defined in our
partnership agreement) from our Audit Committee, which is comprised solely of
independent directors. That committee:
|
|
·
|
evaluates
and, where appropriate, negotiates the proposed
transaction;
|
|
|
·
|
engages
an independent legal counsel and, if it deems appropriate, an independent
financial advisor to assist with its evaluation of the proposed
transaction; and
|
|
|
·
|
determines
whether to reject or approve and recommend the proposed
transaction.
|
Traditionally,
we have consummated proposed material acquisitions or dispositions 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.
Our
Relationship with Quintana Capital Group, L.P.
On
February 5, 2010, affiliates of Quintana Capital Group II, L.P., along with
members of the Davison family and our Senior Executive Management team, acquired
control of our general partner. Our general partner owns all of our
general partner interest and all of our incentive distribution
rights.
Quintana,
an energy-focused private-equity firm headquartered in Houston, Texas, has
stated that it intends to use us as one of its primary vehicles for investing in
the midstream segment of the energy sector. Quintana, through its
affiliated investment funds, currently manages approximately $900 million in
capital for various U.S and international investors. With
offices in Houston, Dallas and Midland, Texas and Beijing, China, Quintana
focuses on control-oriented investments across a wide range of sectors in the
energy industry, developing a portfolio that is diversified across the energy
value chain. Formed in 2006, Quintana is managed by highly
experienced investors, including Corbin J. Robertson, Jr. and former Secretary
of Commerce Donald L. Evans.
Prior to
Quintana’s investment in us, Denbury Resources Inc. (NYSE:DNR) controlled our
general partner. Denbury retained ownership of 10.2% of our
outstanding common units after the sale of our general partner to
Quintana.
Our
Relationship with the Davison Family
Certain
Davison family members have been investors in us since 2007, when we issued
13,459,209 units to them as partial consideration for assets. At
December 31, 2009, the Davison unitholders held approximately 30% of our
outstanding common units.
In
connection with the terms of our acquisition of the Davison businesses, the
Davison unitholders have registration rights with respect to their
units.
These
rights include the following provisions:
|
|
·
|
the
right to require us to file a shelf registration statement, which we filed
in 2008;
|
|
|
·
|
the
right to demand five registrations of their units, one per calendar year,
and piggyback rights for other unit registrations;
and
|
|
|
·
|
the
Davison unitholders have agreed to specified restrictions on the sale and
transfer of the units they received in consideration of this
acquisition. The Davison unitholders cannot sell any of the
units issued as consideration except that portion provided below (subject
to certain exceptions):
|
|
At
closing (July 25, 2007)
|
20 | % | ||
|
At
July 25, 2008
|
20 | % | ||
|
At
January 25, 2009
|
20 | % | ||
|
At
July 25, 2009
|
30 | % | ||
|
At
July 25, 2010
|
10 | % | ||
| 100 | % |
In 2010,
the members of the Davison family acquired an interest in our general
partner.
Pursuant
to the agreements among the owners of our general partner executed on February
5, 2010, the Davison unitholders have the right to designate up to three
directors to our board of directors, depending on their continued level of
ownership in our general partner. The members of the Davison family
have the right to designate and appoint up to three directors, one of whom must
be independent, as long as members of the Davison family hold at least 75% of
the interest in our general partner that they held as of February 5,
2010. If members of the Davison family hold less than 75% but more
than 50% of the interest in our general partner that they held on February 5,
2010, they have the right to appoint two directors and if they hold less than
50%, they have the right appoint one director.
The
members of the Davison family designated and appointed James E. Davison and
James E Davison, Jr. to continue to serve as directors of our general
partner. They waived their right to appoint a third director until a
position on the board of directors is available.
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 were
released, and the remaining 1,345,921 units will be released on July 26,
2010.
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, 2009 was approximately
$16,000.
Our joint
venture partner in DG Marine is TD Marine, LLC, an entity owned by James E.
Davison and two of his sons. TD Marine owns 51% of the
economic interest in DG Marine. Additionally, Community Trust Bank is
a 17% participant in the DG Marine credit facility. Davison family
members own approximately 12% of Community Trust Bank, and James E. Davison, Jr.
serves on the board of the holding company that owns Community Trust
Bank.
During
2009, we sold $0.8 million of petroleum products to businesses owned and
operated by members of the Davison family in the ordinary course of our
operations.
Relationship
with Denbury Resources, Inc.
Historically,
we have entered into transactions with Denbury and its subsidiaries to acquire
assets from time to time. We instituted specific procedures for
evaluating and valuing our material transactions with Denbury and its
subsidiaries.
We
entered into transactions with Denbury in the ordinary course of our
operations. During 2009, these transactions included:
|
|
·
|
Provision
of transportation services for crude oil by truck totaling $3.2
million.
|
|
|
·
|
Provision
of crude oil pipeline transportation services totaling $14.4
million.
|
|
|
·
|
Provision
of CO
2
and
crude oil pipeline transportation services under lease arrangements for
which we received payments totaling $21.9
million.
|
|
|
·
|
Provision
of CO
2
transportation services to our wholesale industrial customers by Denbury’s
pipeline. The fees for this service totaled $5.5 million in
2009.
|
|
|
·
|
Provision
of pipeline monitoring services to Denbury for its CO
2
pipelines totaling $120,000 in
2009.
|
|
|
·
|
Provision
of services by Denbury officers as directors of our general
partner. We paid Denbury $185,000 for these services in
2009.
|
At
December 31, 2009, we owed Denbury $1.0 million for provision of CO
2
transportation services. Denbury owed us $1.9 million for crude oil
trucking and pipeline transportation services.
Denbury
also owns 4,028,086 limited partner units and has the same rights and is
entitled to receive distributions as the other limited partners with respect to
those units. Denbury has registration rights with respect to such
units, including the right to require us to file a shelf registration statement,
which we filed in January 2010, and the right to demand three registrations of
their units, in the form of an underwritten offering, up to two per calendar
year and piggyback rights for other unit registrations.
Director
Independence
Susan O.
Rheney, David C. Baggett and Martin G. White, all members of our Audit
Committee, meet the listing standard requirements of NYSE Amex LLC, and the SEC
rules to be considered independent directors of
Genesis. Additionally, J. Conley Stone also meets the requirements to
be considered an independent director. The term “independent
director” means a person other than an officer or employee of our general
partner, the Partnership or its subsidiaries, or Denbury or its subsidiaries, or
any other individual having a relationship that, in the opinion of the Board of
Directors, would interfere with the exercise of independent judgment in carrying
out the responsibilities of a director. To be considered independent,
neither the director nor an immediate family member of the director has had any
direct or indirect material relationship with Genesis.
The
independent directors meet regularly in executive sessions outside of the
presence of the non-independent directors or members of our management after
each of the regularly scheduled quarterly Audit Committee
meetings. See additional discussion of director independence at Item
10. Directors, Executive Officers and Corporate Governance –
Management of Genesis Energy,
L.P
.
It
em 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, 2009 and
2008.
|
2009
|
2008
|
|||||||
|
(in
thousands)
|
||||||||
|
Audit
Fees
(1)
|
$ | 3,122 | $ | 3,634 | ||||
|
Audit-Related
Fees
(2)
|
80 | 296 | ||||||
|
Tax
Fees
(3)
|
479 | 368 | ||||||
|
All
Other Fees
(4)
|
4 | 3 | ||||||
|
Total
|
$ | 3,685 | $ | 4,301 | ||||
|
|
(1)
|
Includes
fees for the annual audit and quarterly reviews (including internal
control evaluation and reporting), SEC registration statements and
accounting and financial reporting consultations and research work
regarding Generally Accepted Accounting Principles. Also
includes audits of our general partner and separate audits of certain of
our consolidated subsidiaries and joint
ventures.
|
|
|
(2)
|
Includes
fees for the audit of our employee benefit plan. In 2009, also
includes fees for services related to third-party review of workpapers and
review of correspondence with SEC. In 2008, amount includes
fees for assistance in the documentation of internal controls over
financial reporting.
|
|
|
(3)
|
Includes
fees for tax return preparation and tax
consultations.
|
|
|
(4)
|
Includes
fees associated with licenses for accounting research
software.
|
Pre-Approval
Policy
The
services by Deloitte in 2009 and 2008 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 2009
and 2008, 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.
It
em 15. Exhibits and Financial Statement
Schedules
(a)(1)
Financial Statements
See
“Index to Consolidated Financial Statements and Financial Statement Schedules”
set forth on page 99.
(a)(2) Financial
Statement Schedules
See
“Index to Consolidated Financial Statements and Financial Statement Schedules”
set forth on page 99.
(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)
|
||
|
3.3
|
Amendment
No. 1 to Fourth Amended and Restated Agreement of Limited Partnership of
Genesis (incorporated by reference to Exhibit 3.3 to Form 10-K
dated December 31, 2007)
|
||
|
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)
|
||
|
3.6
|
Certificate
of Conversion of Genesis Energy, Inc., a Delaware corporation, into
Genesis Energy, LLC, a Delaware limited liability company (incorporated by
reference to Exhibit 3.1 to Form 8-K dated January 7,
2009)
|
||
|
3.7
|
Certificate
of Formation of Genesis Energy, LLC (incorporated by reference
to Exhibit 3.1 to Form 8-K dated January 7,
2009)
|
|
3.9
|
Amended
and Restated Limited Liability Company Agreement of Genesis Energy, LLC
dated February 5, 2010 (incorporated by reference to Exhibit 3.2 to Form
8-K dated February 11, 2010)
|
||
|
4.1
|
Form
of Unit Certificate of Genesis Energy, L.P. (incorporated by
reference to Exhibit 4.1 to Form 10-K dated December 31,
2007)
|
||
|
10.1
|
First
Amended and Restated Credit Agreement dated as of May 30, 2008 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 10.4 to Form 8-K dated June 5,
2008)
|
||
|
10.2
|
First
Amendment to First Amended and Restated Credit Agreement, dated as of July
18, 2008, among Genesis Crude Oil, L.P., Genesis Energy, L.P., the lenders
party thereto, Fortis Capital Corp. and Deutsche Bank Securities Inc.
(incorporated by reference to Exhibit 10.3 to Form 8-K dated July 22,
2008)
|
||
|
10.3
|
Second
Amendment to First Amended and Restated Credit Agreement dated as of
February 5, 2010, among Genesis Crude Oil, L.P., Genesis Energy, L.P., the
lenders party thereto, Fortis Capital Corp. and Deutsche Bank Securities
Inc. (incorporated by reference to Exhibit 10.1 to Form 8-K dated February
11, 2010)
|
||
|
10.4
|
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)
|
||
|
10.5
|
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)
|
||
|
10.6
|
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)
|
||
|
10.7
|
Amendment
No. 3 to the Contribution and Sale Agreement dated March 3,
2008 (incorporated by reference to Exhibit 10.21 to Form 10-K
dated December 31, 2007)
|
||
|
10.8
|
Registration
Rights Agreement (incorporated by reference to Exhibit 10.3 to Form 8-K
dated July 31, 2007)
|
||
|
10.9
|
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)
|
||
|
10.10
|
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)
|
||
|
10.11
|
Unitholder
Rights Agreement (incorporated by reference to Exhibit 10.4 to Form 8-K
dated July 31, 2007)
|
||
|
10.12
|
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)
|
||
|
10.13
|
Pledge
and Security Agreement (incorporated by reference to Exhibit 10.5 to Form
8-K dated July 31, 2007)
|
||
|
10.14
|
Pipeline
Financing Lease Agreement by and between Genesis NEJD Pipeline, LLC, as
Lessor and Denbury Onshore, LLC, as Lessee for the North East Jackson Dome
Pipeline dated May 30, 2008 (incorporated by reference to Exhibit 10.1 to
Form 8-K dated June 5, 2008)
|
||
|
10.15
|
Purchase
and Sale Agreement between Denbury Onshore, LLC and Genesis Free State
Pipeline, LLC dated May 30, 2008 (incorporated by reference to Exhibit
10.2 to Form 8-K dated June 5,
2008)
|
|
10.16
|
Transportation
Services Agreement between Genesis Free State Pipeline, LLC and Denbury
Onshore, LLC dated May 30, 2008 (incorporated by reference to Exhibit 10.3
to Form 8-K dated June 5, 2008)
|
||
|
10.17
|
Contribution
and Sale Agreement by and Among Grifco Transportation, Ltd., Grifco
Transportation Two, Ltd., and Shore Thing, Ltd. and Genesis Marine
Investments, LLC and Genesis Energy, L.P. and TD Marine, LLC (incorporated
by reference to Exhibit 10.1 to Form 8-K dated July 22,
2008)
|
||
|
10.18
|
Omnibus
Agreement dated as of June 11, 2008 by and among TD Marine, LLC, James E.
Davison, Steven K. Davison, Todd A Davison and Genesis Energy, L.P.
(incorporated by reference to Exhibit 10.1 to Form 8-K dated July 22,
2008)
|
||
|
10.19
|
Registration
Rights Agreement among Denbury Resources, Inc., Denbury Gathering &
Marketing, Inc., Denbury Onshore, LLC and Genesis Energy, L.P. dated
February 5, 2010 (incorporated by reference to Exhibit 4.1 to Form 8-K
dated February 11, 2010)
|
||
|
10.20
|
+
|
Genesis
Energy, LLC First Amended and Restated Stock Appreciation Rights Plan
(incorporated by reference to Exhibit 10.24 to Form 10-K for the year
ended December 31, 2008)
|
|
|
10.21
|
+
|
Form
of Stock Appreciation Rights Plan Grant Notice (incorporated by reference
to Exhibit 10.25 to Form 10-K for the year ended December 31,
2008)
|
|
|
10.22
|
+
|
Genesis
Energy, LLC Amended and Restated Severance Protection Plan (incorporated
by reference to Exhibit 10.1 to Form 8-K dated December 12,
2006)
|
|
|
10.23
|
+
|
Amendment
to the Genesis Energy Severance Protection Plan (incorporated by reference
to Exhibit 10.27 to Form 10-K for the year ended December 31,
2008)
|
|
|
10.24
|
+
|
Genesis
Energy, Inc. 2007 Long Term Incentive Plan (incorporated by reference to
Exhibit 10.1 to Form 8-K dated December 21, 2007)
|
|
|
10.25
|
+
|
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)
|
|
|
10.26
|
+
|
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)
|
|
|
10.27
|
+
|
Employment
Agreement by and between Genesis Energy, LLC and Grant E. Sims, dated
December 31, 2008 (incorporated by reference to Exhibit 10.1 to Form 8-K
dated January 7, 2009)
|
|
|
10.28
|
+
|
Employment
Agreement by and between Genesis Energy, LLC and Joseph A. Blount, Jr.,
dated December 31, 2008 (incorporated by reference to Exhibit
10.2 to Form 8-K dated January 7, 2009)
|
|
|
10.29
|
+
|
Employment
Agreement by and between Genesis Energy, LLC and Robert V. Deere, dated
December 31, 2008 (incorporated by reference to Exhibit 10.3 to Form 8-K
dated January 7, 2009)
|
|
|
*
|
+
|
Employment
Agreement by and between Genesis Energy, Inc. and Steve Nathanson dated
July 25, 2007
|
|
|
10.31
|
+
|
Genesis
Energy, LLC Deferred Compensation Plan, effective December 31, 2008
(incorporated by reference to Exhibit 10.4 to Form 8-K dated January 7,
2009)
|
|
|
10.32
|
+
|
Genesis
Energy, LLC Award – Individual Class B Interest for Grant E. Sims dated
December 31, 2009 (incorporated by reference to Exhibit 10.5 to Form 8-K
dated January 7, 2009)
|
|
|
10.33
|
+
|
Genesis
Energy, LLC Award – Individual Class B Interest for Joseph A. Blount, Jr.
dated December 31, 2009 (incorporated by reference to Exhibit 10.6 to Form
8-K dated January 7, 2009)
|
|
10.34
|
+
|
Genesis
Energy, LLC Award – Individual Class B Interest for Robert V. Deere dated
December 31, 2009 (incorporated by reference to Exhibit 10.7 to Form 8-K
dated January 7, 2009)
|
|
|
10.35
|
+
|
Deferred
Compensation Grant – Genesis Energy, LLC – Grant E. Sims (incorporated by
reference to Exhibit 10.8 to Form 8-K dated January 7,
2009)
|
|
|
10.36
|
+
|
Deferred
Compensation Grant – Genesis Energy, LLC – Joseph A. Blount, Jr.
(incorporated by reference to Exhibit 10.9 to Form 8-K dated January 7,
2009)
|
|
|
10.37
|
+
|
Class
B Agreement (Sims), dated February 5, 2010 (incorporated by reference to
Exhibit 10.2 to Form 8-K dated February 11, 2010)
|
|
|
10.38
|
+
|
Class
B Agreement (Blount), dated February 5, 2010 (incorporated by reference to
Exhibit 10.3 to Form 8-K dated February 11, 2010)
|
|
|
10.39
|
+
|
Class
B Agreement (Deere), dated February 5, 2010 (incorporated by reference to
Exhibit 10.4 to Form 8-K dated February 11, 2010)
|
|
|
10.40
|
+
|
Waiver
Agreement (Sims), dated February 5, 2010 (incorporated by reference to
Exhibit 10.5 to Form 8-K dated February 11, 2010)
|
|
|
10.41
|
+
|
Waiver
Agreement (Deere), dated February 5, 2010 (incorporated by reference to
Exhibit 10.5 to Form 8-K dated February 11, 2010)
|
|
|
10.42
|
+
|
Restricted
Unit Agreement (Sims), dated February 5, 2010 (incorporated by reference
to Exhibit 10.5 to Form 8-K dated February 11, 2010)
|
|
|
10.43
|
+
|
Restricted
Unit Agreement (Deere), dated February 5, 2010 (incorporated by reference
to Exhibit 10.5 to Form 8-K dated February 11, 2010)
|
|
|
10.44
|
+
|
Restricted
Unit Agreement (Pape), dated February 5, 2010 (incorporated by reference
to Exhibit 10.5 to Form 8-K dated February 11, 2010)
|
|
|
*
|
+
|
Restricted
Unit Agreement (Nathanson) dated February 5, 2010
|
|
|
11.1
|
Statement
Regarding Computation of Per Share Earnings (See Notes 2 and 12 of the
Notes to the Consolidated Financial Statements)
|
||
|
*
|
Subsidiaries
of the Registrant
|
||
|
*
|
Consent
of Deloitte & Touche LLP
|
||
|
*
|
Certification
by Chief Executive Officer Pursuant to Rule 13a-14(a) under the Securities
Exchange Act of 1934
|
||
|
*
|
Certification
by Chief Financial Officer Pursuant to Rule 13a-14(a) under the Securities
Exchange Act of 1934
|
||
|
*
|
Certification
by Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002
|
||
|
*
|
Certification
by Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002
|
____________________
|
*
|
Filed
herewith
|
|
+
|
A
management contract or compensation plan or
arrangement.
|
SI
GNATURES
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, LLC,
|
||
| as General Partner | |||
|
Date:
February 26, 2010
|
By:
|
/s/
Grant E.
Sims
|
|
|
Grant
E. Sims
|
|||
|
Chief Executive Officer
|
|||
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons in the capacities and on the dates
indicated.
|
NAME
|
TITLE
|
DATE
|
|||
|
(OF
GENESIS ENERGY, LLC)*
|
|||||
|
/s/
|
Grant
E. Sims
|
Director
and Chief Executive Officer
|
February
26, 2010
|
||
|
Grant
E. Sims
|
(Principal
Executive Officer
|
||||
|
/s/
|
Robert
V. Deere
|
Chief
Financial Officer,
|
February
26, 2010
|
||
|
Robert
V. Deere
|
(Principal
Financial Officer)
|
||||
|
/s/
|
Karen
N. Pape
|
Senior
Vice President and Controller
|
February
26, 2010
|
||
|
Karen
N. Pape
|
(Principal
Accounting Officer)
|
||||
|
/s/
|
Robert
C. Sturdivant
|
Chairman
of the Board and
|
February
26, 2010
|
||
|
Robert
C. Sturdivant
|
Director
|
||||
|
/s/
|
David
C. Baggett, Jr.
|
Director
|
February
26, 2010
|
||
|
David
C. Baggett, Jr.
|
|||||
|
/s/
|
James
E. Davison
|
Director
|
February
26, 2010
|
||
|
James
E. Davison
|
|||||
|
/s/
|
James
E. Davison, Jr.
|
Director
|
February
26, 2010
|
||
|
James
E. Davison, Jr.
|
|||||
|
/s/
|
Donald
L. Evans
|
Director
|
February
26, 2010
|
||
|
D
onald L.
Evans
|
|||||
|
/s/
|
Susan
O. Rheney
|
Director
|
February
26, 2010
|
||
|
Susan
O. Rheney
|
|||||
|
/s/
|
Corbin
J. Robertson, III
|
Director
|
February
26, 2010
|
||
|
Corbin
J. Robertson, III
|
|||||
|
/s/
|
William
K. Robertson
|
Director
|
February
26, 2010
|
||
|
William
K. Robertson
|
|||||
|
/s/
|
J.
Conley Stone
|
Director
|
February
26, 2010
|
||
|
J.
Conley Stone
|
|||||
|
/s/
|
Martin
G. White
|
Director
|
February
26, 2010
|
||
|
Martin
G. White
|
*Genesis
Energy, LLC is our general partner.
GENESIS
ENERGY, L.P.
