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
GENESIS 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.
PART
I
Item 1. Business
Unless
the context otherwise requires, references in this annual report to “Genesis
Energy, L.P.,” “Genesis,” “we,” “our,” “us” or like terms refer to Genesis
Energy, L.P. and its operating subsidiaries (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; “CO2” 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 CO2 producers;
industrial and commercial enterprises that use NaHS and caustic soda; and
businesses that use CO2 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 CO2 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 CO2
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” CO2 pipeline
that extends from CO2 source
fields near Jackson, Mississippi, to oil fields in eastern
Mississippi. We have a twenty-year transportation services agreement
(through 2028) related to the transportation of CO2 on our
Free State Pipeline.
In
addition, Denbury Resources Inc. and its subsidiaries (Denbury) has leased from
us (through 2028) the NEJD Pipeline System, a 183-mile, 20” CO2 pipeline
extending from the Jackson Dome, near Jackson, Mississippi, to near
Donaldsonville, Louisiana. The NEJD System transports CO2 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 CO2 and