INDEX
TO CONSOLIDATED FINANCIAL STATEMENTS
AND
FINANCIAL STATEMENT SCHEDULES
|
Page
|
||
|
Financial
Statements
|
||
|
Report
of Independent Registered Public Accounting Firm
|
100
|
|
|
Consolidated
Balance Sheets, December 31, 2009 and 2008
|
101
|
|
|
Consolidated
Statements of Operations for the Years Ended December 31, 2009, 2008 and
2007
|
102
|
|
|
Consolidated
Statements of Comprehensive Income (Loss) for the Years Ended December 31,
2009, 2008 and 2007
|
103
|
|
|
Consolidated
Statements of Partners’ Capital for the Years Ended December 31, 2009,
2008 and 2007
|
104
|
|
|
Consolidated
Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and
2007
|
105
|
|
|
Notes
to Consolidated Financial Statements
|
106
|
|
|
Financial
Statement Schedules
|
||
|
Schedule
I – Condensed Financial Information (Parent Company Only)
|
150
|
All other
financial statement schedules have been omitted because they are not applicable
or the required information is presented in the Consolidated Financial
Statements or the Notes to the Consolidated Financial
Statements.
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Board of Directors of Genesis Energy, LLC and Unitholders of
Genesis
Energy, L.P.
Houston,
Texas
We have
audited the accompanying consolidated balance sheets of Genesis Energy, L.P. and
subsidiaries (the "Partnership") as of December 31, 2009 and 2008, and the
related consolidated statements of operations, comprehensive income (loss),
partners' capital, and cash flows for each of the three years in the period
ended December 31, 2009. 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 consolidated 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, 2009 and 2008, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2009, 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.
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, 2009, 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 February 24, 2010 expressed an
unqualified opinion on the Partnership’s internal control over financial
reporting.
/s/ DELOITTE
& TOUCHE LLP
Houston,
Texas
February
24, 2010
|
GENESIS
ENERGY, L.P.
|
||||||||
|
|
||||||||
|
(In
thousands)
|
||||||||
|
December 31,
|
December 31,
|
|||||||
|
2009
|
2008
|
|||||||
|
ASSETS
|
||||||||
|
CURRENT
ASSETS:
|
||||||||
|
Cash
and cash equivalents
|
$ | 4,148 | $ | 18,985 | ||||
|
Accounts
receivable - trade, net of allowance for doubtful accounts of $1,372 and
$1,132 at December 31, 2009 and 2008, respectively
|
127,248 | 112,229 | ||||||
|
Accounts
receivable - related party
|
2,617 | 2,875 | ||||||
|
Inventories
|
40,204 | 21,544 | ||||||
|
Net
investment in direct financing leases, net of unearned income -current
portion - related party
|
4,202 | 3,758 | ||||||
|
Other
|
10,825 | 8,736 | ||||||
|
Total
current assets
|
189,244 | 168,127 | ||||||
|
FIXED
ASSETS, at cost
|
373,927 | 349,212 | ||||||
|
Less: Accumulated
depreciation
|
(89,040 | ) | (67,107 | ) | ||||
|
Net
fixed assets
|
284,887 | 282,105 | ||||||
|
NET
INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income - related
party
|
173,027 | 177,203 | ||||||
|
CO
2
ASSETS, net of amortization
|
20,105 | 24,379 | ||||||
|
EQUITY
INVESTEES AND OTHER INVESTMENTS
|
15,128 | 19,468 | ||||||
|
INTANGIBLE
ASSETS, net of amortization
|
136,330 | 166,933 | ||||||
|
GOODWILL
|
325,046 | 325,046 | ||||||
|
OTHER
ASSETS, net of amortization
|
4,360 | 15,413 | ||||||
|
TOTAL
ASSETS
|
$ | 1,148,127 | $ | 1,178,674 | ||||
|
LIABILITIES
AND PARTNERS' CAPITAL
|
||||||||
|
CURRENT
LIABILITIES:
|
||||||||
|
Accounts
payable - trade
|
$ | 114,428 | $ | 96,454 | ||||
|
Accounts
payable - related party
|
3,197 | 3,105 | ||||||
|
Accrued
liabilities
|
23,803 | 26,713 | ||||||
|
Total
current liabilities
|
141,428 | 126,272 | ||||||
|
LONG-TERM
DEBT
|
366,900 | 375,300 | ||||||
|
DEFERRED
TAX LIABILITIES
|
15,167 | 16,806 | ||||||
|
OTHER
LONG-TERM LIABILITIES
|
5,699 | 2,834 | ||||||
|
COMMITMENTS
AND CONTINGENCIES (Note 20)
|
||||||||
|
PARTNERS'
CAPITAL:
|
||||||||
|
Common
unitholders, 39,488 and 39,457 units issued and outstanding at December
31, 2009 and 2008, respectively
|
585,554 | 616,971 | ||||||
|
General
partner
|
11,152 | 16,649 | ||||||
|
Accumulated
other comprehensive loss
|
(829 | ) | (962 | ) | ||||
|
Total
Genesis Energy, L.P. partners' capital
|
595,877 | 632,658 | ||||||
|
Noncontrolling
interests
|
23,056 | 24,804 | ||||||
|
Total
partners' capital
|
618,933 | 657,462 | ||||||
|
TOTAL
LIABILITIES AND PARTNERS' CAPITAL
|
$ | 1,148,127 | $ | 1,178,674 | ||||
The
accompanying notes are an integral part of these consolidated financial
statements.
|
GENESIS
ENERGY, L.P.
|
||||||||||||
|
|
||||||||||||
|
(In
thousands, except per unit amounts)
|
||||||||||||
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
REVENUES:
|
||||||||||||
|
Supply
and logistics:
|
||||||||||||
|
Unrelated
parties
|
$ | 1,222,914 | $ | 1,847,575 | $ | 1,092,398 | ||||||
|
Related
parties
|
3,924 | 4,839 | 1,791 | |||||||||
|
Refinery
services
|
141,365 | 225,374 | 62,095 | |||||||||
|
Pipeline
transportation, including natural gas sales:
|
||||||||||||
|
Transportation
services - unrelated parties
|
16,097 | 19,469 | 17,153 | |||||||||
|
Transportation
services - related parties
|
32,590 | 21,730 | 5,754 | |||||||||
|
Natural
gas sales revenues
|
2,264 | 5,048 | 4,304 | |||||||||
|
CO
2
marketing:
|
||||||||||||
|
Unrelated
parties
|
13,339 | 15,423 | 13,376 | |||||||||
|
Related
parties
|
2,867 | 2,226 | 2,782 | |||||||||
|
Total
revenues
|
1,435,360 | 2,141,684 | 1,199,653 | |||||||||
|
COSTS
AND EXPENSES:
|
||||||||||||
|
Supply
and logistics costs:
|
||||||||||||
|
Product
costs - unrelated parties
|
1,114,055 | 1,736,637 | 1,041,637 | |||||||||
|
Product
costs - related parties
|
1,754 | - | 101 | |||||||||
|
Operating
costs
|
82,262 | 78,453 | 37,121 | |||||||||
|
Refinery
services operating costs
|
88,910 | 166,096 | 40,197 | |||||||||
|
Pipeline
transportation costs:
|
||||||||||||
|
Pipeline
transportation operating costs
|
10,954 | 10,306 | 10,054 | |||||||||
|
Natural
gas purchases
|
2,070 | 4,918 | 4,122 | |||||||||
|
CO
2
marketing costs:
|
||||||||||||
|
Transportation
costs - related party
|
5,763 | 6,424 | 5,213 | |||||||||
|
Other
costs
|
62 | 60 | 152 | |||||||||
|
General
and administrative
|
40,413 | 29,500 | 25,920 | |||||||||
|
Depreciation
and amortization
|
62,581 | 71,370 | 38,747 | |||||||||
|
Net
loss on disposal of surplus assets
|
160 | 29 | 266 | |||||||||
|
Impairment
expense
|
5,005 | - | 1,498 | |||||||||
|
Total
costs and expenses
|
1,413,989 | 2,103,793 | 1,205,028 | |||||||||
|
OPERATING
INCOME (LOSS)
|
21,371 | 37,891 | (5,375 | ) | ||||||||
|
Equity
in earnings of joint ventures
|
1,547 | 509 | 1,270 | |||||||||
|
Interest
income
|
70 | 458 | 385 | |||||||||
|
Interest
expense
|
(13,730 | ) | (13,395 | ) | (10,485 | ) | ||||||
|
Income
(loss) before income taxes
|
9,258 | 25,463 | (14,205 | ) | ||||||||
|
Income
tax (expense) benefit
|
(3,080 | ) | 362 | 654 | ||||||||
|
NET
INCOME (LOSS)
|
6,178 | 25,825 | (13,551 | ) | ||||||||
|
Net
loss attributable to noncontrolling interests
|
1,885 | 264 | 1 | |||||||||
|
NET
INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.
|
$ | 8,063 | $ | 26,089 | $ | (13,550 | ) | |||||
|
GENESIS
ENERGY, L.P.
|
||||||||||||
|
CONSOLIDATED
STATEMENTS OF OPERATIONS - CONTINUED
|
||||||||||||
|
(In
thousands, except per unit amounts)
|
||||||||||||
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
NET
INCOME (LOSS) ATTRIBUTABLE TO
|
||||||||||||
|
GENESIS
ENERGY, L.P. PER COMMON UNIT:
|
||||||||||||
|
BASIC
|
$ | 0.51 | $ | 0.59 | $ | (0.66 | ) | |||||
|
DILUTED
|
$ | 0.51 | $ | 0.59 | $ | (0.66 | ) | |||||
|
WEIGHTED
AVERAGE OUTSTANDING COMMON UNITS:
|
||||||||||||
|
BASIC
|
39,471 | 38,961 | 20,754 | |||||||||
|
DILUTED
|
39,603 | 39,025 | 20,754 | |||||||||
The
accompanying notes are an integral part of these consolidated financial
statements.
|
GENESIS
ENERGY, L.P.
|
||||||||||||
|
CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
|
||||||||||||
|
(In
thousands)
|
||||||||||||
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Net
income (loss)
|
$ | 6,178 | $ | 25,825 | $ | (13,551 | ) | |||||
|
Change
in fair value of derivatives:
|
||||||||||||
|
Current
period reclassification to earnings
|
784 | 33 | - | |||||||||
|
Changes
in derivative financial instruments - interest rate swaps
|
(508 | ) | (1,997 | ) | - | |||||||
|
Comprehensive
income (loss)
|
6,454 | 23,861 | (13,551 | ) | ||||||||
|
Comprehensive
loss attributable to noncontrolling interests
|
1,742 | 1,266 | 1 | |||||||||
|
Comprehensive
income (loss) attributable to Genesis Energy, L.P.
|
$ | 8,196 | $ | 25,127 | $ | (13,550 | ) | |||||
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
|
||||||||||||||||||||||||
|
Accumulated
|
||||||||||||||||||||||||
|
Number
of
|
Other
|
Non-
|
||||||||||||||||||||||
|
Common
|
Common
|
General
|
Comprehensive
|
controlling
|
||||||||||||||||||||
|
Units
|
Unitholders
|
Partner
|
Loss
|
Interests
|
Total
|
|||||||||||||||||||
|
Partners'
capital, January 1, 2007
|
13,784 | $ | 83,884 | $ | 1,778 | $ | - | $ | 522 | $ | 86,184 | |||||||||||||
|
Comprehensive
income:
|
||||||||||||||||||||||||
|
Net
loss
|
- | (13,279 | ) | (271 | ) | - | (1 | ) | (13,551 | ) | ||||||||||||||
|
Cash
contributions
|
- | - | 1,412 | - | - | 1,412 | ||||||||||||||||||
|
Contribution
for management compensation (Note 12)
|
- | - | 3,434 | - | - | 3,434 | ||||||||||||||||||
|
Cash
distributions
|
- | (16,743 | ) | (432 | ) | - | (2 | ) | (17,177 | ) | ||||||||||||||
|
Issuance
of units
|
24,469 | 561,403 | 10,618 | - | 51 | 572,072 | ||||||||||||||||||
|
Partners'
capital, December 31, 2007
|
38,253 | 615,265 | 16,539 | - | 570 | 632,374 | ||||||||||||||||||
|
Comprehensive
income:
|
||||||||||||||||||||||||
|
Net
income
|
- | 23,485 | 2,604 | - | (264 | ) | 25,825 | |||||||||||||||||
|
Interest
rate swap losses reclassified to interest expense
|
- | - | - | 16 | 17 | 33 | ||||||||||||||||||
|
Interest
rate swap loss
|
- | - | - | (978 | ) | (1,019 | ) | (1,997 | ) | |||||||||||||||
|
Cash
contributions
|
- | - | 511 | - | 25,505 | 26,016 | ||||||||||||||||||
|
Cash
distributions
|
- | (47,529 | ) | (3,005 | ) | - | (5 | ) | (50,539 | ) | ||||||||||||||
|
Issuance
of units
|
2,037 | 41,667 | - | - | - | 41,667 | ||||||||||||||||||
|
Unit
based compensation expense
|
5 | 750 | - | - | - | 750 | ||||||||||||||||||
|
Redemption
of units
|
(838 | ) | (16,667 | ) | - | - | - | (16,667 | ) | |||||||||||||||
|
Partners'
capital, December 31, 2008
|
39,457 | 616,971 | 16,649 | (962 | ) | 24,804 | 657,462 | |||||||||||||||||
|
Comprehensive
income:
|
||||||||||||||||||||||||
|
Net
income
|
21,469 | (13,406 | ) | - | (1,885 | ) | 6,178 | |||||||||||||||||
|
Interest
rate swap losses reclassified to interest expense
|
383 | 401 | 784 | |||||||||||||||||||||
|
Interest
rate swap loss
|
(250 | ) | (258 | ) | (508 | ) | ||||||||||||||||||
|
Cash
contributions
|
9 | 9 | ||||||||||||||||||||||
|
Contribution
for management compensation (Note 12)
|
14,104 | 14,104 | ||||||||||||||||||||||
|
Cash
distributions
|
(53,876 | ) | (6,204 | ) | (6 | ) | (60,086 | ) | ||||||||||||||||
|
Unit
based compensation expense
|
31 | 990 | 990 | |||||||||||||||||||||
|
Partners'
capital, December 31, 2009
|
39,488 | $ | 585,554 | $ | 11,152 | $ | (829 | ) | $ | 23,056 | $ | 618,933 | ||||||||||||
The
accompanying notes are an integral part of these consolidated financial
statements.
|
GENESIS
ENERGY, L.P.
|
||||||||||||
|
|
||||||||||||
|
(In
thousands)
|
||||||||||||
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
||||||||||||
|
Net
income (loss)
|
$ | 6,178 | $ | 25,825 | $ | (13,551 | ) | |||||
|
Adjustments
to reconcile net income (loss) to net cash provided by operating
activities -
|
||||||||||||
|
Depreciation,
amortization and impairment
|
67,586 | 71,370 | 40,245 | |||||||||
|
Amortization
and write-off of credit facility issuance costs
|
2,503 | 1,437 | 779 | |||||||||
|
Amortization
of unearned income and initial direct costs on direct financing
leases
|
(18,095 | ) | (10,892 | ) | (620 | ) | ||||||
|
Payments
received under direct financing leases
|
21,853 | 11,519 | 1,188 | |||||||||
|
Equity
in earnings of investments in joint ventures
|
(1,547 | ) | (509 | ) | (1,270 | ) | ||||||
|
Distributions
from joint ventures - return on investment
|
950 | 1,272 | 1,845 | |||||||||
|
Non-cash
effect of unit-based compensation plans
|
4,248 | (2,063 | ) | 910 | ||||||||
|
Non-cash
compensation charge
|
14,104 | - | 3,434 | |||||||||
|
Deferred
and other tax liabilities
|
1,914 | (2,771 | ) | (2,658 | ) | |||||||
|
Other
non-cash items
|
(46 | ) | 882 | 347 | ||||||||
|
Net
changes in components of operating assets and liabilities, net of working
capital acquired (See Note 15)
|
(9,569 | ) | (1,262 | ) | 3,280 | |||||||
|
Net
cash provided by operating activities
|
90,079 | 94,808 | 33,929 | |||||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
||||||||||||
|
Payments
to acquire fixed and intangible assets
|
(30,332 | ) | (37,354 | ) | (8,235 | ) | ||||||
|
CO
2
pipeline transactions and related costs
|
- | (228,891 | ) | - | ||||||||
|
Distributions
from joint ventures - return of investment
|
- | 886 | 395 | |||||||||
|
Investments
in joint ventures and other investments
|
(83 | ) | (2,397 | ) | (1,104 | ) | ||||||
|
Acquisition
of Grifco assets
|
- | (65,693 | ) | - | ||||||||
|
Acquisition
of Davison assets, net of cash acquired
|
- | (993 | ) | (301,640 | ) | |||||||
|
Acquisition
of Port Hudson assets
|
- | - | (8,103 | ) | ||||||||
|
Other,
net
|
1,182 | 718 | (2,655 | ) | ||||||||
|
Net
cash used in investing activities
|
(29,233 | ) | (333,724 | ) | (321,342 | ) | ||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
||||||||||||
|
Bank
borrowings
|
255,300 | 531,712 | 392,200 | |||||||||
|
Bank
repayments
|
(263,700 | ) | (236,412 | ) | (320,200 | ) | ||||||
|
Repayment
to Grifco of seller-financing of asset acquisition
|
(6,000 | ) | (6,000 | ) | - | |||||||
|
Credit
facility issuance fees
|
(422 | ) | (2,255 | ) | (2,297 | ) | ||||||
|
Issuance
of common units for cash
|
- | - | 231,433 | |||||||||
|
Redemption
of common units for cash
|
- | (16,667 | ) | - | ||||||||
|
General
partner contributions
|
9 | 511 | 12,030 | |||||||||
|
Noncontrolling
interests contributions, net of distributions
|
(6 | ) | 25,500 | 49 | ||||||||
|
Distributions
to common unitholders
|
(53,876 | ) | (47,529 | ) | (16,743 | ) | ||||||
|
Distributions
to general partner interest
|
(6,204 | ) | (3,005 | ) | (432 | ) | ||||||
|
Other,
net
|
(784 | ) | 195 | 906 | ||||||||
|
Net
cash (used in) provided by financing activities
|
(75,683 | ) | 246,050 | 296,946 | ||||||||
|
Net
(decrease) increase in cash and cash equivalents
|
(14,837 | ) | 7,134 | 9,533 | ||||||||
|
Cash
and cash equivalents at beginning of period
|
18,985 | 11,851 | 2,318 | |||||||||
|
Cash
and cash equivalents at end of period
|
$ | 4,148 | $ | 18,985 | $ | 11,851 | ||||||
The
accompanying notes are an integral part of these consolidated financial
statements.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization
We are a
growth-oriented limited partnership focused on the midstream segment of the oil
and gas industry in the Gulf Coast area of the United States. We
conduct our operations through our operating subsidiaries and joint
ventures. We manage our businesses through four
divisions:
|
|
·
|
Pipeline
transportation of crude oil and carbon dioxide (or CO
2)
;
|
|
|
·
|
Refinery
services involving processing of high sulfur (or “sour”) gas streams for
refineries to remove the sulfur, and sale of the related by-product,
sodium hydrosulfide (or NaHS, commonly pronounced nash) and supplying
caustic soda (or NaOH);
|
|
|
·
|
Supply
and logistics services, which includes terminaling, blending, storing,
marketing, and transporting by trucks and barge of crude oil and petroleum
products; and
|
|
|
·
|
Industrial
gas activities, including wholesale marketing of CO
2
and
processing of syngas through a joint
venture.
|
Our
2% general partner interest is held by Genesis Energy, LLC, a Delaware limited
liability company and an indirect, majority-owned subsidiary of Denbury
Resources Inc. Denbury and its subsidiaries are hereafter referred to
as Denbury. Our general partner and its affiliates also own 10.2% of
our outstanding common units. In February 2010, Denbury sold our
general partner interest to the Quintana-Controlled Owner Group. See
Note 23.
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, 2009 and 2008 and our results of
operations, cash flows and changes in partners’ capital for the years ended
December 31, 2009, 2008 and 2007. All intercompany transactions have
been eliminated. The accompanying Consolidated Financial Statements
include Genesis Energy, L.P. and its operating subsidiaries, Genesis Crude Oil,
L.P. and Genesis NEJD Holdings, LLC, and their subsidiaries.
In
July 2007, we acquired the energy-related businesses of the Davison
family. See Note 3. The results of the operations of these
businesses have been included in our Consolidated Financial Statements since
August 1, 2007.
Except
per unit amounts, or as noted within the context of each footnote disclosure,
the dollar amounts presented in the tabular data within these footnote
disclosures are stated in thousands of dollars.
Subsequent
Events
We have
considered subsequent events through February 25, 2010, the date of issuance, in
preparing the Consolidated Financial Statements and notes thereto.
Joint
Ventures
We
participate in three joint ventures: DG Marine Transportation, LLC
(DG Marine), T&P Syngas Supply Company (T&P Syngas) and Sandhill Group,
LLC (Sandhill). As of the acquisition date in July 2008, DG Marine is
consolidated in our financial statements. We account for our 50%
investments in T&P Syngas and Sandhill by the equity method of accounting.
See Notes 3, 4 and 9.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
DG Marine
Transportation, LLC
In July
2008, we acquired an interest in DG Marine which acquired the inland marine
transportation business of Grifco Transportation, Ltd and two of its
affiliates. DG Marine is a joint venture with TD Marine, LLC, an
entity owned by members of the Davison family. We own an effective
49% economic interest and TD Marine, LLC owns a 51% economic interest in DG
Marine. The day-to-day operations are conducted by and managed by DG
Marine employees.
T&P
Syngas Supply Company
We
own a 50% interest in T&P Syngas, a Delaware general
partnership. Praxair Hydrogen Supply Inc. (“Praxair”) owns the
remaining 50% partnership interest in T&P Syngas. T&P Syngas
is a partnership that owns a syngas manufacturing facility located in Texas
City, Texas. That facility processes natural gas to produce syngas (a
combination of carbon monoxide and hydrogen) and high pressure
steam. Praxair provides the raw materials to be processed and
receives the syngas and steam produced by the facility under a long-term
processing agreement. T&P Syngas receives a processing fee for
its services. Praxair operates the facility.
Sandhill
Group, LLC
We own a
50% interest in Sandhill. Reliant Processing Ltd. holds the other 50%
interest in Sandhill. Sandhill owns a CO
2
processing
facility located in Brandon, Mississippi. Sandhill is engaged in the production
and distribution of liquid carbon dioxide for use in the food, beverage,
chemical and oil industries. The facility acquires CO
2
from us
under a long-term supply contract that we acquired in 2005 from
Denbury.
Noncontrolling
Interests
Our
general partner owns a 0.01% general partner interest in Genesis Crude Oil, L.P.
and TD Marine, LLC, a related party, owns the remaining 51% economic interest in
DG Marine. The net interest of those parties in our results of
operations and financial position are reflected in our Consolidated Financial
Statements as noncontrolling interests.
Use
of Estimates
The
preparation of our Consolidated Financial Statements requires us to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities, if any, at the
date of the Consolidated Financial Statements and the reported amounts of
revenues and expenses during the reporting period. We based these
estimates and assumptions on historical experience and other information that we
believed to be reasonable under the circumstances. Significant
estimates that we make include: (1) estimated useful lives of assets, which
impacts depreciation and amortization, (2) liability and contingency accruals,
(3) estimated fair value of assets and liabilities acquired and identification
of associated goodwill and intangible assets, (4) estimates of future net cash
flows from assets for purposes of determining whether impairment of those assets
has occurred, and (5) estimates of future asset retirement
obligations. Additionally, for purposes of the calculation of the
fair value of awards under equity-based compensation plans, we make estimates
regarding the expected life of the rights, expected forfeiture rates of the
rights, volatility of our unit price and expected future distribution yield on
our units. While we believe these estimates are reasonable, actual
results could differ from these estimates.
Cash
and Cash Equivalents
Cash and
cash equivalents consist of all demand deposits and funds invested in highly
liquid instruments with original maturities of three months or
less. The Partnership has no requirement for compensating balances or
restrictions on cash. We periodically assess the financial condition
of the institutions where these funds are held and believe that our credit risk
is minimal.
Accounts
Receivable
Our
accounts receivable are primarily from purchasers of crude oil and petroleum
products, and, to a lesser extent, purchasers of NaHS and CO
2
. These
purchasers include refineries, marketing and trading companies. The
majority of our accounts receivable relate to our supply and logistics
activities that can be described as high volume and low margin
activities.
Recent
volatility in the financial markets combined with significant energy price
volatility has caused liquidity issues impacting many companies, which in turn
have increased the potential credit risks associated with certain counterparties
with which we do business. We utilize our credit review process to
monitor these conditions and to make a determination with respect to the amount,
if any, of credit to be extended to any given customer and the form and amount
of financial performance assurances we require.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
We review
our outstanding accounts receivable balances on a regular basis and record a
reserve for amounts that we expect will not be fully
recovered. Actual balances are not applied against the reserve until
substantially all collection efforts have been exhausted.
The
following table presents the activity of our allowance for doubtful accounts for
the years ended December 31, 2009 and 2008:
|
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Balance
at beginning of period
|
$ | 1,132 | $ | - | ||||
|
Charged
to costs and expenses
|
558 | 1,152 | ||||||
|
Amounts
written off
|
(320 | ) | (20 | ) | ||||
|
Recoveries
|
2 | - | ||||||
|
Balance
at end of period
|
$ | 1,372 | $ | 1,132 | ||||
There was
no allowance for doubtful accounts in 2007.
Inventories
Crude oil
and petroleum products inventories held for sale are valued at the lower of
average cost or market. Fuel inventories are carried at the lower of
cost or market. Caustic soda and NaHS inventories are stated at the
lower of cost or market. Cost is determined principally under the average cost
method within specific inventory pools.
Fixed
Assets
Property
and equipment are carried at cost. Depreciation of property and
equipment is provided using the straight-line method over the respective
estimated useful lives of the assets. Asset lives are 5 to 15 years
for pipelines and related assets, 25 years for push boats and barges, 10 to 20
years for machinery and equipment, 40 years for tanks, 3 to 7 years for vehicles
and transportation equipment, and 3 to 10 years for buildings, office equipment,
furniture and fixtures and other equipment.
Interest
is capitalized in connection with the construction of major
facilities. The capitalized interest is recorded as part of the asset
to which it relates and is amortized over the asset’s estimated useful
life.
Maintenance
and repair costs are charged to expense as incurred. Costs incurred
for major replacements and upgrades are capitalized and depreciated over the
remaining useful life of the asset.
Certain
volumes of crude oil are classified in fixed assets, as they are necessary to
ensure efficient and uninterrupted operations of the gathering
businesses. These crude oil volumes are carried at their weighted
average cost.
Long-lived
assets are reviewed for impairment. An asset is tested for impairment
when events or circumstances indicate that its carrying value may not be
recoverable. The carrying value of a long-lived asset is not
recoverable if it exceeds the sum of the undiscounted cash flows expected to be
generated from the use and ultimate disposal of the asset. If the
carrying value is determined to not be recoverable under this method, an
impairment charge equal to the amount the carrying value exceeds the fair value
is recognized. Fair value is generally determined from estimated
discounted future net cash flows.
Asset
Retirement Obligations
Some of
our assets have contractual or regulatory obligations to perform dismantlement
and removal activities, and in some instances remediation, when the assets are
abandoned. In general, our future asset retirement obligations relate
to future costs associated with the removal of our oil, natural gas and CO
2
pipelines,
barge decommissioning, removal of equipment and facilities from leased acreage
and land restoration. The fair value of a liability for an asset retirement
obligation is recorded in the period in which it is incurred, discounted to its
present value using our credit adjusted risk-free interest rate, and a
corresponding amount capitalized by increasing the carrying amount of the
related long-lived asset. The capitalized cost is depreciated over the useful
life of the related asset. Accretion of the discount increases the
liability and is recorded to expense. See Note 6.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
Direct
Financing Leasing Arrangements
When a
direct financing lease is consummated, we record the gross finance receivable,
unearned income and the estimated residual value of the leased
pipelines. Unearned income represents the excess of the gross
receivable plus the estimated residual value over the costs of the
pipelines. Unearned income is recognized as financing income using
the interest method over the term of the transaction and is included in pipeline
revenue in the Consolidated Statements of Operations. The pipeline
cost is not included in fixed assets. See Note 7.
CO
2
Assets
Our
CO
2
assets include three volumetric production payments and long-term contracts to
sell the CO
2
volume. The contract values are being amortized on a
units-of-production method. See Note 8.
Intangible
Assets
Intangible
assets with finite useful lives are amortized over their respective estimated
useful lives. If an intangible asset has a finite useful life, but
the precise length of that life is not known, that intangible asset shall be
amortized over the best estimate of its useful life. At a minimum, we
will assess the useful lives and residual values of all intangible assets on an
annual basis to determine if adjustments are required. We are
recording amortization of our customer and supplier relationships, licensing
agreements and trade name based on the period over which the asset is expected
to contribute to our future cash flows. Generally, the contribution
of these assets to our cash flows is expected to decline over time, such that
greater value is attributable to the periods shortly after the acquisition was
made. The favorable lease and other intangible assets are being
amortized on a straight-line basis.
We test
intangible assets periodically to determine if impairment has
occurred. An impairment loss is recognized for intangibles if the
carrying amount of an intangible asset is not recoverable and its carrying
amount exceeds its fair value. No impairment has occurred of
intangible assets in any of the periods presented.
Goodwill
Goodwill
represents the excess of purchase price over fair value of net assets
acquired. 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. No goodwill impairment has
occurred in any of the periods presented. See Note 10.
Environmental
Liabilities
We
provide for the estimated costs of environmental contingencies when liabilities
are probable to occur and a reasonable estimate of the associated costs can be
made. Ongoing environmental compliance costs, including maintenance
and monitoring costs, are charged to expense as incurred.
Equity-Based
Compensation
The
compensation cost associated with our stock appreciation rights plan, which will
result in the payment of cash to the employee upon exercise, is re-measured each
reporting period. The liability and related compensation cost is
calculated using a fair value method that takes into consideration the expected
future value of the rights at their expected exercise dates.
Our 2007
Long-term Incentive Plan provides for awards of phantom units to our
non-employee directors and to the employees of our general
partner. The compensation cost related to phantom units issued
under our 2007 Long-term Incentive Plan is recognized in our Consolidated
Financial Statements based on estimated fair value at the date of the
grant. See Note 16.
On
December 31, 2008, our general partner awarded Class B Membership Interests in
our general partner to our senior executives. The compensation cost
related to these interests is re-measured at each reporting date based on the
fair value of the interests, and changes in that fair value are recognized over
the vesting period. Recorded expense will be subsequently adjusted to fair value
until final settlement. See Note 16.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
Revenue
Recognition
Product
Sales - Revenues from the sale of crude oil and petroleum products by our supply
and logistics segment, natural gas by our pipeline transportation segment, and
caustic soda and NaHS by our refinery services segment are recognized when title
to the inventory is transferred to the customer, collectability is reasonably
assured and there are no further significant obligations for future performance
by us. Most frequently, title transfers upon our delivery of the
inventory to the customer at a location designated by the customer, although in
certain situations, title transfers when the inventory is loaded for
transportation to the customer. Our crude oil, natural gas and
petroleum products are typically sold at prices based off daily or monthly
published prices. Many of our contracts for sales of NaHS incorporate
the price of caustic soda in the pricing formulas.
Pipeline
Transportation - Revenues from transportation of crude oil or natural gas by our
pipelines are based on actual volumes at a published tariff. Tariff
revenues are recognized either at the point of delivery or at the point of
receipt pursuant to the specifications outlined in our regulated
tariffs.
In order
to compensate us for bearing the risk of volumetric losses in volumes that occur
to crude oil in our pipelines due to temperature, crude quality and the inherent
difficulties of measurement of liquids in a pipeline, our tariffs include the
right for us to make volumetric deductions from the shippers for quality and
volumetric fluctuations. We refer to these deductions as pipeline
loss allowances.
We
compare these allowances to the actual volumetric gains and losses of the
pipeline and the net gain or loss is recorded as revenue or expense, based on
prevailing market prices at that time. When net gains occur, we have
crude oil inventory. When net losses occur, we reduce any recorded
inventory on hand and record a liability for the purchase of crude oil that we
must make to replace the lost volumes. We reflect inventories in the
Consolidated Financial Statements at the lower of the recorded value or the
market value at the balance sheet date. We value liabilities to
replace crude oil at current market prices. The crude oil in
inventory can then be sold, resulting in additional revenue if the sales price
exceeds the inventory value.
Income
from direct financing leases is being recognized ratably over the term of the
leases and is included in pipeline revenues.
CO
2
Sales -
Revenues from CO
2
marketing
activities are recorded when title transfers to the customer at the inlet meter
of the customer’s facility.
Cost
of Sales and Operating Expenses
Supply
and logistics costs and expenses include the cost to acquire the product and the
associated costs to transport it to our terminal facilities or to a customer for
sale. Other than the cost of the products, the most significant costs
we incur relate to transportation utilizing our fleet of trucks and barges,
including personnel costs, fuel and maintenance of our equipment.
When we
enter into buy/sell arrangements concurrently or in contemplation of one another
with a single counterparty, we reflect the amounts of revenues and purchases for
these transactions as a net amount in our Consolidated Statements of
Operations.
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 CO
2
marketing
activities consists of a transportation fee charged by Denbury to transport the
CO
2
to
the customer through Denbury’s pipeline and insurance costs. The
transportation fee charged by Denbury is adjusted annually for
inflation. For the years ended December 31, 2009, 2008 and 2007, the
fee averaged $0.2043, $0.1927, and $0.1848 per Mcf, respectively.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
Excise
and Sales Taxes
The
Company collects and remits excise and sales taxes to state and federal
governmental authorities on its sales of fuels. These taxes are
presented on a net basis, with any differences due to rebates allowed by those
governmental entities reflected as a reduction of product cost in the
Consolidated Statements of Operations.
Income
Taxes
We are a
limited partnership, organized as a pass-through entity for federal income tax
purposes. As such, we do not directly pay federal income tax. Our taxable income
or loss, which may vary substantially from the net income or net loss we report
in our Consolidated Statements of Operations, is includable in the federal
income tax returns of each partner.
Some of
our corporate subsidiaries pay U.S. federal, state, and foreign income taxes.
Deferred income tax assets and liabilities for certain operations conducted
through corporations are recognized for temporary differences between the assets
and liabilities for financial reporting and tax purposes. Changes in tax
legislation are included in the relevant computations in the period in which
such changes are effective. Deferred tax assets are reduced by a valuation
allowance for the amount of any tax benefit not expected to be
realized. Penalties and interest related to income taxes will be
included in income tax expense in the Consolidated Statements of
Operations.
Derivative
Instruments and Hedging Activities
We
minimize our exposure to price risk by limiting our inventory
positions. However when we hold inventory positions in crude oil and
petroleum products, we use derivative instruments to hedge exposure to price
risk. DG Marine uses interest rate swap contracts to manage its
exposure to interest rate risk.
Derivative
transactions, which can include forward contracts and futures positions on the
NYMEX, are recorded in the Consolidated Balance Sheets as assets and liabilities
based on the derivative’s fair value. Changes in the fair value of
derivative contracts are recognized currently in earnings unless specific hedge
accounting criteria are met. We must formally designate the
derivative as a hedge and document and assess the effectiveness of derivatives
associated with transactions that receive hedge
accounting. Accordingly, changes in the fair value of
derivatives are included in earnings in the current period for (i) derivatives
accounted for as fair value hedges; (ii) derivatives that do not qualify for
hedge accounting and (iii) the portion of cash flow hedges that is not highly
effective in offsetting changes in cash flows of hedged
items. Changes in the fair value of cash flow hedges are deferred in
Accumulated Other Comprehensive Income (“AOCI”) and reclassified into earnings
when the underlying position affects earnings. See Note
18.
Fair
Value of Current Assets and Current Liabilities
The
carrying amount of other current assets and other current
liabilities approximates their fair value due to their short-term
nature.
Net
Income Per Common Unit
Our net
income is first allocated to our general partner based on the amount of
incentive distributions to our general partner. We then allocate to
our general partner the amount of equity-based compensation costs which our
general partner has agreed to pay. The remainder is then allocated
98% to the limited partners and 2% to the general partner. Basic net
income per limited partner unit is determined by dividing net income
attributable to limited partners by the weighted average number of outstanding
limited partner units during the period. Diluted net income per
common unit is calculated in the same manner, but also considers the impact to
common units for the potential dilution from phantom units outstanding. (See
Note 16 for discussion of our equity-based compensation.)
In a
period of net operating losses, incremental phantom units are excluded from the
calculation of diluted earnings per unit due to their anti-dilutive effect.
During 2009 and 2008, we reported net income; therefore incremental phantom
units have been included in the calculation of diluted earnings per
unit.
Effective
January 1, 2009, we adopted new accounting guidance related to the consideration
of distributions paid by a master limited partnership, like us, to its general
and limited partners in the computation of earnings per unit.. See
“Recent and Proposed Accounting Announcements – Implemented in 2009”
below.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
Recent
and Proposed Accounting Pronouncements
Implemented
in 2009
Accounting
Standards Codification
In June
2009, the Financial Accounting Standards Board (FASB) issued Statement of
Financial Accounting Standards No. 168, “The FASB Accounting Standards
Codification and the Hierarchy of Generally Accepted Accounting Principles – a
replacement of FASB Statement No. 162,” (The Codification). The
Codification establishes the FASB Accounting Standards Codification (ASC) as the
source of authoritative U.S. generally accepted accounting principles (GAAP)
recognized by the FASB to be applied by nongovernmental entities. The
Codification reorganizes GAAP pronouncements by topic and modifies the GAAP
hierarchy to include only two levels: authoritative and
non-authoritative. All of the content in the Codification carries the
same level of authority. This statement was effective for financial
statements issued for interim and annual periods ending after September 15,
2009. We adopted the Codification on September 30,
2009. Thus, subsequent references to GAAP in our Consolidated
Financial Statements will refer exclusively to the Codification.
Recognized
and Non-Recognized Subsequent Events
In May
2009, the FASB issued new guidance for accounting for subsequent
events. The new guidance establishes the accounting for and
disclosures of events that occur after the balance sheet date but before
financial statements are issued or are available to be issued. It
requires the disclosure of the date through which an entity has evaluated
subsequent events and the basis for that date, that is, whether that date
represents the date the financial statements were issued or were available to be
issued. See “Subsequent Events” included in “Note 1 – Organization”
for the related disclosure. The new guidance was applied prospectively beginning
in the second quarter of 2009 and did not have a material impact on our
Consolidated Financial Statements.
Disclosures
about Fair Value of Financial Instruments
In April
2009, the FASB issued new guidance regarding interim disclosures about the fair
value of financial instruments. The new guidance requires fair value
disclosures on an interim basis for financial instruments that are not reflected
in the Consolidated Balance Sheets at fair value. Previously, the fair values of
those financial instruments were only disclosed on an annual basis. We adopted
the new guidance for our quarter ended June 30, 2009, and there was no material
impact on our Consolidated Financial Statements.
Business
Combinations
In
December 2007, the FASB issued revised guidance for the accounting of business
combinations. The revised guidance retains the purchase method of
accounting used in business combinations but replaces superseded guidance 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 revised guidance requires disclosures to
enable users of the financial statements to evaluate the nature and financial
effects of the business combination. The revised guidance applies to
acquisitions we make after December 31, 2008. The impact to us will
be dependent on the nature of the business combination.
Noncontrolling
Interests in Consolidated Financial Statements
In
December 2007, the FASB issued guidance regarding noncontrolling interests in
consolidated financial statements. The new guidance establishes accounting and
reporting standards for noncontrolling interests, which were 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. The new guidance 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. The provisions of the new guidance were effective for
fiscal years beginning after December 15, 2008. On January 1, 2009,
we adopted the new guidance which changed the presentation of the interests in
Genesis Crude Oil, L.P. held by our general partner and the interests in DG
Marine held by our joint venture partner in our Consolidated Financial
Statements. Amounts for prior periods have been changed to be
consistent with the presentation required by the new guidance.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
Derivative
Instruments and Hedging Activities
In March
2008, the FASB issued new guidance regarding disclosures about derivative
instruments and hedging activities. The new guidance requires enhanced
disclosures about our derivative and hedging activities. This guidance was
effective for financial statements issued for fiscal years and interim periods
beginning after November 15, 2008. We adopted the guidance on January 1, 2009
and have included the enhanced disclosures in Note 18. Adoption did
not have any material impact on our financial position, results of operations or
cash flows
Application
of the Two-Class Method to Master Limited Partnerships
In March
2008, the FASB issued new guidance regarding the application of the two-class
method of determining income per unit for master limited partnerships having
multiple classes of securities that may participate in partnership
distributions. Under this guidance, the computation of earnings per
unit is affected by the incentive distribution rights (“IDRs”) we are
contractually obligated to distribute at the end of the each reporting
period. In periods when earnings are in excess of cash distributions,
we reduce net income or loss for the current reporting period (for purposes of
calculating earnings or loss per unit only) by the amount of available cash that
will be distributed to our limited partners and general partner for its general
partner interest and incentive distribution rights for the reporting period, and
the remainder is allocated to the limited partner and general partner in
accordance with their ownership interests. When cash distributions
exceed current-period earnings, net income or loss (for purposes of calculating
earnings or loss per unit only) is reduced (or increased) by cash distributions,
and the resulting excess of distributions over earnings is allocated to the
general partner and limited partner based on their respective sharing of
losses. The new guidance was effective for fiscal years beginning
after December 15, 2008, and interim periods within those fiscal
years. We adopted the new guidance on January 1, 2009 and have
reflected the calculation of earnings per unit for the years ended December 31,
2009, 2008 and 2007 in accordance with its provisions. See Note
12.
Measuring
Liabilities and Fair Value
In August
2009, the FASB issued guidance that provides clarification to the valuation
techniques required to measure the fair value of liabilities. The guidance also
provides clarification around required inputs to the fair value measurement of a
liability and definition of a Level 1 liability. The guidance was effective for
interim and annual periods beginning after August 2009. We adopted this standard
beginning with our financial statements for the year ended December 31, 2009.
The adoption of this standard did not have a material effect on our financial
statements.
Implemented
January 1, 2010
Consolidation
of Variable Interest Entities (“VIEs”)
In June
2009, the FASB issued authoritative guidance to amend the manner in which
entities evaluate whether consolidation is required for VIEs. The
model for determining which enterprise has a controlling financial interest and
is the primary beneficiary of a VIE has changed significantly under the new
guidance. Previously, variable interest holders had to determine
whether they had a controlling interest in a VIE based on a quantitative
analysis of the expected gains and/or losses of the entity. In
contrast, the new guidance requires an enterprise with a variable interest in a
VIE to qualitatively assess whether it has a controlling interest in the entity,
and if so, whether it is the primary beneficiary. Furthermore, this
guidance requires that companies continually evaluate VIEs for consolidation,
rather than assessing based upon the occurrence of triggering
events. This revised guidance also requires enhanced disclosures
about how a company’s involvement with a VIE affects its financial statements
and exposure to risks. This guidance was effective for us beginning
January 1, 2010. We are currently assessing the impact this guidance
may have on our consolidated financial statements.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
3. Acquisitions
2008
DG Marine Transportation Investment
On July
18, 2008, DG Marine completed the acquisition of the inland marine
transportation business of Grifco Transportation, Ltd. (“Grifco”) and two of
Grifco’s affiliates. DG Marine is a joint venture we formed with TD
Marine, LLC, an entity owned by members of the Davison family. (See
discussion below on the acquisition of the Davison family businesses in 2007.).
TD Marine owns (indirectly) a 51% economic interest in the joint venture, DG
Marine, and we own (directly and indirectly) a 49% economic
interest. This acquisition gives us the capability to provide
transportation services of petroleum products by barge and complements our other
supply and logistics operations.
Grifco
received initial purchase consideration of approximately $80 million, comprised
of $63.3 million in cash and $16.7 million, or 837,690 of our common
units. A portion of the units are subject to certain lock-up
restrictions. DG Marine acquired substantially all of Grifco’s assets, including
twelve barges, seven push boats, certain commercial agreements, and
offices. Additionally, DG Marine and/or its subsidiaries
acquired the rights, and assumed the obligations, to take delivery of four new
barges in late third quarter of 2008 and four additional new barges late in
first quarter of 2009 (at a total price of approximately $27 million). Grifco
financed $12 million of additional purchase consideration that we agreed to pay
after we placed the eight new barges in service. At December 31,
2009, all of the seller-financed additional purchase price consideration was
paid.
The
Grifco acquisition and related closing costs were funded with $50 million of
aggregate equity contributions from us and TD Marine, in proportion to our
ownership percentages, and with borrowings of $32.4 million under a revolving
credit facility which is non-recourse to us and TD Marine (other than with
respect to our investments in DG Marine). Although DG
Marine’s debt is non-recourse to us, our ownership interest in DG Marine is
pledged to secure its indebtedness. We funded our $24.5 million equity
contribution with $7.8 million of cash and 837,690 of our common units, valued
at $19.896 per unit, for a total value of $16.7 million. At closing,
we also redeemed 837,690 of our common units from the Davison
family. See Notes 11 and 12.
We
entered into a subordinated loan agreement with DG Marine whereby we loaned $25
million to DG Marine. See Note 4.
Accounting
provisions require the primary beneficiary to consolidate variable interest
entities. In determining the primary beneficiary of a variable
interest entity ("VIE") that is held between two or more related parties the
primary beneficiary is considered to be the party that is "most closely
associated" with the VIE. We are considered to be the primary
beneficiary due to (i) our involvement in the design of DG Marine, (ii) the
ongoing involvement with regards to financial and operating decision making of
DG Marine, excluding matters related to new contracts and vessel disposal which
are decided solely by TD Marine, and (iii) the financial support we provide to
DG Marine. TD Marine has no requirements to make any additional
contributions to DG Marine.
As we are
considered the primary beneficiary, DG Marine is consolidated in our
Consolidated Financial Statements and the 51% ownership interest of TD Marine in
the net assets and net income of DG Marine is included in noncontrolling
interests in our Consolidated Financial Statements.
The
acquisition cost allocated to the assets consisted of $63.3 million of cash,
$16.7 million of value from the issuance of our limited partnership units to
Grifco, $11.7 million related to the discounted value of the additional
consideration that was owed to Grifco when the barges under construction were
placed in service and $2.4 million of transaction costs. The
acquisition cost was allocated to the assets acquired based on estimated fair
values. Such fair values were developed by management.
The
allocation of the acquisition cost is summarized as follows:
|
Property
and equipment
|
$ | 91,772 | ||
|
Amortizable
intangible assets:
|
||||
|
Customer
relationships
|
800 | |||
|
Trade
name
|
900 | |||
|
Non-compete
agreements
|
600 | |||
|
Total
allocated cost
|
$ | 94,072 |
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
The
weighted average amortization period for the intangible assets at the date of
acquisition is 10 years for customer relationships, 3 years for the trade name
and 7 years for the non-compete agreements. The weighted average
amortization period for all intangible assets acquired in the Grifco transaction
is 6 years.
See
additional information on intangible assets in Note 10.
2008
Denbury Drop-Down Transactions
On May
30, 2008, we completed two transactions with Denbury Onshore LLC, (Denbury
Onshore), a wholly-owned subsidiary of Denbury Resources Inc.
NEJD
Pipeline System
In 2008,
we entered into a twenty-year financing lease transaction with Denbury valued at
$175 million and related to the NEJD Pipeline System. The NEJD
Pipeline System is a 183-mile, 20” pipeline extending from the Jackson Dome,
near Jackson, Mississippi, to near Donaldsonville, Louisiana, and is currently
being leased and used by Denbury for its tertiary recovery operations in
southwest Mississippi. We recorded this lease arrangement in our
Consolidated Financial Statements as a direct financing lease. Under the terms
of the agreement, Denbury Onshore began making quarterly rent payments beginning
August 30, 2008. These quarterly rent payments are fixed at
$5,166,943 per quarter or approximately $20.7 million per year during the lease
term at an interest rate of 10.25%. At the end of the lease term, we
will convey all of our interests in the NEJD Pipeline to Denbury Onshore for a
nominal payment.
Denbury
has the rights to exclusive use of the NEJD Pipeline System, will be responsible
for all operations and maintenance on that system, and will bear and assume all
obligations and liabilities with respect to that system. The NEJD
transaction was funded with borrowings under our credit facility.
See
additional discussion of this direct financing lease in Note 7.
Free
State Pipeline System
We
purchased the Free State Pipeline for $75 million from Denbury, consisting of
$50 million in cash which we borrowed under our credit facility, and $25 million
in the form of 1,199,041 of our common units. The number of common
units issued was based on the average closing price of our common units from May
28, 2008 through June 3, 2008.
The Free
State Pipeline is an 86-mile, 20” pipeline that extends from CO
2
source
fields at Jackson Dome, near Jackson, Mississippi, to oil fields in east
Mississippi. We entered into a twenty-year transportation services
agreement to deliver CO
2
on the
Free State pipeline for use in tertiary recovery
operations. Under the terms of the transportation
services agreement, we are responsible for owning, operating, maintaining and
making improvements to that pipeline. Denbury currently has rights to
exclusive use of that pipeline and is required to use that pipeline to supply
CO
2
to
its current and certain of its other tertiary operations in east
Mississippi. The transportation services agreement provides for a
$100,000 per month minimum payment, which is accounted for as an operating
lease, plus a tariff based on throughput. Denbury has two renewal options, each
for five years on similar terms. Any sale by us of the Free State Pipeline and
related assets or of an ownership interest in our subsidiary that holds such
assets would be subject to a right of first refusal of Denbury.
2007
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. 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.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
The
Davison family is our largest unitholder, with approximately 30% 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
The
purchase price was allocated to the assets acquired and liabilities assumed
based on estimated fair values. Such fair values were developed by
management. The allocation of the purchase price is summarized as
follows:
|
Cash
and cash equivalents
|
$ | 21,686 | ||
|
Accounts
receivable
|
55,631 | |||
|
Inventories
|
10,825 | |||
|
Other
current assets
|
982 | |||
|
Other
assets
|
294 | |||
|
Property
and equipment
|
67,655 | |||
|
Goodwill
|
316,739 | |||
|
Amortizable
intangible assets:
|
||||
|
Customer
relationships
|
129,284 | |||
|
Supplier
agreements
|
36,469 | |||
|
Licensing
agreements
|
38,678 | |||
|
Trade
name
|
17,988 | |||
|
Covenants
not-to-compete
|
695 | |||
|
Favorable
lease agreement
|
13,260 | |||
|
Accounts
payable and accrued expenses
|
(35,230 | ) | ||
|
Deferred
tax liabilties assumed
|
(21,794 | ) | ||
|
Total
allocation
|
$ | 653,162 |
See
additional information on intangible assets and goodwill in Note
10. Goodwill represents the residual of the purchase price over the
fair value of net tangible and identifiable intangible assets
acquired.
The
following table presents selected unaudited pro forma financial information
incorporating the historical operating results of the Davison
businesses. The effective closing date of our purchase of the Davison
businesses was July 25, 2007. As a result, our Consolidated Statement
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 the 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.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
|
Year
Ended December 31,
|
||||
|
2007
|
||||
|
Pro
Forma Earnings Data:
|
||||
|
Revenue
|
$ | 1,574,730 | ||
|
Costs
and expenses
|
1,572,809 | |||
|
Operating
income
|
1,921 | |||
|
(Loss)
Income before extraordinary items
|
(29,666 | ) | ||
|
Net
(loss) income
|
(29,666 | ) | ||
|
Basic
and diluted (loss) earnings per unit:
|
||||
|
As
reported units outstanding
|
20,754 | |||
|
Pro
forma units outstanding
|
28,319 | |||
|
As
reported net (loss) income per unit
|
$ | (0.64 | ) | |
|
Pro
forma net (loss) income per unit
|
$ | (1.05 | ) | |
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 was 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 10.
4.
Consolidated Joint Venture - DG Marine
DG Marine
is a joint venture we formed with TD Marine. TD Marine owns (indirectly) a 51%
economic interest in DG Marine, and we own (directly and indirectly) a 49%
economic interest. This joint venture gives us the capability to
provide transportation services of petroleum products by barge and complements
our other supply and logistics operations.
We
entered into a subordinated loan agreement with DG Marine whereby we may (at our
sole discretion) lend up to $25 million to DG Marine. The loan
agreement provides for DG Marine to pay us interest on any loans at the prime
rate plus 4%. Those loans will mature on January 31,
2012. Under that subordinated loan agreement, DG Marine is required
to make monthly payments to us of principal and interest to the extent DG Marine
has any available cash that otherwise would have been distributed to the owners
of DG Marine in respect of their equity interest. DG Marine also has
a revolving credit facility with a syndicate of financial institutions that
includes restrictions on DG Marine’s ability to make specified payments under
our subordinated loan agreement and distributions in respect of our equity
interest. At December 31, 2009, $25 million was outstanding under the
subordinated loan agreement; however this amount and the associated interest
expense were eliminated in our Consolidated Financial Statements. No
payments have been made to us from DG Marine under the subordinated loan
agreement as of December 31, 2009. At December 31, 2008, there were
no amounts outstanding under the subordinated loan agreement.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
At
December 31, 2009 and 2008, our Consolidated Balance Sheets included the
following amounts related to DG Marine:
|
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Cash
|
$ | 585 | $ | 623 | ||||
|
Accounts
receivable - trade
|
3,216 | 2,812 | ||||||
|
Other
current assets
|
2,421 | 859 | ||||||
|
Fixed
assets, at cost
|
124,276 | 110,214 | ||||||
|
Accumulated
depreciation
|
(9,139 | ) | (3,084 | ) | ||||
|
Intangible
assets, net
|
1,758 | 2,208 | ||||||
|
Other
assets
|
1,174 | 2,178 | ||||||
|
Total
assets
|
$ | 124,291 | $ | 115,810 | ||||
|
Accounts
payable
|
$ | 1,788 | $ | 1,072 | ||||
|
Accrued
liabilities
|
3,601 | 9,258 | ||||||
|
Long-term
debt
|
46,900 | 55,300 | ||||||
|
Other
long-term liabilities
|
683 | 1,393 | ||||||
|
Total
liabilities
|
$ | 52,972 | $ | 67,023 | ||||
5. Inventories
The major
components of inventories were as follows:
|
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Crude
oil
|
13,901 | 1,878 | ||||||
|
Petroleum
products
|
22,150 | 5,589 | ||||||
|
Caustic
soda
|
1,985 | 7,139 | ||||||
|
NaHS
|
2,154 | 6,923 | ||||||
|
Other
|
14 | 15 | ||||||
|
Total
inventories
|
$ | 40,204 | $ | 21,544 | ||||
At
December 31, 2009, market values of our inventory exceeded recorded
costs. Our inventory at December 31, 2008 is reflected net of charges
totaling $1.2 million that we recorded to reduce the cost basis of our crude oil
and petroleum products inventory to reflect market value. The lower
of cost or market adjustment is included in “Product Costs” of our Supply &
Logistics segment on our Consolidated Statements of Operations.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
6. Fixed
Assets and Asset Retirement Obligations
Fixed
Assets
Fixed
assets consisted of the following.
|
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Land,
buildings and improvements
|
$ | 14,028 | $ | 13,549 | ||||
|
Pipelines
and related assets
|
156,274 | 139,184 | ||||||
|
Machinery
and equipment
|
27,016 | 22,899 | ||||||
|
Transportation
equipment
|
31,669 | 32,833 | ||||||
|
Barges
and push boats
|
122,913 | 96,865 | ||||||
|
Office
equipment, furniture and fixtures
|
4,412 | 4,401 | ||||||
|
Construction
in progress
|
4,813 | 27,906 | ||||||
|
Other
|
12,802 | 11,575 | ||||||
|
Subtotal
|
373,927 | 349,212 | ||||||
|
Accumulated
depreciation
|
(89,040 | ) | (67,107 | ) | ||||
|
Total
|
$ | 284,887 | $ | 282,105 | ||||
In 2009,
2008 and 2007, $112,000, $276,000 and $57,000 of interest cost, respectively,
were capitalized related to the construction of pipelines and related
assets.
Depreciation
expense was $25.2 million, $20.4 million and $8.9 million for the years ended
December 31, 2009, 2008, and 2007, 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 $1.5 million related to these assets.
Asset
Retirement Obligations
A
reconciliation of our liability for asset retirement obligations is as
follows:
|
Asset
retirement obligations as of December 31, 2007
|
$ | 1,173 | ||
|
Liabilities
incurred and assumed in the current period
|
121 | |||
|
Accretion
expense
|
136 | |||
|
Asset
retirement obligations as of December 31, 2008
|
1,430 | |||
|
Liabilities
incurred and assumed in the current period
|
726 | |||
|
Liabilities
settled in the current period
|
(117 | ) | ||
|
Accretion
expense
|
152 | |||
|
Revisions
in estimated cash flows
|
2,647 | |||
|
Asset
retirement obligations as of December 31, 2009
|
$ | 4,838 |
At
December 31, 2008, $0.2 million of our asset retirement obligation was
classified in “Accrued liabilities” under current liabilities in our
Consolidated Balance Sheets. Liabilities incurred and assumed during the period
are for properties acquired during the year. Certain of our
unconsolidated affiliates have asset retirement obligations recorded at December
31, 2009 and 2008 relating to contractual agreements. These amounts
are immaterial to our Consolidated Financial Statements.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
7. Net
Investment in Direct Financing Leases
As
discussed in Note 3, we entered into a lease arrangement with Denbury related to
the NEJD Pipeline in May 2008 that is being accounted for as a direct financing
lease. Denbury pays us fixed payments of $5.2 million per quarter
related to that lease that began in August 2008.
The
following table lists the components of the net investment in direct financing
leases:
|
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Total
minimum lease payments to be received
|
$ | 385,565 | $ | 407,392 | ||||
|
Estimated
residual values of leased property (unguaranteed)
|
1,287 | 1,287 | ||||||
|
Unamortized
initial direct costs
|
2,380 | 2,580 | ||||||
|
Less
unearned income
|
(212,003 | ) | (230,298 | ) | ||||
|
Net
investment in direct financing leases
|
$ | 177,229 | $ | 180,961 | ||||
At
December 31, 2009, minimum lease payments to be received for each of the five
succeeding fiscal years are $21.9 million per year for 2010 through 2011, $21.8
million for 2012, $21.3 million for 2013 and $21.2 million for
2014.
8. CO
2
Assets
CO
2
assets
consisted of the following.
|
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
CO
2
volumetric production payments
|
$ | 43,570 | $ | 43,570 | ||||
|
Less
- Accumulated amortization
|
(23,465 | ) | (19,191 | ) | ||||
|
Net
CO
2
assets
|
$ | 20,105 | $ | 24,379 | ||||
The
volumetric production payments entitle us to a maximum daily quantity of CO
2
of 91,875
million cubic feet, or 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, Denbury processes and delivers this CO
2
to our
industrial customers and receive a fee of $0.16 per Mcf, subject to inflationary
adjustments from us. During 2009 this fee averaged $0.2043 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 2011 and 2016, with one small contract extending until
2023.
The
CO
2
assets are being amortized on a units-of-production method. After
purchase price adjustments, we had 276.7 Bcf of CO
2
at
acquisition, and the total $43.6 million cost is being amortized based on the
volume of CO
2
sold each
month. For 2009, 2008 and 2007, we recorded amortization
of $4,274,000, $4,537,000 and $4,488,000, respectively. We have 127.0
Bcf of CO
2
remaining
under the volumetric production payments at December 31, 2009. Based
on the historical deliveries of CO
2
to the
customers (which have exceeded minimum take-or-pay volumes), we expect
amortization for the next five years to be approximately $4,274,000 for 2010,
$3,920,000 for 2011 and 2012 and $3,258,000 for 2013 and 2014.
9. Equity
Investees and Other Investments
Equity
Investees
We are
accounting for our 50% ownership in each of two joint ventures, T&P Syngas
and Sandhill under the equity method of accounting. We paid
$7.8 million more for our interest in these joint ventures than our share of
capital on their balance sheets at the date of the acquisition. This
excess amount of the purchase price over the equity in the joint ventures has
been allocated to the tangible and intangible assets of the joint ventures based
on the fair value of those assets, with the remainder of the excess purchase
price of $0.7 million allocated to goodwill. The table below reflects
information included in our Consolidated Financial Statements related to our
equity investees.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Genesis'
share of operating earnings
|
1,261 | 1,137 | 1,898 | |||||||||
|
Amortization
of excess purchase price
|
285 | (628 | ) | (628 | ) | |||||||
|
Net
equity in earnings
|
$ | 1,546 | $ | 509 | $ | 1,270 | ||||||
|
Distributions
received
|
$ | 950 | $ | 2,158 | $ | 2,240 | ||||||
Other
Projects
In 2006,
we invested in the Faustina Project, a petroleum coke to ammonia project that is
in the development stage. As a result of a review of the financing
alternatives for the project, requirements for continued funding for the project
and the change in control of our general partner in February 2010, we decided
not to fund our share of further development in the project. We
further determined that the likelihood of a recovery of our investment was
remote, and the fair value of the investment was zero. In 2009,
we recorded a $5.0 million impairment charge related to our investment in the
Faustina Project, reducing the value of that investment in our Consolidated
Balance Sheets at December 31, 2009 to zero. At December 31, 2008,
our Consolidated Balance Sheet included $4.9 million related to our investment
in the Faustina Project.
10. Intangible
Assets, Goodwill and Other Assets
Intangible
Assets
In
connection with the Davison and DG Marine acquisitions (See Note 3), we
allocated a portion of the purchase price to intangible assets based on their
fair values. The following table reflects the components of
intangible assets being amortized at December 31, 2009:
|
December 31,
2009
|
December 31,
2008
|
||||||||||||||||||||||||||
|
Weighted
Amortization Period in Years
|
Gross
Carrying Amount
|
Accumulated
Amortization
|
Carrying
Value
|
Gross
Carrying Amount
|
Accumulated
Amortization
|
Carrying
Value
|
|||||||||||||||||||||
|
Refinery
services customer relationships
|
5 | $ | 94,654 | $ | 41,450 | $ | 53,204 | $ | 94,654 | $ | 26,017 | $ | 68,637 | ||||||||||||||
|
Supply
and logistics customer relationships
|
5 | 35,430 | 15,493 | 19,937 | 35,430 | 9,957 | 25,473 | ||||||||||||||||||||
|
Refinery
services supplier relationships
|
2 | 36,469 | 28,551 | 7,918 | 36,469 | 24,483 | 11,986 | ||||||||||||||||||||
|
Refinery
services licensing agreements
|
6 | 38,678 | 11,681 | 26,997 | 38,678 | 7,176 | 31,502 | ||||||||||||||||||||
|
Supply
and logistics trade names - Davison and Grifco
|
7 | 18,888 | 5,444 | 13,444 | 18,888 | 3,118 | 15,770 | ||||||||||||||||||||
|
Supply
and logistics favorable lease
|
15 | 13,260 | 1,144 | 12,116 | 13,260 | 671 | 12,589 | ||||||||||||||||||||
|
Other
|
5 | 3,823 | 1,109 | 2,714 | 1,322 | 346 | 976 | ||||||||||||||||||||
|
Total
|
5 | $ | 241,202 | $ | 104,872 | $ | 136,330 | $ | 238,701 | $ | 71,768 | $ | 166,933 | ||||||||||||||
The
licensing agreements referred to in the table above relate to the agreements we
have with refiners to provide services. The trade names are the
Davison and Grifco names, which we retained the right to use in our
operations. The favorable lease relates to a lease of a terminal
facility in Shreveport, Louisiana.
We are
recording amortization of our intangible assets based on the period over which
the asset is expected to contribute to our future cash
flows. Generally, the contribution to our cash flows of the customer
and supplier relationships, licensing agreements and trade name intangible
assets is expected to decline over time, such that greater value is attributable
to the periods shortly after the acquisition was made. The favorable
lease and other intangible assets are being amortized on a straight-line
basis. Amortization expense on intangible assets was $33.1 million,
$46.4 million and $25.4 million for the years ended December 31, 2009, 2008 and
2007, respectively.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
The
following table reflects our estimated amortization expense for each of the five
subsequent fiscal years:
|
2010
|
2011
|
2012
|
2013
|
2014
|
||||||||||||||||
|
Refinery
services customer relationships
|
$ | 11,689 | $ | 8,972 | $ | 7,056 | $ | 7,116 | $ | 5,597 | ||||||||||
|
Supply
and logistics customer relationships
|
4,488 | 3,603 | 2,819 | 2,165 | 1,660 | |||||||||||||||
|
Refinery
services supplier relationships
|
2,925 | 2,629 | 2,364 | - | - | |||||||||||||||
|
Refinery
services licensing agreements
|
4,105 | 3,690 | 3,416 | 3,163 | 2,928 | |||||||||||||||
|
Supply
and logistics trade name
|
2,086 | 1,851 | 1,432 | 1,237 | 1,073 | |||||||||||||||
|
Supply
and logistics favorable lease
|
474 | 474 | 474 | 474 | 474 | |||||||||||||||
|
Other
|
869 | 700 | 701 | 110 | 58 | |||||||||||||||
|
Total
|
$ | 26,636 | $ | 21,919 | $ | 18,262 | $ | 14,265 | $ | 11,790 | ||||||||||
Goodwill
In
connection with the Davison and Port Hudson acquisitions (See Note 3), we
allocated the residual of the purchase price over the fair values of the net
tangible and identifiable intangible assets acquired to goodwill. The
carrying amount of goodwill by business segment at December 31, 2009 and 2008
was $301.9 million in refinery services and $23.1 million in supply and
logistics. We have not recognized any impairment losses related to
goodwill for any of the periods presented.
Other
Assets
Other
assets consisted of the following.
|
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Credit
facility fees - Genesis
|
$ | 5,022 | $ | 5,022 | ||||
|
Credit
facility fees - DG Marine
|
2,373 | 2,536 | ||||||
|
Initial
direct costs related to Free State Pipeline lease
|
1,132 | 1,132 | ||||||
|
Deferred
tax asset
|
- | 1,543 | ||||||
|
Other
deferred costs and deposits
|
131 | 7,502 | ||||||
| 8,658 | 17,735 | |||||||
|
Less
- Accumulated amortization
|
(4,298 | ) | (2,322 | ) | ||||
|
Net
other assets
|
$ | 4,360 | $ | 15,413 | ||||
Amortization
of the initial direct costs related to the Free State Pipeline lease for the
years ended December 31, 2009 and 2008 was $60,000 and $35,000,
respectively. Amortization expense of credit facility fees for the
years ended December 31, 2009, 2008 and 2007 was $1,917,000, $1,437,000 and
$779,000, respectively. In the fourth quarter of 2009, we
charged to expense $586,000 of unamortized fees related to the DG Marine credit
facility that we amended in November 2009. Additional fees of
$423,000 related to the amendment of the DG Marine facility were deferred in
November 2009 and will be amortized over the remaining term of the
facility. Total amortization of initial direct costs and credit
facility fees for the next five years will be $1,898,000 for 2010, $1,413,000
for 2011 and $60,000 per year for 2012 through 2014.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
At
December 31, 2009 our obligations under credit facilities consisted of the
following:
|
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Genesis
Credit Facility
|
$ | 320,000 | $ | 320,000 | ||||
|
DG
Marine Credit Facility (non-recourse to Genesis)
|
46,900 | 55,300 | ||||||
|
Total
Long-Term Debt
|
$ | 366,900 | $ | 375,300 | ||||
Genesis
Credit Facility
We have a
$500 million credit facility, $100 million of which can be used for letters of
credit, with a group of banks led by Fortis Capital Corp. and Deutsche Bank
Securities Inc. The borrowing base is recalculated quarterly and at
the time of material acquisitions. The borrowing base represents the
amount that can be borrowed or utilized for letters of credit from a credit
standpoint based on our EBITDA (earnings before interest, taxes, depreciation
and amortization), computed in accordance with the provisions of our credit
facility.
The
borrowing base may be increased to the extent of pro forma additional EBITDA, as
defined in the credit agreement, attributable to acquisitions or internal growth
projects with approval of the lenders. Our borrowing base as of
December 31, 2009 was $407 million.
At
December 31, 2009, we had $320 million borrowed under our credit facility and
$5.2 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, 2009
was $82 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, 2009, our borrowing rates were the prime rate plus 0.75% or the LIBOR
rate plus 1.75%.
|
|
|
·
|
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, 2009, our letter of credit rate was
1.75%.
|
|
|
·
|
We
pay a commitment fee on the unused portion of the $500 million maximum
facility amount. The commitment fee will range from 0.30% to
0.50% based on our leverage ratio as computed under the credit
facility. The rate can fluctuate quarterly. At
December 31, 2008, the commitment fee rate was
0.375%.
|
Collateral
under the credit facility consists of substantially all our assets, excluding
our interest in the NEJD pipeline, our ownership interest in the Free State
pipeline, and the assets of and our equity interest in DG Marine. All of the
equity interest of DG Marine is pledged to secure its credit facility, which is
described below. While our general partner is jointly and severally
liable for all of our obligations unless and except to the extent those
obligations provide that they are non-recourse to our general partner, our
credit facility expressly provides that it is non-recourse to our general
partner (except to the extent of its pledge of its general partner interest in
certain of our subsidiaries), as well as to Denbury and its other
subsidiaries.
Our
credit facility contains customary covenants (affirmative, negative and
financial) that limit the manner in which we may conduct our
business. Our credit facility contains three primary financial
covenants - a debt service coverage ratio, leverage ratio and funded
indebtedness to capitalization ratio – that require us to achieve specific
minimum financial metrics. In general, our debt service coverage
ratio calculation compares EBITDA (as defined and adjusted in accordance with
the credit facility) to interest expense. Our leverage ratio
calculation compares our consolidated funded debt (as calculated in accordance
with our credit facility) to EBITDA (as adjusted). Our funded
indebtedness ratio compares outstanding debt to the sum of our consolidated
total funded debt plus our consolidated net worth. Our credit
facility includes provisions for the temporary adjustment of the required ratios
following material acquisitions and with lender approval.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
|
Financial
Covenant
|
Requirement
|
Required
Ratio through December 31, 2009
|
Actual
Ratio as of December 31, 2009
|
|||
|
Debt
Service Coverage Ratio
|
Minimum
|
3.00
to 1.0
|
13.93
to 1.0
|
|||
|
Leverage
Ratio
|
Maximum
|
5.50
to 1.0
|
3.22
to 1.0
|
|||
|
Funded
Indebtedness Ratio
|
Maximum
|
0.65
to 1.0
|
0.40
to 1.0
|
If we
meet these financial metrics and are not otherwise in default under our credit
facility, we may make quarterly distributions; however, the amount of such
distributions may not exceed the sum of the distributable cash (as defined in
the credit facility) generated by us for the eight most recent quarters, less
the sum of the distributions made with respect to those quarters. At
December 31, 2009, the excess of distributable cash over distributions under
this provision of the credit facility was $76.8 million.
DG
Marine Credit Facility
In
connection with its acquisition of the Grifco assets on July 18, 2008, DG Marine
entered into a $90 million revolving credit facility with a syndicate of banks
led by SunTrust Bank and BMO Capital Markets Financing, Inc. The
facility amount was reduced to $54 million in November 2009. Genesis
has provided a guaranty of $7.5 million to the lenders in the DG Marine credit
facility.
In
addition to partially financing the Grifco acquisition, DG Marine may borrow
under that facility for general corporate purposes, such as paying for its newly
constructed barges and funding working capital requirements, including up to $5
million in letters of credit. That facility, which matures on July
18, 2011, is secured by all of the equity interests issued by DG Marine and
substantially all of DG Marine’s assets. Other than the pledge of our
equity interest in DG Marine and our guaranty of $7.5 million, that facility is
non-recourse to us and TD Marine. At December 31, 2009, our
Consolidated Balance Sheet included $124.3 million of DG Marine’s assets in our
total assets.
At
December 31, 2009, DG Marine had $46.9 million outstanding under its credit
facility. Due to the revolving nature of loans under the DG Marine
credit facility, additional borrowings and periodic repayments and re-borrowings
may be made until the maturity date. The total amount available for
borrowings at December 31, 2009 was $7.1 million under this credit
facility.
The key
terms for rates under the DG Marine credit facility are as follows:
|
|
·
|
The
interest rate on borrowings may be based on the prime rate or the LIBOR
rate, at our option. The interest rate on prime rate loans can
range from the prime rate plus 1.50% to the prime rate plus
4.00%. The interest rate for LIBOR-based loans can range from
the LIBOR rate plus 2.50% to the LIBOR rate plus 5.00%. The
rate is based on DG Marine’s leverage ratio as computed under the credit
facility. Under the terms of DG Marine’s credit facility, the rates will
fluctuate quarterly based on the leverage ratio. At December 31, 2009, DG
Marine’s borrowing rates were the prime rate plus 4.00% or the LIBOR rate
plus 5.00%.
|
|
|
·
|
Letter
of credit fees will range from 2.50% to 5.00% based on DG Marine’s
leverage ratio as computed under the credit facility. The rate
can fluctuate quarterly. At December 31, 2009, there were no
letters of credit outstanding under the DG Marine credit
facility.
|
|
|
·
|
DG
Marine pays a commitment fee on the unused portion of the $54 million
facility amount. The commitment fee will range from 0.25% to
0.50% based on its leverage ratio as computed under the credit
facility. The rate will fluctuate quarterly based on the
leverage ratio. At December 31, 2009, the commitment fee rate
was 0.50%.
|
In August
2008, DG Marine entered into a series of interest rate swap agreements to
effectively fix the underlying LIBOR rate on $32.9 million of its borrowings
under its credit facility through July 18, 2011. The fixed interest rates in the
swap agreements range from the three-month interest rate of 3.88% in effect at
December 31, 2009 to 4.68% at July 18, 2011.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
DG
Marine’s credit facility contains customary covenants (affirmative, negative and
financial) that limit the manner in which it may conduct its
business. DG Marine’s credit facility contains three primary
financial covenants – an interest coverage ratio, leverage ratio and asset
coverage ratio – that require DG Marine to achieve specific minimum financial
metrics. In general, the interest coverage ratio calculation compares
EBITDA (as defined and adjusted in accordance with the credit facility) to
interest expense. The leverage ratio calculation compares DG Marine’s
funded debt (as calculated in accordance with the credit facility) to EBITDA (as
adjusted). The asset coverage ratio compares an estimated liquidation
value of DG Marine’s boats and barges to DG Marine’s outstanding
debt.
|
Financial
Covenant
|
Requirement
|
Required
Ratio through December 31, 2009
|
Actual
Ratio as of December 31, 2009
|
|||
|
Interest
Coverage Ratio
|
Minimum
|
2.50
to 1.0
|
2.95
to 1.0
|
|||
|
Leverage
Ratio
|
Maximum
|
4.00
to 1.0
|
3.60
to 1.0
|
|||
|
Asset
Coverage Ratio
|
Minimum
|
1.0
to 1.0
|
1.75
to 1.0
|
Our
long-term debt, including the DG Marine credit facility, totaling $366.9 million
matures in 2011. We have estimated the fair value of our long-term
debt to be approximately $359.9 million, or $7.0 million less than the carrying
value of that debt based on consideration of our credit standing.
12. Partners’
Capital and Distributions
Partner’s
capital at December 31, 2009 consists of 39,487,997 common units, including
4,028,096 units owned by our general partner and its affiliates, representing a
98% aggregate ownership interest in the Partnership and its subsidiaries (after
giving effect to the general partner interest), and a 2% general partner
interest. Subsequent to December 31, 2009, our general partner
transferred the common units it held to another affiliate of
Denbury. See Note 23.
Our
general partner owns all of our general partner interest, including incentive
distribution rights (IDRs), all of the 0.01% general partner interest in Genesis
Crude Oil, L.P. (which is reflected as a noncontrolling interest in the
Consolidated Balance Sheet at December 31, 2009) and operates our
business.
Our
partnership agreement authorizes our general partner to cause us to issue
additional limited partner interests and other equity securities, the proceeds
from which could be used to provide additional funds for acquisitions or other
needs.
Distributions
Generally,
we will distribute 100% of our available cash (as defined by our partnership
agreement) within 45 days after the end of each quarter to unitholders of record
and to our general partner. Available cash consists generally of all
of our cash receipts less cash disbursements adjusted for net changes to
reserves. As discussed in Note 11, our credit facility limits the
amount of distributions we may pay in any quarter. At December 31,
2009, our restricted net assets (as defined in Rule 4-03(e)(3) of Regulations
S-X) were $492.1 million.
Pursuant
to our partnership agreement, our general partner receives incremental incentive
cash distributions when unitholders’ cash distributions exceed certain target
thresholds, in addition to its 2% general partner interest. The
allocations of distributions between our common unitholders and our general
partner, including the incentive distribution rights is as follows:
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
|
Unitholders
|
General
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
|
74.53 | % | 25.47 | % | ||||
|
Over
Second Target - Cash distributions greater than $.033 per
Unit
|
49.02 | % | 50.98 | % | ||||
We paid
distributions in 2008 and 2009 as follows:
|
Distribution For
|
Date Paid
|
Per
Unit Amount
|
Limited
Partner Interests Amount
|
General
Partner Interest Amount
|
General
Partner Incentive Distribution Amount
|
Total
Amount
|
||||||||||||||||
|
Fourth
quarter 2007
|
February
2008
|
$ | 0.2850 | $ | 10,902 | $ | 222 | $ | 245 | $ | 11,369 | |||||||||||
|
First
quarter 2008
|
May
2008
|
$ | 0.3000 | $ | 11,476 | $ | 234 | $ | 429 | $ | 12,139 | |||||||||||
|
Second
quarter 2008
|
August
2008
|
$ | 0.3150 | $ | 12,427 | $ | 254 | $ | 633 | $ | 13,314 | |||||||||||
|
Third
quarter 2008
|
November
2008
|
$ | 0.3225 | $ | 12,723 | $ | 260 | $ | 728 | $ | 13,711 | |||||||||||
|
Fourth
quarter 2008
|
February
2009
|
$ | 0.3300 | $ | 13,021 | $ | 266 | $ | 823 | $ | 14,110 | |||||||||||
|
First
quarter 2009
|
May
2009
|
$ | 0.3375 | $ | 13,317 | $ | 271 | $ | 1,125 | $ | 14,713 | |||||||||||
|
Second
quarter 2009
|
August
2009
|
$ | 0.3450 | $ | 13,621 | $ | 278 | $ | 1,427 | $ | 15,326 | |||||||||||
|
Third
quarter 2009
|
November
2009
|
$ | 0.3525 | $ | 13,918 | $ | 284 | $ | 1,729 | $ | 15,931 | |||||||||||
|
Fourth
quarter 2009
|
February
2010
|
$ | 0.3600 | $ | 14,251 | $ | 291 | $ | 2,037 | $ | 16,579 | |||||||||||
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
Net
Income (Loss) per Common Unit
The
following table sets forth the computation of basic net income per common
unit.
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Numerators
for basic and diluted net income (loss)per common unit:
|
||||||||||||
|
Income
(loss) attributable to Genesis Energy, L.P.
|
$ | 8,063 | $ | 26,089 | $ | (13,550 | ) | |||||
|
Less:
General partner's incentive distribution paid or to be paid for the
period
|
(6,318 | ) | (2,613 | ) | (335 | ) | ||||||
|
Add:
Expense allocable to our general partner
|
18,853 | - | - | |||||||||
|
Subtotal
|
20,598 | 23,476 | (13,885 | ) | ||||||||
|
Less:
General partner 2% ownership
|
(412 | ) | (470 | ) | 277 | |||||||
|
Income
(loss) available for common unitholders
|
$ | 20,186 | $ | 23,006 | $ | (13,608 | ) | |||||
|
Denominator
for basic per common unit:
|
||||||||||||
|
Common
Units
|
39,471 | 38,961 | 20,754 | |||||||||
|
Denominator
for diluted per common unit:
|
||||||||||||
|
Common
Units
|
39,471 | 38,961 | 20,754 | |||||||||
|
Phantom
Units
|
132 | 64 | - | |||||||||
| 39,603 | 39,025 | 20,754 | ||||||||||
|
Basic
net income per common unit
|
$ | 0.51 | $ | 0.59 | $ | (0.66 | ) | |||||
|
Diluted
net income per common unit
|
$ | 0.51 | $ | 0.59 | $ | (0.66 | ) | |||||
Equity
Issuances and Contributions
During
the last three years we have issued a total of 15,495,940 common units in the
acquisition of assets. A summary of these unit issuances is as
follows:
|
Period
|
Acquisition
Transaction
|
Units
|
Value
Attributed
to Assets
|
|||||||
|
July 2008
|
Grifco
|
838 | $ | 16,667 | ||||||
|
May 2008
|
Free
State Pipeline
|
1,199 | $ | 25,000 | ||||||
|
July 2007
|
Davison
|
13,459 | $ | 330,000 | ||||||
We issued
new common units to the public and our general partner for cash as
follows:
|
Period
|
Purchaser
of
Common Units
|
Units
|
Gross
Unit Price
|
Issuance
Value
|
GP
Contributions
|
Costs
|
Net
Proceeds
|
|||||||||||||||||||
|
December 2007
|
Public
|
9,200 | $ | 22.000 | $ | 202,400 | $ | - | $ | 8,846 | $ | 193,554 | ||||||||||||||
|
December 2007
|
General
Partner
|
735 | $ | 21.120 | $ | 15,518 | $ | 4,447 | $ | - | $ | 19,965 | ||||||||||||||
|
July 2007
|
General
Partner
|
1,075 | $ | 20.836 | $ | 22,361 | $ | 6,171 | $ | - | $ | 28,532 | ||||||||||||||
On July
18, 2008, we issued 837,690 of our common units to Grifco. The units
were issued at a value of $19.896 per unit, for a total value of $16.7 million,
as a portion of the consideration for the acquisition of the inland marine
transportation business of Grifco.
Additionally,
on July 18, 2008, we redeemed 837,690 of our common units owned by members of
the Davison family. Those units had been issued as a portion of the
consideration for the acquisition of the energy-related business of the Davison
family in July 2007. The redemption was at a value of $19.896 per
unit, for a total value of $16.7 million. After giving effect to the
issuance and redemption described above, we did not experience a change in the
number of common units outstanding.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
On May
30, 2008, we issued 1,199,041 common units to Denbury in connection with the
acquisition of the Free State pipeline. Our general partner also
contributed $0.5 million to maintain its capital account balance.
On
December 10, 2007 we issued 9,200,000 common units is a public offering,
providing cash of $193.6 million after underwriters discount and offering
costs. Our general partner exercised its right to maintain its
proportionate share of our outstanding units and purchased 734,732 common units
from us for $15.5 million, or $21.12 per common unit. Our general
partner also contributed approximately $4.4 million to maintain its capital
account balance.
In July
2007, we issued 13,459,209 common units to the entities owned and controlled by
the Davison family as a portion of the purchase price. Additionally
at that time, our general partner exercised its right to maintain its
proportionate share of our outstanding common units by purchasing 1,074,882
common units from us for $22.4 million cash, or $20.8036 per common
unit. As required under our partnership agreement, our general
partner also contributed approximately $6.2 million to maintain its capital
account balance.
Our
general partner made a capital contribution of $1.4 million in December 2007 to
offset a portion of the severance payment to a former executive. We
also recorded a non-cash capital contribution of $3.4 million from our general
partner for the estimated value of the compensation earned in 2007 under the
proposed arrangements with our senior management team related to an incentive
interest in our general partner. In 2009, we recorded a
additional non-cash contribution of $14.1 million from our general partner
related to incentive compensation arrangements with our senior
executives. 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.
13. Business
Segment Information
Our
operations consist of four operating segments: (1) Pipeline
Transportation – interstate and intrastate crude oil, and to a lesser extent,
natural gas and CO
2
pipeline
transportation; (2) Refinery Services – processing high sulfur (or “sour”) gas
streams as part of refining operations to remove the sulfur and sale of the
related by-product; (3) Industrial Gases – the sale of CO
2
acquired
under volumetric production payments to industrial customers and our investment
in a syngas processing facility, and (4) Supply and Logistics – terminaling,
blending, storing, marketing, gathering and transporting by truck and barge
crude oil and petroleum products. Substantially all of our revenues
are derived from, and substantially all of our assets are located in the United
States.
We define
segment margin as revenues less cost of sales, operating expenses (excluding
depreciation and amortization), and segment general and administrative expenses,
plus our equity in distributable cash generated by our joint
ventures. Our segment margin definition also excludes the non-cash
effects of our equity-based compensation plans and the unrealized gains and
losses on derivative transactions not designated as hedges for accounting
purposes. Segment margin includes the non-income portion of payments
received under direct financing leases. Our chief operating decision
maker (our Chief Executive Officer) evaluates segment performance based on a
variety of measures including segment margin, segment volumes where relevant and
maintenance capital investment.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
|
Pipeline
|
Refinery
|
Supply
&
|
Industrial
|
|||||||||||||||||
|
Transportation
|
Services
|
Logistics
|
Gases
(a)
|
Total
|
||||||||||||||||
|
Year Ended December 31,
2009
|
||||||||||||||||||||
|
Segment
margin
(b)
|
$ | 42,162 | $ | 51,844 | $ | 29,052 | $ | 11,432 | $ | 134,490 | ||||||||||
|
Capital
expenditures
(c)
|
$ | 3,043 | $ | 2,572 | $ | 23,498 | $ | 83 | $ | 29,196 | ||||||||||
|
Maintenance
capital expenditures
|
$ | 1,281 | $ | 1,246 | $ | 1,899 | $ | - | $ | 4,426 | ||||||||||
|
Net
fixed and other long-term assets
(d)
|
$ | 279,574 | $ | 409,556 | $ | 234,421 | $ | 35,332 | $ | 958,883 | ||||||||||
|
Revenues:
|
||||||||||||||||||||
|
External
customers
|
$ | 44,461 | $ | 147,240 | $ | 1,227,453 | $ | 16,206 | $ | 1,435,360 | ||||||||||
|
Intersegment
(e)
|
6,490 | (5,875 | ) | (615 | ) | - | - | |||||||||||||
|
Total
revenues of reportable segments
|
$ | 50,951 | $ | 141,365 | $ | 1,226,838 | $ | 16,206 | $ | 1,435,360 | ||||||||||
|
Year Ended December 31,
2008
|
||||||||||||||||||||
|
Segment
margin
(b)
|
$ | 33,149 | $ | 55,784 | $ | 32,448 | $ | 13,504 | $ | 134,885 | ||||||||||
|
Capital
expenditures
(c)
|
$ | 262,200 | $ | 5,490 | $ | 118,585 | $ | 2,397 | $ | 388,672 | ||||||||||
|
Maintenance
capital expenditures
|
$ | 719 | $ | 1,881 | $ | 1,854 | $ | - | $ | 4,454 | ||||||||||
|
Net
fixed and other long-term assets
(d)
|
$ | 285,773 | $ | 434,956 | $ | 245,815 | $ | 44,003 | $ | 1,010,547 | ||||||||||
|
Revenues:
|
||||||||||||||||||||
|
External
customers
|
$ | 39,051 | $ | 233,871 | $ | 1,851,113 | $ | 17,649 | $ | 2,141,684 | ||||||||||
|
Intersegment
(e)
|
7,196 | (8,497 | ) | 1,301 | - | - | ||||||||||||||
|
Total
revenues of reportable segments
|
$ | 46,247 | $ | 225,374 | $ | 1,852,414 | $ | 17,649 | $ | 2,141,684 | ||||||||||
|
Year Ended December 31,
2007
|
||||||||||||||||||||
|
Segment
margin
(b)
|
$ | 14,170 | $ | 19,713 | $ | 10,646 | $ | 13,038 | $ | 57,567 | ||||||||||
|
Capital
expenditures
(c)
|
$ | 6,592 | $ | 503,765 | $ | 138,403 | $ | 1,104 | $ | 649,864 | ||||||||||
|
Maintenance
capital expenditures
|
$ | 2,880 | $ | 469 | $ | 491 | $ | - | $ | 3,840 | ||||||||||
|
Net
fixed and other long-term assets
(d)
|
$ | 32,936 | $ | 468,068 | $ | 145,915 | $ | 47,364 | $ | 694,283 | ||||||||||
|
Revenues:
|
||||||||||||||||||||
|
External
customers
|
$ | 23,356 | $ | 65,581 | $ | 1,094,558 | $ | 16,158 | $ | 1,199,653 | ||||||||||
|
Intersegment
(e)
|
3,855 | (3,486 | ) | (369 | ) | - | - | |||||||||||||
|
Total
revenues of reportable segments
|
$ | 27,211 | $ | 62,095 | $ | 1,094,189 | $ | 16,158 | $ | 1,199,653 | ||||||||||
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
(a)
|
The
industrial gases segment includes our CO
2
marketing operations and the income from our investments in T&P Syngas
and Sandhill.
|
|
|
(b)
|
A
reconciliation of segment margin to income before income taxes for each
year presented is as follows:
|
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Segment
margin
|
$ | 134,490 | $ | 134,885 | $ | 57,567 | ||||||
|
Corporate
general and administrative expenses
|
(36,475 | ) | (22,113 | ) | (17,573 | ) | ||||||
|
Depreciation,
amortization and impairment
|
(67,586 | ) | (71,370 | ) | (40,245 | ) | ||||||
|
Net
loss on disposal of surplus assets
|
(160 | ) | (29 | ) | (266 | ) | ||||||
|
Interest
expense, net
|
(13,660 | ) | (12,937 | ) | (10,100 | ) | ||||||
|
Non-cash
expenses not included in segment margin
|
(4,089 | ) | 1,355 | (2,009 | ) | |||||||
|
Other
non-cash items affecting segment margin
|
(3,262 | ) | (4,328 | ) | (1,579 | ) | ||||||
|
Income
(loss) before income taxes
|
$ | 9,258 | $ | 25,463 | $ | (14,205 | ) | |||||
|
(c)
|
Capital
expenditures includes fixed asset additions and acquisitions of
businesses.
|
|
(d)
|
Net
fixed and other long-term assets is a measure used by management in
evaluating the results of our operations on a segment basis. Current
assets are not allocated to segments as the amounts are not meaningful in
evaluating the success of the segment’s operations. Amounts for our
Industrial Gases segment include investments in equity investees totaling
$15.1 million, $14.5 million and $16.2 million at December 31, 2009, 2008
and 2007, respectively.
|
|
(e)
|
Intersegment
sales were conducted on an arm’s length
basis.
|
14. Transactions
with Related Parties
Sales,
purchases and other transactions with affiliated companies, in the opinion of
management, are conducted under terms no more or less favorable than
then-existing market conditions.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Truck
transportation services provided to Denbury
|
$ | 3,167 | $ | 3,578 | $ | 1,791 | ||||||
|
Pipeline
transportation services provided to Denbury
|
$ | 14,375 | $ | 10,727 | $ | 5,290 | ||||||
|
Payments
received under direct financing leases from Denbury
|
$ | 21,853 | $ | 11,519 | $ | 1,188 | ||||||
|
Pipeline
transportation income portion of direct financing lease
fees
|
$ | 18,295 | $ | 11,011 | $ | 641 | ||||||
|
Pipeline
monitoring services provided to Denbury
|
$ | 120 | $ | 120 | $ | 120 | ||||||
|
Directors'
fees paid to Denbury
|
$ | 185 | $ | 195 | $ | 150 | ||||||
|
CO
2
transportation services provided by Denbury
|
$ | 5,475 | $ | 6,424 | $ | 5,213 | ||||||
|
Crude
oil purchases from Denbury
|
$ | 1,754 | $ | - | $ | 101 | ||||||
|
Operations,
general and administrative services provided by our general
partner
|
$ | 50,417 | $ | 51,872 | $ | 22,490 | ||||||
|
Distributions
to our general partner on its limited partner units and general partner
interest, including incentive distributions
|
$ | 10,066 | $ | 6,463 | $ | 1,671 | ||||||
|
Sales
of CO
2
to
Sandhill
|
$ | 2,867 | $ | 2,941 | $ | 2,783 | ||||||
|
Petroleum
products sales to Davison family businesses
|
$ | 757 | $ | 1,261 | $ | - | ||||||
|
Transition
services costs to Davison family
|
$ | - | $ | - | $ | 9,880 | ||||||
Transportation
Services
We
provide truck transportation services to Denbury to move their crude oil from
the wellhead to our Mississippi pipeline. Denbury pays us a fee for
this trucking service that varies with the distance the crude oil is
trucked. These fees are reflected in the statement of operations as
supply and logistics revenues.
We earn
tariffs on our Mississippi pipeline for transporting Denbury’s
oil. We earned fees from Denbury for the transportation of their
CO
2
on
our Free State pipeline. We also earned fees from Denbury under the
direct financing lease arrangements for the Olive and Brookhaven crude oil
pipelines and the Brookhaven and NEJD CO
2
pipelines
and recorded pipeline transportation income from these
arrangements.
We also
provide pipeline monitoring services to Denbury. This revenue is
included in pipeline revenues in the statements of operations.
Directors’
Fees
We paid
Denbury for the services of each of the Denbury’s officers who served as
directors of our general partner, at an annual rate and for attendance at
meetings that was the same as the rates at which our independent directors were
paid.
CO
2
Operations
and Transportation
Denbury
charges us a transportation fee of $0.16 per Mcf (adjusted for inflation) to
deliver CO
2
for us to
our customers. In 2009, the inflation-adjusted transportation
fee averaged $0.2043 per Mcf.
Operations,
General and Administrative Services
We do not
directly employ any persons to manage or operate our business. Those
functions are provided by our general partner. We reimburse the
general partner for all direct and indirect costs of these services, excluding
any payments to our management team pursuant to their Class B Membership
Interests. See Note 16.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
Amounts
due to and from Related Parties
At
December 31, 2009 and 2008, we owed Denbury $1.0 million, respectively, for
CO
2
transportation charges. Denbury owed us $1.9 million and $2.0 million
for transportation services at December 31, 2009 and 2008,
respectively. We owed our general partner $2.1 million for
administrative services at both December 31, 2009 and 2008. At
December 31, 2009 and 2008, Sandhill owed us $0.7 million for purchases of
CO
2
,
respectively.
Drop-down
transactions
On May
30, 2008, we entered into a $175 million financing lease arrangement with
Denbury Onshore for the NEJD Pipeline System, and acquired the Free State
CO
2
pipeline system for $75 million, consisting of $50 million cash and $25 million
of our common units. See Note 3.
Unit
redemption
As
discussed in Note 12, we redeemed 837,690 of our common units owned by members
of the Davison family in July 2008. The total value of the units
redeemed was $16.7 million.
DG
Marine joint venture
Our
partner in the DG Marine joint venture is TD Marine, LLC, a joint venture
consisting of three members of the Davison family. See Note
3.
Financing
Our
credit facility is non-recourse to our general partner, except to the extent of
its pledge of its 0.01% general partner interest in Genesis Crude Oil,
L.P. Our general partner’s principal assets are its general and
limited partnership interests in us. Our credit agreement obligations
are not guaranteed by Denbury or any of its other subsidiaries.
We
guarantee 50% of the obligation of Sandhill to Community Trust
Bank. At December 31, 2009, the total amount of Sandhill’s obligation
to the bank was $2.65 million; therefore, our guarantee was for $1.33
million.
Approximately
12% of the outstanding common shares of Community Trust Bank are held by Davison
family members. Community Trust Bank is a 17% participant in the DG
Marine credit facility. James E. Davison, Jr., a member of our board
of directors, also serves on the board of the holding company that owns
Community Trust Bank.
As
discussed in Note 12, our general partner made capital contributions in order to
maintain its capital account totaling less than $0.1 million and $0.5 million in
2009 and 2008, respectively. Our general partner also purchased
common units totaling $37.9 million in 2007. In addition, our general
partner made a capital contribution of $1.4 million in December 2007 to offset a
portion of the severance payment to a former executive. In 2009 and
2007, we recorded a capital contribution from our general partner of $14.1
million and $3.4 million, respectively, related to compensation recognized for
our executive management team. See Note 16.
15. Supplemental
Cash Flow Information
The
following table provides information regarding the net changes in components of
operating assets and liabilities.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Decrease
(increase) in:
|
||||||||||||
|
Accounts
receivable
|
$ | (7,979 | ) | $ | 61,126 | $ | (35,362 | ) | ||||
|
Inventories
|
(16,559 | ) | (5,557 | ) | (143 | ) | ||||||
|
Other
current assets
|
(2,712 | ) | (2,419 | ) | (1,887 | ) | ||||||
|
Increase
(decrease) in:
|
||||||||||||
|
Accounts
payable
|
19,203 | (58,224 | ) | 34,523 | ||||||||
|
Accrued
liabilities
|
(1,522 | ) | 3,812 | 6,149 | ||||||||
|
Net
changes in components of operating assets and liabilities,net of working
capital acquired
|
$ | (9,569 | ) | $ | (1,262 | ) | $ | 3,280 | ||||
Cash
received by us for interest during the years ended December 31, 2009, 2008 and
2007 was $0.1 million, $0.1 million and $0.3 million,
respectively. Payments of interest and commitment fees were $13.3
million, $11.3 million and $8.4 million, during the years ended December 31,
2009, 2008 and 2007, respectively.
Cash paid
for income taxes in during the years ended December 31, 2009, 2008 and 2007 was
$0.2 million, $2.4 million and $1.6 million, respectively.
At
December 31, 2009 and 2008, we had incurred liabilities for fixed asset
additions totaling $0.5 million and $1.7 million, respectively, that had not
been paid at the end of the year and, therefore, are not included in the caption
“Additions to property and equipment” on the Consolidated Statements of Cash
Flows. We had incurred liabilities for other assets totaling $0.3
million at December 31, 2007 that had not been paid at the end of the year and,
therefore, are not included in the caption “Other, net” under investing
activities on the Consolidated Statements of Cash Flows.
In May
2008, we issued common units with a value of $25 million as part of the
consideration for the acquisition of the Free State Pipeline from
Denbury. In July 2008, we issued common units with a value of $16.7
million as part of the consideration for the acquisition of the inland marine
transportation assets of Grifco. These common unit issuances are non-cash
transactions and the value of the assets acquired is not included in investing
activities and the issuance of the common units is not reflected under financing
activities in our Consolidated Statements of Cash Flows.
Additionally,
we deferred payment of $12 million ($11.7 million discounted) of the
consideration in the acquisition from Grifco to December 2008 and
2009. This deferral of the payment of consideration was a non-cash
transaction and the value of the assets acquired is not included in investing
activities in our Consolidated Statements of Cash Flows. The
seller-financed consideration payments made in December 2008 and December 2009
are included in financing cash flows.
In July
2007, we issued common units with a value of $330 million as part of the
consideration in the Davison acquisition. This common unit issuance
is a non-cash transaction and the value of the assets acquired is not included
under investing activities and the issuance of the common units are not
reflected under financing activities in our Consolidated Statements of Cash
Flows.
In 2007,
our general partner made a non-cash contribution to us in the amount of $3.4
million that is not included in financing activities in the Consolidated
Statements of Cash Flows. This contribution related to the estimated
compensation earned by our management team for its services in 2007 under the
proposed compensation arrangement with these individuals that existed at
December 31, 2007.
16. Employee
Benefit Plans and Equity-Based Compensation Plans
We do not
directly employ any of the persons responsible for managing or operating our
activities. Employees of our general partner provide those services
and are covered by various retirement and other benefit plans.
In order
to encourage long-term savings and to provide additional funds for retirement to
its employees, our general partner sponsors a profit-sharing and retirement
savings plan. Under this plan, our general partner’s matching
contribution is calculated as an equal match of the first 3% of each employee’s
annual pretax contribution and 50% of the next 3% of each employee’s annual
pretax contribution. Our general partner also made a profit-sharing
contribution of 3% of each eligible employee’s total compensation (subject to
IRS limitations). The expenses included in the Consolidated
Statements of Operations for costs relating to this plan were $2.2 million, $2.2
million, and $0.8 million for the years ended December 31, 2009, 2008 and 2007,
respectively.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
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 $1.8 million, $1.7 million, and $1.5 million
in 2009, 2008 and 2007, respectively. Effective January 1, 2008, the
employees who operate the assets we acquired from the Davison family became
participants in these plans.
Stock
Appreciation Rights Plan
Under the
terms of our stock appreciation rights plan, regular, full-time active employees
(with the exception of our chief executive officer, chief operating officer and
chief financial officer) and the members of the Board are eligible to
participate in the plan. The plan is administered by the Compensation
Committee of the Board, who shall determine, in its full discretion, who shall
receive awards under the plan, the number of rights to award, the grant date of
the units and the formula for allocating rights to the participants and the
strike price of the rights awarded. Each right is equivalent to one
common unit.
The
rights have a term of 10 years from the date of grant. If the right
has not been exercised at the end of the ten year term and the participant has
not terminated his employment with us, the right will be deemed exercised as of
the date of the right’s expiration and a cash payment will be made as described
below.
Upon
vesting, the participant may exercise his rights and receive a cash payment
calculated as the difference between the averages of the closing market price of
our common units for the ten days preceding the date of exercise over the strike
price of the right being exercised. The cash payment to the
participant will be net of any applicable withholding taxes required by
law. If the Committee determines, in its full discretion, that it
would cause significant financial harm to the Partnership to make cash payments
to participants who have exercised rights under the plan, then the Committee may
authorize deferral of the cash payments until a later date.
Termination
for any reason other than death, disability or normal retirement (as these terms
are defined in the plan) will result in the forfeiture of any non-vested
rights. Upon death, disability or normal retirement, all rights will
become fully vested. If a participant is terminated for any reason
within one year after the effective date of a change in control (as defined in
the plan) all rights will become fully vested.
The
compensation cost associated with our stock appreciation rights plan, which upon
exercise will result in the payment of cash to the employee, is re-measured each
reporting period based on the fair value of the rights. Under
accounting guidance, the liability is calculated using a fair value method that
takes into consideration the expected future value of the rights at their
expected exercise dates.
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 expense we recognize is adjusted
for expected forfeitures of rights (due to terminations before vesting, or
expirations after vesting). The liability amount accrued on the
balance sheet is adjusted to this amount at each balance sheet date with the
adjustment reflected in the statement of operations.
The
estimates that we make each period to determine the fair value of these rights
include the following assumptions:
|
Assumptions Used for Fair Value of
Rights
|
|||
|
December 31,
2009
|
December 31,
2008
|
December
31, 2007
|
|
|
Expected
life of rights (in years)
|
0.25
- 5.50
|
1.25
- 6.00
|
2.25
- 6.25
|
|
Risk-free
interest rate
|
0.05%
- 2.52%
|
0.57%
- 1.71%
|
3.12%
- 3.65%
|
|
Expected
unit price volatility
|
43.8%
|
42.8%
|
34.2%
|
|
Expected
future distribution yield
|
8.50%
|
6.00%
|
6.00%
|
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
|
·
|
In
determining the expected life of the rights, we use the simplified method
allowed by the Securities and Exchange Commission. As our stock
appreciation rights plan was not put in place until December 31, 2003 and
our employee population tripled in 2008, we have very limited experience
with employee exercise
patterns.
|
|
·
|
The
expected volatility of our units is computed using the historical period
we believe is representative of future expectations. We determined
the period to use as the historical period by considering our distribution
history and distribution
yield.
|
|
·
|
The
risk-free interest rate was determined from the current yield for U.S.
Treasury zero-coupon bonds with a term similar to the remaining expected
life of the rights.
|
|
·
|
In
determining our expected future distribution yield, we considered our
history of distribution payments, our expectations for future payments,
and the distribution yields of entities similar to us. While current
market conditions result in a lower distribution yield, we believe that
the yield will be closer to 8.5% over the life of the outstanding
rights.
|
|
·
|
We
estimated the expected forfeitures of non-vested rights and expirations of
vested rights. We have limited experience with employee forfeiture
and expiration patterns, as our plan was not initiated until December 31,
2003. We reviewed the history available to us as well as employee turnover
patterns in determining the rates to use. We also used different
estimates for different groups of
employees.
|
The
following table reflects rights activity under our plan as of January 1, 2009,
and changes during the year ended December 31, 2009:
|
Stock
Appreciation Rights
|
Rights
|
Weighted
Average Exercise Price
|
Weighted
Average Contractual Remaining Term (Yrs)
|
Aggregate
Intrinsic Value
|
||||||||||||
|
Outstanding
at January 1, 2009
|
1,017,985 | $ | 18.09 | |||||||||||||
|
Granted
during 2009
|
228,212 | $ | 13.00 | |||||||||||||
|
Exercised
during 2009
|
(24,602 | ) | $ | 15.41 | ||||||||||||
|
Forfeited
or expired during 2009
|
(101,597 | ) | $ | 18.34 | ||||||||||||
|
Outstanding
at December 31, 2009
|
1,119,998 | $ | 17.14 | 7.4 | $ | 3,515 | ||||||||||
|
Exercisable
at December 31, 2009
|
587,981 | $ | 16.13 | 6.2 | $ | 2,396 | ||||||||||
The
weighted-average fair value at December 31, 2009 of rights granted during 2009
was $4.82 per right, determined using the following assumptions:
|
Assumptions
Used for Fair Value of Rights at Grant Date
|
|
|
Granted
in 2009
|
|
|
Expected
life of rights (in years)
|
5.50
|
|
Risk-free
interest rate
|
2.52%
|
|
Expected
unit price volatility
|
43.8%
|
|
Expected
future distribution yield
|
8.50%
|
The total
intrinsic value of rights exercised during 2009, 2008 and 2007 was $0.1 million,
$0.4 million and $1.6 million, respectively, which was paid in cash to the
participants.
At
December 31, 2009, there was $0.9 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, 2009 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, 2009, the
remaining cost will be recognized over a weighted average period of
approximately one year.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
We
recorded charges and credits related to our stock appreciation rights for three
years ended December 31, 2009 as follows:
|
Expense (Credits to Expense) Related to Stock
Appreciation Rights
|
||||||||||||
|
Statement
of Operations
|
2009
|
2008
|
2007
|
|||||||||
|
Supply
and logistics operating costs
|
$ | 1,431 | $ | (997 | ) | $ | 528 | |||||
|
Refinery
services operating costs
|
325 | 23 | - | |||||||||
|
Pipeline
operating costs
|
360 | (296 | ) | 420 | ||||||||
|
General
and administrative expenses
|
1,263 | (1,141 | ) | 1,576 | ||||||||
|
Total
|
$ | 3,379 | $ | (2,411 | ) | $ | 2,524 | |||||
2007
Long Term Incentive Plan
Our
Genesis Energy, Inc. 2007 Long Term Incentive Plan (the “2007 LTIP”) provides
for awards of Phantom Units and Distribution Equivalent Rights to non-employee
directors and employees of Genesis Energy, LLC, our general partner. Phantom
Units are notional units representing unfunded and unsecured promises to deliver
a Partnership common unit to the participant should specified vesting
requirements be met. Distribution Equivalent Rights are rights to receive an
amount of cash equal to all or a portion of the cash distributions made by the
Partnership during a specified period. The 2007 LTIP is administered by the
Compensation Committee of the board of directors of our general partner (the
“Board”).
The
Compensation Committee (at its discretion) will designate participants in the
2007 LTIP, determine the types of awards to grant to participants, determine the
number of units to be covered by any award, and determine the conditions and
terms of any award including vesting, settlement and forfeiture conditions. The
2007 LTIP may be amended or terminated at any time by the Board or the
Compensation Committee; however, any material amendment, such as a material
increase in the number of units available under the 2007 LTIP or a change in the
types of awards available under the 2007 LTIP, will also require the approval of
our unitholders. The Compensation Committee is also authorized to make
adjustments in the terms and conditions of and the criteria included in awards
under the plan in specified circumstances.
The
common units to be awarded under the 2007 Plan will be obtained by our general
partner through purchases made on the open market, from us, from any affiliates
of our general partner or from any other person; however, it is generally
intended that units are to be acquired from us as newly-issued common
units.
Subject
to adjustment as provided in the 2007 LTIP, awards with respect to up to an
aggregate of 1,000,000 units may be granted under the 2007 LTIP, of which
832,928 remain authorized for issuance at December 31,
2009. 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 the expense
we recognize is adjusted for an allowance for estimated
forfeitures. Due to the positions of the small group of employees and
non-employee directors who received these grants, we have assumed that there
will be no forfeitures of these Phantom Units in our fair value calculation as
of December 31, 2009. The grant date fair value of the awards is
measured by reducing the grant date market price by the present value of the
distributions expected to be paid on the shares during the requisite service
period, discounted at an appropriate risk-free interest rate.
The
aggregate grant date fair value of Phantom Unit awards granted during 2009, 2008
and 2007 was $0.7 million, $0.8 million and $0.9 million,
respectively. The total fair value of Phantom Units that vested
during the years ended December 31, 2009 and 2008 was $0.7 million and $0.1
million, respectively. Compensation expense recognized during 2009
and 2008 for Phantom Units was as follows:
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
|
Expense Related to Phantom Unit
Awards
|
||||||||
|
Statement
of Operations
|
2009
|
2008
|
||||||
|
Supply
and logistics operating costs
|
$ | 36 | $ | 114 | ||||
|
Refinery
services operating costs
|
120 | - | ||||||
|
Pipeline
operating costs
|
4 | 139 | ||||||
|
General
and administrative expenses
|
869 | 494 | ||||||
|
Total
|
$ | 1,029 | $ | 747 | ||||
Expense
recorded during 2007 was less than $0.1 million. As of December 31,
2009, there was $0.5 million of unrecognized compensation expense related to
these units. This unrecognized compensation cost is expected to be
recognized over a weighted-average period of one year. Due to the
provisions in the 2007 Plan providing for immediate vesting of outstanding
Phantom Units upon the occurrence of a change in control of our general partner,
the outstanding Phantom Units vested in February 2010. See Note
23.
The
following table summarizes information regarding our non-vested Phantom Unit
grants as of December 31, 2009:
|
Non-vested
Phantom Unit Grants
|
Number
of Units
|
Weighted
Average Grant-Date Fair Value
|
Weighted
Average Contractual Remaining Term (Yrs)
|
Aggregate
Intrisic Value
|
|||||||||
|
Non-vested
at January 1, 2008
|
78,388 | $ | 19.32 | ||||||||||
|
Granted
during 2009
|
82,501 | $ | 8.14 | ||||||||||
|
Vested
during 2009
|
(33,532 | ) | $ | 19.79 | |||||||||
|
Forfeited
during 2009
|
(3,500 | ) | $ | 8.88 | |||||||||
|
Non-vested
at December 31, 2009
|
123,857 | $ | 12.04 |
0.9
|
$ | 2,341 | |||||||
The
weighted-average fair value of Phantom Units granted during 2009, 2008 and 2007
was determined using the following assumptions:
|
Year Granted
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Expected distribution
rate
|
$ | 0.33 | $ | 0.285 - $0.315 | $ | 0.27 | ||||||
|
Risk-free
rate
|
0.73% - 1.50 | % | 2.01% - 2.40 | % | 3.19% - 3.31 | % | ||||||
|
Weighted
average grant date fair value
|
$ | 8.14 | $ | 17.63 | $ | 21.92 | ||||||
Bonus
Program
In
January 2008, the Committee of the Board of our general partner approved a bonus
program (referred to below as the Bonus Plan) for all employees of our general
partner (with the exception of our Chief Executive Officer, Chief Operating
Officer and Chief Financial Officer (collectively our “Senior Executives”)) that
was applicable to 2009 and 2008. The Bonus Plan is paid at the
discretion of our Board based on the recommendation of the Compensation
Committee, and can be amended or changed at any time. The Bonus Plan
is designed to enhance the financial performance of the Partnership by rewarding
employees for achieving financial performance and safety
objectives. While the maximum amount that will be paid each year as
bonuses is calculated based on two metrics, the actual amounts paid individually
are discretionary and may total to less than the maximum that might otherwise be
available.
The Bonus
Plan is based primarily on the amount of money we generate for distributions to
our unitholders, and is measured on a calendar-year basis. For 2009
and 2008, two metrics were used to determine the bonus pool – the level of
Available Cash before Reserves (before subtracting bonus expense and related
employer tax burdens) that we generate and our company-wide safety record
improvement. The level of Available Cash before Reserves generated for the year
as a percentage of a target set by our Committee is weighted ninety percent and
the achieved level of the targeted improvement in our safety record is weighted
ten percent. The sum of the weighted percentage achievement of these
targets is multiplied by the eligible compensation and the target percentages
established by our Compensation Committee for the various levels of our
employees to determine the maximum bonus pool from which the majority of our
employees are paid bonuses.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
A
separate marketing bonus pool is available for compensating certain marketing
personnel that is based on the contribution of that marketing group to Available
Cash before Reserves. A minimum level of contribution to Available
Cash before Reserves is required before any amounts are allocated to the
marketing bonus pool.
For 2009
and 2008, we accrued $3.5 million and $4.0 million, respectively, for the
general bonus pool and $0.4 million and $0.5 million, respectively, for the
marketing bonus pool. 2009 bonuses will be paid to employees in March
2010.
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 our Senior
Executives.) 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 material change in job status, a material
reduction in pay, or a requirement to relocate more than 25 miles.
A change
in control is defined in the Severance Plan. Generally, a change in
control is a change in the control of Denbury, a disposition by Denbury of more
than 50% of our general partner, or a transaction involving the disposition of
substantially all of the assets of Genesis.
The
amount of severance is determined separately for three classes of
participants. The first class, which includes two Executive Officers
of Genesis, would receive a severance benefit equal to three times that
participant’s annual salary and bonus amounts. The second class,
which includes certain other members of management, would receive a severance
benefit equal to two times that participant’s salary and bonus
amounts. The third class of participant would receive a severance
benefit based on the participant’s salary and bonus amounts and length of
service. Participants would also receive certain medical and dental
benefits.
Class
B Membership Interests
As part
of finalizing the compensation arrangements for our Senior Executives on
December 31, 2008, our general partner awarded them an equity interest in our
general partner as long-term incentive compensation. These Class B Membership
Interests compensate the holders thereof by providing rewards based on increased
shares of the cash distributions attributable to our incentive distribution
rights (or IDRs)(See Note 12) to the extent we increase the level of available
cash we generate for each quarter through the vesting date.
Our
general partner agreed that it will not seek reimbursement (on behalf of itself
or its affiliates) under our partnership agreement for the costs of these Senior
Executive compensation arrangements . Although our general partner will not seek
reimbursement for the costs of the Class B Membership Interests and deferred
compensation plan arrangements, we will record non-cash expense.
The Class
B Membership Interests awarded to our senior executives are accounted for as
liability awards under the guidance for equity-based compensation. As
such, the fair value of the compensation cost we record for these awards is
recomputed at each measurement date through final settlement and the expense to
be recorded is adjusted based on that fair value. Therefore, changes
in management’s assumptions utilized in the determination of the fair value of
the awards change the amount of compensation cost we
record. Additionally the determination of fair value is affected by
the distribution yield of a group of publicly-traded entities that are the
general partners in publicly-traded master limited partnerships, a factor over
which we have no control.
As these
awards were issued, among other reasons, in settlement of our obligation to
these employees recorded as of December 2007, we treated the issuance as a
modification in accordance with the accounting guidance for share-based
payments. Therefore, we compared the value of the compensation
arrangements before the modification ($3.4 million) to the fair value of the
awards and reflected the incremental compensation cost over the requisite
service period of the new grant.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
At
December 31, 2009, management estimates that the fair value of the Class B
Membership Awards and the related deferred compensation awards granted to our
Senior Executives is approximately $30.5 million. Management’s
estimates of fair value were made in order to record non-cash compensation
expense over the vesting period. For the year ended December 31,
2009, we recorded expense of $14.1 million for these awards.
The fair
value of the Class B Membership Awards and the related deferred compensation was
calculated utilizing assumptions regarding the following factors:
|
|
·
|
Estimates
of the level of IDR distributions that would be paid to our general
partner assuming our current quarterly increase in the distribution
through the final vesting date of December 31,
2012.
|
|
|
·
|
Estimates
of the level of available cash we estimate we will generate for each
quarter through the vesting date and available cash attributable to
certain assets that are excluded in the
computations.
|
|
|
·
|
Estimates
of an appropriate discount factor to utilize for computation of the fair
value of the awards.
|
The Class
B Membership Awards and related deferred compensation agreements contained
provisions providing for accelerated vesting upon a change in control of our
general partner. As a result of the sale of our general partner in
February 2010, the Class B Membership Interests were redeemed or converted into
other ownership interests in our general partner, and the deferred compensation
was paid to the Senior Executives. See Note 23.
17. Major
Customers and Credit Risk
Due to
the nature of our supply and logistics operations, a disproportionate percentage
of our trade receivables constitute obligations of oil
companies. This industry concentration has the potential to impact
our overall exposure to credit risk, either positively or negatively, in that
our customers could be affected by similar changes in economic, industry or
other conditions. However, we believe that the credit risk posed by
this industry concentration is offset by the creditworthiness of our customer
base. Our portfolio of accounts receivable is comprised in large part
of integrated and large independent energy companies with stable payment
experience. The credit risk related to contracts which are traded on
the NYMEX is limited due to the daily cash settlement procedures and other NYMEX
requirements.
We have
established various procedures to manage our credit exposure, including initial
credit approvals, credit limits, collateral requirements and rights of
offset. Letters of credit, prepayments and guarantees are also
utilized to limit credit risk to ensure that our established credit criteria are
met.
Shell Oil
Company accounted for 12.5% and 14.6% of total revenues in 2009 and 2008,
respectively. Shell Oil Company and Occidental Energy Marketing, Inc.
accounted for 20.7% and 11.2% of total revenues in 2007,
respectively. The revenues from these two customers in all three
years relate primarily to our supply and logistics operations.
18. Derivatives
On
January 1, 2009, we adopted new accounting guidance which require enhanced
disclosures about (1) how and why we use derivative instruments, (2) how
derivative instruments and related hedged items are accounted for by us and (3)
how derivative instruments and related hedged items affect our financial
position, financial performance and cash flows.
Commodity
Derivatives
We have
exposure to commodity price changes related to our inventory and purchase
commitments. We utilize derivative instruments (primarily futures and
options contracts traded on the NYMEX) to hedge our exposure to commodity
prices, primarily crude oil, fuel oil and petroleum products; however, only a
portion of these instruments are designated as hedges under the accounting
guidance. Our decision as to whether to designate derivative instruments as fair
value hedges for accounting purposes relates to our expectations of the length
of time we expect to have the commodity price exposure and our expectations as
to whether the derivative contract will qualify as highly effective under
accounting guidance in limiting our exposure to commodity price
risk. Most of the petroleum products, including fuel oil that we
supply cannot be hedged with a high degree of effectiveness with derivative
contracts available on the NYMEX; therefore, we do not designate derivative
contracts utilized to limit our price risk related to these products as hedges
for accounting purposes. Typically we utilize crude oil and natural
gas futures and option contracts to limit our exposure to the effect of
fluctuations in petroleum products prices on the future sale of our inventory or
commitments to purchase petroleum products, and we recognize any changes in fair
value of the derivative contracts as increases or decreases in our cost of
sales. The recognition of changes in fair value of the derivative
contracts not designated as hedges for accounting purposes can occur in
reporting periods that do not coincide with the recognition of gain or loss on
the actual transaction being hedged. Therefore we will, on occasion,
report gains or losses in one period that will be partially offset by gains or
losses in a future period when the hedged transaction is
completed.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
We have
designated certain crude oil futures contracts as hedges of crude oil inventory
due to our expectation that these contracts will be highly effective in hedging
our exposure to fluctuations in crude oil prices during the period that we
expect to hold that inventory. We account for these derivative
instruments as fair value hedges under the accounting
guidance. Changes in the fair value of these derivative instruments
designated as fair value hedges are used to offset related changes in the fair
value of the hedged crude oil inventory. Any hedge ineffectiveness in
these fair value hedges and any amounts excluded from effectiveness testing are
recorded as a gain or loss in the Consolidated Statements of
Operations.
In
accordance with NYMEX requirements, we fund the margin associated with our loss
positions on commodity derivative contracts traded on the NYMEX. The
amount of the margin is adjusted daily based on the fair value of the commodity
contracts. The margin requirements are intended to mitigate a party’s
exposure to market volatility and the associated contracting party
risk. We offset fair value amounts recorded for our NYMEX derivative
contracts against margin funding as required by the NYMEX in Other Current
Assets in our Consolidated Balance Sheets.
At
December 31, 2009, we had the following outstanding derivative commodity
futures, forwards and options contracts that were entered into to hedge
inventory or fixed price purchase commitments:
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
|
Sell
(Short)
|
Buy
(Long)
|
|||||||
|
Contracts
|
Contracts
|
|||||||
|
Designated
as hedges under accounting rules:
|
||||||||
|
Crude
oil futures:
|
||||||||
|
Contract
volumes (1,000 bbls)
|
146 | - | ||||||
|
Weighted
average contract price per bbl
|
$ | 78.98 | $ | - | ||||
|
Not
qualifying or not designated as hedges under accounting
rules:
|
||||||||
|
Crude
oil futures:
|
||||||||
|
Contract
volumes (1,000 bbls)
|
305 | 111 | ||||||
|
Weighted
average contract price per bbl
|
$ | 77.79 | $ | 77.93 | ||||
|
Heating
oil futures:
|
||||||||
|
Contract
volumes (1,000 bbls)
|
94 | 43 | ||||||
|
Weighted
average contract price per gal
|
$ | 1.92 | $ | 2.04 | ||||
|
RBOB
gasoline futures:
|
||||||||
|
Contract
volumes (1,000 bbls)
|
14 | - | ||||||
|
Weighted
average contract price per gal
|
$ | 1.91 | $ | - | ||||
|
#6
Fuel Oil futures:
|
||||||||
|
Contract
volumes (1,000 bbls)
|
75 | - | ||||||
|
Weighted
average contract price per bbl
|
$ | 68.06 | $ | - | ||||
|
Crude
oil written calls:
|
||||||||
|
Contract
volumes (1,000 bbls)
|
73 | - | ||||||
|
Weighted
average premium received
|
$ | 2.79 | $ | - | ||||
At
December 31, 2008 and 2007, we had no commodity price risk derivatives that were
designated as hedges for financial reporting purposes. Therefore, the
derivative contracts were marked to fair value based on the closing price for
the contracts at the end of each period and an asset or liability was recorded
for the fair value and the change in fair value was recorded in our Consolidated
Statements of Operations.
Interest
Rate Derivatives
DG Marine
utilizes swap contracts with financial institutions to hedge interest payments
for $32.9 million of its outstanding debt through July 2011. The
weighted average interest rate of these swap contracts is 4.36%. DG
Marine expects these interest rate swap contracts to be highly effective in
limiting its exposure to fluctuations in market interest rates, therefore, we
have designated these swap contracts as cash flow hedges under accounting
guidance. The effective portion of the derivative represents the
change in fair value of the hedge that offsets the change in cash flows of the
hedged item. The effective portion of the gain or loss in the fair
value of these swap contracts is reported as a component of Accumulated Other
Comprehensive Income (Loss) (AOCI) and reclassified into future earnings
contemporaneously as interest expense associated with the underlying debt under
the DG Marine credit facility is recorded. To the extent that the
change in the fair value of the interest rate swaps does not perfectly offset
the change in the fair value of our exposure to interest rates, the ineffective
portion of the hedge will be immediately recognized in interest expense in our
Consolidated Statements of Operations.
Financial
Statement Impacts
The
following table summarizes the accounting treatment and classification of our
derivative instruments on our Consolidated Financial
Statements.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
|
Impact
of Unrealized Gains and Losses
|
||||||
|
Derivative
Instrument
|
Hedged
Risk
|
Consolidated
Balance Sheets
|
Consolidated
Statements of Operations
|
|||
|
Designated
as hedges under accounting guidance:
|
||||||
|
Crude
oil futures contracts
|
Volatility
in crude
|
Derivative
is recorded in
|
Excess,
if any, over effective
|
|||
|
(fair
value hedge)
|
oil
prices - effect on market value of inventory
|
Other
Current Assets (offset against margin deposits) and offsetting change in
fair value of inventory is recorded in Inventory
|
portion
of hedge is recorded in Supply and Logistics - Cost of Sales. Effective
portion is offset in Cost of Sales against change in value of inventory
being hedged
|
|||
|
Interest
rate swaps
|
Changes
in
|
Entire
hedge is recorded in
|
Expect
hedge to fully
|
|||
|
(cash
flow hedge)
|
interest
rates
|
Accrued
Liabilities or Other Liabilities depending on duration
|
offset
hedged risk; no
|
|||
|
ineffectiveness
recorded. Effective portion is recorded to AOCI and ultimately
reclassified to interest expense
|
||||||
|
Not
qualifying or not designated as hedges under accounting
guidance:
|
||||||
|
Commodity
hedges consisting of crude oil, heating oil and natural gas futures and
forward contracts and call options
|
Volatility
in crude oil and petroleum products prices - effect on market value of
inventory or purchase commitments.
|
Derivative
is recorded in Other Current Assets (offset against margin deposits) or
Accrued Liabilities
|
Supply
and Logistics - Cost Entire amount of change
in fair value of
derivative
is recorded in of
Sales
|
|||
Unrealized
gains are subtracted from net income and unrealized losses are added to net
income in determining cash flows from operating
activities. Additionally, the offsetting change in the fair value of
inventory that is recorded for our fair value hedges is also eliminated from net
income in determining cash flows from operating
activities. Changes in margin deposits necessary to fund
unrealized losses also affect cash flows from operating activities.
The
following tables reflected the estimated fair value gain (loss) position of our
hedge derivatives and related inventory impact for qualifying hedges at December
31, 2009:
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
|
Fair
Value of Derivative Assets and Liabilities
|
|||||||||||
|
Consolidated
|
Consolidated
|
||||||||||
|
Derivative
|
Balance
Sheets
|
Derivative
|
Balance
Sheets
|
||||||||
|
Assets
|
Location
|
Liabilities
|
Location
|
||||||||
|
Commodity
derivatives - futures and call options:
|
|||||||||||
|
Hedges
designated under accounting guidance as fair value hedges
|
$ | 53 |
Other
Current Assets
|
$ | (159 | ) (1) |
Other
Current Assets
|
||||
|
Undesignated
hedges
|
307 |
Other
Current Assets
|
(2,118 | ) (1) |
Other
Current Assets
|
||||||
|
Total
commodity derivatives
|
360 | (2,277 | ) | ||||||||
|
Interest
rate swaps designated as cash flow hedges under accounting
rules:
|
|||||||||||
|
Portion
expected to be reclassified into earnings within one year
|
(1,176 | ) |
Accrued
Liabilities
|
||||||||
|
Portion
expected to be reclassified into earnings after one year
|
(512 | ) |
Other
Liabilities
|
||||||||
|
Total
derivatives
|
$ | 360 | $ | (3,965 | ) | ||||||
(1) These
derivative liabilities have been funded with margin deposits recorded in our
Consolidated Balance Sheets in Other Current Assets.
|
Year
Ended December 31, 2009
|
||||||||||||
|
Effect
on Consolidated Statements of Operations
|
||||||||||||
|
and
Other Comprehensive Income (Loss)
|
||||||||||||
|
Amount
of Loss Recognized in Income
|
||||||||||||
|
Other
|
||||||||||||
|
Interest
|
Comprehensive
|
|||||||||||
|
Supply
&
|
Expense
|
Income
(Loss)
|
||||||||||
|
Logistics
-
|
Reclassified
|
|||||||||||
|
Product
|
from
|
Effective
|
||||||||||
|
Costs
|
AOCI
|
Portion
|
||||||||||
|
Commodity
derivatives - futures and call options:
|
||||||||||||
|
Contracts
designated as hedges under accounting guidance:
|
$ | (5,321 | ) (1) | $ | - | $ | - | |||||
|
Contracts
not considered hedges under accounting guidance:
|
(2,446 | ) | ||||||||||
|
Total
commodity derivatives
|
(7,767 | ) | - | - | ||||||||
|
Interest
rate swaps designated as cash flow hedges under accounting
guidance
|
(784 | ) | (508 | ) | ||||||||
|
Total
derivatives
|
$ | (7,767 | ) | $ | (784 | ) | $ | (508 | ) | |||
(1)
Represents the amount of loss recognized in income for derivatives related to
the fair value hedge of inventory. The amount excludes the gain on
the hedged inventory under the fair value hedge of $7.5 million.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
During
2009, DG Marine’s interest rate hedges fully offset the hedged risk; therefore,
there was no ineffectiveness recorded for the hedges.
We expect
to reclassify $1.2 million in unrealized losses from AOCI into interest expense
during the next 12 months. Because a portion of these losses are
based on market prices at the current period end, actual amounts to be
reclassified to earnings will differ and could vary materially as a result of
changes in market conditions. We have no derivative contracts with
credit contingent features.
19. Fair-Value
Measurements
The
following table sets forth by level within the fair value hierarchy our
financial assets and liabilities that were accounted for at fair value on a
recurring basis as of December 31, 2009 and 2008. As required by fair
value accounting guidance, financial assets and liabilities are classified in
their entirety based on the lowest level of input that is significant to the
fair value measurement. Our assessment of the significance of a
particular input to the fair value requires judgment and may affect the
placement of assets and liabilities within the fair value hierarchy
levels.
|
Fair Value at December 31,
2009
|
Fair Value at December 31,
2008
|
|||||||||||||||||||||||
|
Recurring
Fair Value Measures
|
Level
1
|
Level
2
|
Level
3
|
Level
1
|
Level
2
|
Level
3
|
||||||||||||||||||
|
Commodity
derivatives :
|
||||||||||||||||||||||||
|
Assets
|
$ | 360 | $ | - | $ | - | $ | 482 | $ | - | $ | - | ||||||||||||
|
Liabilities
|
$ | (2,277 | ) | $ | - | $ | - | $ | (970 | ) | $ | - | $ | - | ||||||||||
|
Interest
rate swaps
|
$ | - | $ | - | $ | (1,688 | ) | $ | - | $ | - | $ | (1,964 | ) | ||||||||||
Level
1
Included
in Level 1 of the fair value hierarchy as commodity derivative contracts are
exchange-traded futures and exchange-traded option contracts. The
fair value of these exchange-traded derivative contracts is based on unadjusted
quoted prices in active markets and is, therefore, included in Level 1 of the
fair value hierarchy.
Level
2
At
December 31, 2009 and 2008, we had no Level 2 fair value
measurements.
Level
3
Included
within Level 3 of the fair value hierarchy are our interest rate
swaps. The fair value of our interest rate swaps is based on
indicative broker price quotations. These derivatives are included in Level 3 of
the fair value hierarchy because broker price quotations used to measure fair
value are indicative quotations rather than quotations whereby the broker or
dealer is ready and willing to transact. However, the fair value of
these Level 3 derivatives is not based upon significant management assumptions
or subjective inputs.
The
following table provides a reconciliation of changes in fair value of the
beginning and ending balances for our derivatives measured at fair value using
inputs classified as level 3 in the fair value hierarchy:
|
Year
Ended December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Balance
at beginning of period
|
$ | (1,964 | ) | $ | - | |||
|
Realized
and unrealized gains (losses)-
|
||||||||
|
Reclassified
into interest expense for settled contracts
|
784 | 33 | ||||||
|
Included
in other comprehensive income
|
(508 | ) | (1,997 | ) | ||||
|
Balance
at end of period
|
$ | (1,688 | ) | $ | (1,964 | ) | ||
|
Total
amount of losses for the year ended included in earnings attributable to
the change in unrealized losses relating to liabilities still held at
December 31, 2009 and 2008, respectively
|
$ | (10 | ) | $ | (5 | ) | ||
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
See Note
18 for additional information on our derivative instruments.
We
generally apply fair value techniques on a non-recurring basis associated with
(1) valuing the potential impairment loss related to goodwill and (2) valuing
potential impairment loss related to long-lived assets.
20. Commitments
and Contingencies
Commitments
and Guarantees
In 2008,
we entered into a new office lease for our corporate headquarters that extends
until January 31, 2016. We lease office space for field offices under
leases that expire between 2011 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, 2009, were as follows (in thousands).
|
Office
Space
|
Transportation
Equipment
|
Terminals
and Tanks
|
Total
|
|||||||||||||
|
2010
|
$ | 861 | $ | 3,438 | $ | 5,256 | $ | 9,555 | ||||||||
|
2011
|
800 | 2,569 | 4,345 | 7,714 | ||||||||||||
|
2012
|
768 | 1,453 | 4,304 | 6,525 | ||||||||||||
|
2013
|
733 | 798 | 1,555 | 3,086 | ||||||||||||
|
2014
|
731 | 596 | 1,004 | 2,331 | ||||||||||||
|
2015
and thereafter
|
803 | 1,937 | 23,860 | 26,600 | ||||||||||||
|
Total
minimum lease obligations
|
$ | 4,696 | $ | 10,791 | $ | 40,324 | $ | 55,811 | ||||||||
Total
operating lease expense was as follows (in thousands).
|
Year
ended December 31, 2009
|
$ | 12,023 | ||
|
Year
ended December 31, 2008
|
$ | 8,757 | ||
|
Year
ended December 31, 2007
|
$ | 6,079 |
We have
guaranteed the payments by our subsidiary 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, 2009 were $320.0 million and are
reflected in the Consolidated Balance Sheet. We have also guaranteed
the payments by our operating partnership under the terms of our operating
leases of tractors and trailers. Such obligations are included in
future minimum rental payments in the table above.
We
guarantee $7.5 million of the outstanding debt of DG Marine under its credit
facility. The outstanding debt of DG Marine in included in our
Consolidated Balance Sheets. We believe the likelihood we would be
required to perform or otherwise incur any significant losses associated with
this guaranty is remote.
We
guaranteed $1.2 million of residual value related to the leases of
trailers. We believe the likelihood we would be required to perform
or otherwise incur any significant losses associated with this guaranty is
remote.
We
guaranty 50% of the obligations of Sandhill under a credit facility with a
bank. At December 31, 2009, Sandhill owed $2.65 million; therefore
our guarantee was $1.33 million. Sandhill makes principal payments
for this obligation totaling $0.6 million per year. We believe the
likelihood we would be required to perform or otherwise incur any significant
losses associated with this guaranty is remote.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
In
general, we expect to incur expenditures in the future to comply with increasing
levels of regulatory safety standards. While the total amount of
increased expenditures cannot be accurately estimated at this time, we expect
that our annual expenditures for integrity testing, repairs and improvements
under regulations requiring assessment of the integrity of crude oil pipelines
to average from $1.0 million to $1.5 million.
We are
subject to various environmental laws and regulations. Policies and
procedures are in place to monitor compliance and to detect and address any
releases of crude oil from our pipelines or other facilities, however no
assurance can be made that such environmental releases may not substantially
affect our business.
Other
Matters
Our
facilities and operations may experience damage as a result of an accident or
natural disaster. These hazards can cause personal injury or loss of
life, severe damage to and destruction of property and equipment, pollution or
environmental damage and suspension of operations. We maintain
insurance that we consider adequate to cover our operations and properties, in
amounts we consider reasonable. Our insurance does not cover every
potential risk associated with operating our facilities, including the potential
loss of significant revenues. The occurrence of a significant event
that is not fully-insured could materially and adversely affect our results of
operations. We believe we are adequately insured for public liability
and property damage to others and that our coverage is similar to other
companies with operations similar to ours. No assurance can be made
that we will be able to maintain adequate insurance in the future at premium
rates that we consider reasonable.
We are
subject to lawsuits in the normal course of business and examination by tax and
other regulatory authorities. We do not expect such matters presently
pending to have a material adverse effect on our financial position, results of
operations or cash flows.
21. Income
Taxes
We are
not a taxable entity for federal income tax purposes. As such, we do
not directly pay federal income taxes. Other than with respect to our
corporate subsidiaries and the Texas Margin Tax, our taxable income or loss is
includible in the federal income tax returns of each of our
partners.
A portion
of the operations we acquired in the Davison transactions are owned by
wholly-owned corporate subsidiaries that are taxable as
corporations. We pay federal and state income taxes on these
operations. In May 2006, the State of Texas enacted a law which will
require us to pay a tax of 0.5% on our “margin,” as defined in the law,
beginning in 2008 based on our 2007 results. The “margin” to which
the tax rate is applied generally will be calculated as our revenues (for
federal income tax purposes) less the cost of the products sold (for federal
income tax purposes), in the State of Texas.
Our
income tax provision (benefit) is as follows:
|
Year
Ended
|
||||||||||||
|
December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Current:
|
||||||||||||
|
Federal
|
$ | 1,458 | $ | 2,979 | $ | 1,665 | ||||||
|
State
|
1,442 | 872 | 339 | |||||||||
|
Total
current income tax expense
|
2,900 | 3,851 | 2,004 | |||||||||
|
Deferred:
|
||||||||||||
|
Federal
|
168 | (3,850 | ) | (2,432 | ) | |||||||
|
State
|
12 | (363 | ) | (226 | ) | |||||||
|
Total
deferred income tax benefit
|
180 | (4,213 | ) | (2,658 | ) | |||||||
|
Total
income tax expense (benefit)
|
$ | 3,080 | $ | (362 | ) | $ | (654 | ) | ||||
Deferred
income taxes relate to temporary differences based on tax laws and statutory
rates in effect at the December 31, 2009 balance sheet date. Deferred
tax assets and liabilities consist of the following:
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
|
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Deferred
tax assets:
|
||||||||
|
Current:
|
||||||||
|
Other
current assets
|
$ | 279 | $ | 271 | ||||
|
Other
|
8 | 97 | ||||||
|
Total
current deferred tax asset
|
287 | 368 | ||||||
|
Net
operating loss carryforwards - federal
|
- | 1,415 | ||||||
|
Net
operating loss carryforwards - state
|
- | 128 | ||||||
|
Total
long-term deferred tax asset
|
- | 1,543 | ||||||
|
Total
deferred tax assets
|
287 | 1,911 | ||||||
|
Deferred
tax liabilities:
|
||||||||
|
Current:
|
||||||||
|
Other
|
(198 | ) | (3 | ) | ||||
|
Long-term:
|
||||||||
|
Fixed
assets
|
(8,481 | ) | (9,868 | ) | ||||
|
Intangible
assets
|
(6,686 | ) | (6,937 | ) | ||||
|
Total
long-term liability
|
(15,167 | ) | (16,805 | ) | ||||
|
Total
deferred tax liabilities
|
(15,365 | ) | (16,808 | ) | ||||
|
Total
net deferred tax liability
|
$ | (15,078 | ) | $ | (14,897 | ) | ||
Our
income tax benefit varies from the amount that would result from applying the
federal statutory income tax rate to income before income taxes as
follows:
|
Year
Ended
|
||||||||||||
|
December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Income
(loss) before income taxes
|
$ | 9,258 | $ | 25,463 | $ | (14,205 | ) | |||||
|
Partnership
(income) loss not subject to tax
|
(7,822 | ) | (30,902 | ) | 8,894 | |||||||
|
Income
(loss) subject to income taxes
|
1,436 | (5,439 | ) | (5,311 | ) | |||||||
|
Tax
benefit at federal statutory rate
|
503 | $ | (1,904 | ) | $ | (1,859 | ) | |||||
|
State
income taxes, net of federal benefit
|
991 | 357 | 33 | |||||||||
|
Effects
of unrecognized tax benefits, federal and state
|
1,733 | 1,431 | 1,168 | |||||||||
|
Return
to provision, federal and state
|
(224 | ) | (258 | ) | - | |||||||
|
Other
|
77 | 12 | 4 | |||||||||
|
Income
tax expense (benefit)
|
$ | 3,080 | $ | (362 | ) | $ | (654 | ) | ||||
|
Effective
tax rate on income (loss) before income taxes
|
33 | % | -1 | % | 5 | % | ||||||
The
company adopted the provisions in accounting guidance related to uncertain tax
positions on January 1, 2007. A reconciliation of the beginning and
ending amount of unrecognized tax benefits was as follows:
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
|
Balance
at January 1, 2008
|
$ | 864 | ||
|
Additions
based on tax positions related to current year
|
1,735 | |||
|
Balance
at December 31, 2008
|
2,599 | |||
|
Additions
based on tax positions related to current year
|
1,733 | |||
|
Balance
at December 31, 2009
|
$ | 4,332 |
If the
unrecognized tax benefits at December 31, 2009 were recognized, $4.3 million
would affect our effective income tax rate. There are no uncertain
tax positions as of December 31, 2009 for which it is reasonably possible that
the amount of unrecognized tax benefits would significantly decrease during
2010.
22. Quarterly
Financial Data (Unaudited)
The table
below summarizes our unaudited quarterly financial data for 2009 and
2008.
|
2009
Quarters
|
Total
|
|||||||||||||||||||
|
First
|
Second
|
Third
|
Fourth
|
Year
|
||||||||||||||||
|
Revenues
|
$ | 253,493 | $ | 342,204 | $ | 403,389 | $ | 436,274 | $ | 1,435,360 | ||||||||||
|
Operating
income (loss)
|
$ | 7,021 | $ | 7,748 | $ | 8,356 | $ | (1,754 | ) | $ | 21,371 | |||||||||
|
Net
income attributable to Genesis Energy, L.P.
|
$ | 5,290 | $ | 4,456 | $ | 4,299 | $ | (5,982 | ) | $ | 8,063 | |||||||||
|
Net
income per common unit - basic
|
$ | 0.16 | $ | 0.13 | $ | 0.14 | $ | 0.08 | $ | 0.51 | ||||||||||
|
Net
income per common unit - diluted
|
$ | 0.16 | $ | 0.13 | $ | 0.14 | $ | 0.08 | $ | 0.51 | ||||||||||
|
Cash
distributions per common unit
(1)
|
$ | 0.3300 | $ | 0.3375 | $ | 0.3450 | $ | 0.3525 | $ | 1.3650 | ||||||||||
|
2008
Quarters
|
Total
|
|||||||||||||||||||
|
First
|
Second
|
Third
|
Fourth
|
Year
|
||||||||||||||||
|
Revenues
|
$ | 486,185 | $ | 640,540 | $ | 636,919 | $ | 378,040 | $ | 2,141,684 | ||||||||||
|
Operating
income
|
$ | 1,759 | $ | 11,032 | $ | 13,381 | $ | 11,719 | $ | 37,891 | ||||||||||
|
Net
income attributable to Genesis Energy, L.P.
|
$ | 1,645 | $ | 7,328 | $ | 10,763 | $ | 6,353 | $ | 26,089 | ||||||||||
|
Net
income per common unit - basic
|
$ | 0.03 | $ | 0.17 | $ | 0.25 | $ | 0.14 | $ | 0.59 | ||||||||||
|
Net
income per common unit - diluted
|
$ | 0.03 | $ | 0.17 | $ | 0.25 | $ | 0.14 | $ | 0.59 | ||||||||||
|
Cash
distributions per common unit
(1)
|
$ | 0.2850 | $ | 0.3000 | $ | 0.3150 | $ | 0.3225 | $ | 1.2225 | ||||||||||
(1) Represents
cash distributions declared and paid in the applicable period.
23. Subsequent
Events
On
February 5, 2010, affiliates of Quintana Capital Group, L.P., along with members
of the Davison family and members of our senior executive management team, EIV
Capital Fund LP, a Delaware limited partnership, and other investors
(collectively, the New Owner Group) purchased all of the Class A membership
interests in our general partner from Denbury. In connection
with the amendment and restatement of our general partner’s limited liability
agreement, two forms of member interests in our general partner replaced the
Class A Member and Class B Member Interests. These new member
interests are identified as Series A and Series B units.
All of
the Class B membership interests in our general partner held by the three
existing Senior Executives (see Note 16) were either (i) converted into Series A
units in our general partner or (ii) or redeemed by our general partner on
February 5, 2010. The amounts owed under the deferred compensation
plan with the Senior Executives was similarly converted or
redeemed. In total, the value of the Series A units issued and cash
payments made by our general partner to settle its obligations under the Class B
membership interests and deferred compensation totaled $14.9 million. This
value, when combined with amounts previously paid to the Senior Executives
during 2009 related to the Class B Membership Interests, resulted in total
non-cash compensation expense of $15.4 million. The difference
between the recorded cumulative compensation expense related to these interests
through December 31, 2009 of $17.5 million and the total non-cash compensation
expense of $15.4 million will be recorded as a reduction of expense in the first
quarter of 2010.
GENESIS
ENERGY, L.P.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
As a
result of the change in control of our general partner on February 5, 2010, all
outstanding phantom units issued pursuant to our 2007 LTIP
vested. As a result of this acceleration of the vesting period,
we will record non-cash compensation expense of $0.5 million in the first
quarter of 2010. In total, 123,857 phantom units
vested. In connection with the departure of one of our Senior
Executives in February 2010, we will also record approximately $1.0 million of
compensation expense.
Pursuant
to restricted unit agreements entered into with our general partner on February
5, 2010, certain members of the senior executive management team of the Company
received an aggregate of 767 Series B units in our general partner that vest as
follows: (i) 25% vest on the first anniversary of the issuance, (ii)
33 1/3% of the remaining unvested units vest on the second anniversary of the
issuance, (iii) 50% of the remaining unvested units vest on the third
anniversary of the issuance and (iv) 100% of the remaining unvested units vest
on the fourth anniversary of the issuance. Under the terms of the
restricted unit agreements, in the event of certain public offerings, a change
of control or similar transaction by the Company, the executive’s unvested units
will become fully vested. In the event of death or disability, the executive’s
employment date will be deemed extended through to the next anniversary date for
vesting purposes. If the executive is terminated for “cause” or he or
she leaves without “good reason” (as such terms are defined in the restricted
unit agreements), he or she will forfeit all of his or her units, whether vested
or unvested. If the executive is terminated without “cause,” by death
or disability, or by the executive for “good reason,” then he or she will
forfeit all unvested units and our general partner will have the right to
repurchase or redeem any vested units. Subject to the rights of the
holders of Series A units to receive distributions up to certain threshold
amounts, holders of Series B units, upon vesting, have the right to receive
quarterly distributions and certain tax distributions in accordance with the
Amended and Restated Limited Liability Company Agreement of the Company
.
|
Schedule
I - Condensed Financial Information
|
||||||||||||
|
Genesis
Energy, L.P. (Parent Company Only)
|
||||||||||||
|
Condensed
Statements of Income and Comprehensive Income
|
||||||||||||
|
Years
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Equity
in earnings (losses) of subsidiaries
|
$ | 8,063 | $ | 26,089 | $ | (13,550 | ) | |||||
|
Net
income (loss)
|
8,063 | 26,089 | (13,550 | ) | ||||||||
|
Other
comprehensive gain (loss) of subsidiary
|
133 | (962 | ) | - | ||||||||
|
Total
comprehensive income (loss)
|
$ | 8,196 | $ | 25,127 | $ | (13,550 | ) | |||||
|
Condensed
Balance Sheets
|
||||||||
|
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(in
thousands)
|
||||||||
|
Assets
|
||||||||
|
Cash
|
$ | 2 | $ | 3 | ||||
|
Investment
in subsidiaries
|
628,553 | 665,334 | ||||||
|
Advances
to subsidiaries
|
92 | 91 | ||||||
|
Total
Assets
|
$ | 628,647 | $ | 665,428 | ||||
|
Partners'
Capital
|
||||||||
|
Limited
Partners
|
$ | 617,629 | $ | 649,046 | ||||
|
General
Partner
|
11,847 | 17,344 | ||||||
|
Accumulated
other comprehensive loss
|
(829 | ) | (962 | ) | ||||
|
Total
Partners' Capital
|
$ | 628,647 | $ | 665,428 | ||||
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,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Cash
Flows from Operating Activities:
|
||||||||||||
|
Net
income (loss)
|
$ | 8,063 | $ | 26,089 | $ | (13,550 | ) | |||||
|
Equity
in losses (earnings) of GCO
|
9,395 | (15,773 | ) | 13,550 | ||||||||
|
Equity
in (earnings) losses of GNEJD
|
(17,458 | ) | (10,316 | ) | - | |||||||
|
Change
in advances to GCO
|
(1 | ) | (7 | ) | 4 | |||||||
|
Net
cash (used in) provided by operating activities
|
(1 | ) | (7 | ) | 4 | |||||||
|
Cash
Flows from Investing Activities:
|
||||||||||||
|
Investment
in GCO
|
(9 | ) | (511 | ) | (216,172 | ) | ||||||
|
Distributions
from GCO - return of investment
|
60,080 | 50,534 | 17,175 | |||||||||
|
Net
cash provided by (used in) investing activities
|
60,071 | 50,023 | (198,997 | ) | ||||||||
|
Cash
Flows from Financing Activities:
|
||||||||||||
|
Issuance
of limited and general partner interests, net
|
9 | 511 | 216,172 | |||||||||
|
Distributions
to limited and general partners
|
(60,080 | ) | (50,534 | ) | (17,175 | ) | ||||||
|
Net
cash (used in) provided by financing activities
|
(60,071 | ) | (50,023 | ) | 198,997 | |||||||
|
Net
(decrease) increase in cash
|
(1 | ) | (7 | ) | 4 | |||||||
|
Cash
at beginning of period
|
3 | 10 | 6 | |||||||||
|
Cash
at end of period
|
$ | 2 | $ | 3 | $ | 10 | ||||||
See
accompanying notes to condensed financial statements.
Schedule
I – Condensed Financial Statements – Continued
Genesis
Energy, L.P. (Parent Company Only)
Notes to
Condensed Financial Statements
1. Basis
of Presentation
Genesis
Energy, L.P., or GEL, is the owner of 99.99% of Genesis Crude Oil, L.P., or GCO
and 100% of Genesis NEJD Holdings, LLC, or GNEJD. These parent
company only financial statements for GEL summarize the results of operations
and cash flows for the years ended December 31, 2009, 2008 and 2007, and GEL’s
financial position at December 31, 2009 and 2008. In these
statements, GEL’s investments in GCO and GNEJD are stated on the equity method
basis of accounting. The GEL statements should be read in conjunction
with the Consolidated Financial Statements of Genesis Energy, L.P.
As
discussed in Note 11 of the Notes to the Consolidated Financial Statements, the
terms of the credit facility with GCO, limit the amount of distributions that
GCO and its subsidiaries may pay to GEL. Such distributions may
not exceed the sum of the distributable cash generated by GCO and its
subsidiaries for the eight most recent quarters, less the sum of the
distributions made with respect to those quarters. This restriction results in
the restricted net assets (as defined in Rule 4-08 (e)(3) of Regulation S-X) of
GEL’s subsidiary exceeding 25% of the consolidated net assets of GEL and its
subsidiaries.
2. Contingencies
GEL
guarantees the obligations of GCO under our credit facility. See Note
11 of the Notes to the Consolidated Financial Statements of Genesis Energy, L.P.
for a description of GCO’s credit facility.
GEL
guarantees the obligations of GCO under our lease with Paccar Leasing
Services. See Note 20 of the Notes to the Consolidated Financial
Statements of Genesis Energy, L.P.
GEL has
guaranteed crude oil and petroleum products purchases of GCO and its
subsidiaries. These guarantees, totaling $43.0 million, were provided
to counterparties. To the extent liabilities exist under the
contracts subject to these guarantees, such liabilities are included in the
Consolidated Financial Statements of Genesis Energy, L.P.
GEL has
guaranteed $7.5 million of the outstanding debt of DG Marine under its credit
facility.
3. Supplemental
Cash Flow Information
In May
2008, additional limited partner interests in GCO with a value of $25 million
were issued to GEL. GEL issued common units with an equal value as part of the
consideration in acquisition of the Free State Pipeline from
Denbury. In July 2008, additional limited partner interests in GCO
with a value of $16.7 million were issued to GEL. GEL issued common
units with an equal value as part of the consideration in the Grifco
acquisition. These transactions are non-cash transactions and are not
included in the Statements of Cash Flows in investing or financing
activities.
152
TABLE OF CONTENTS
Part IPart IIPart III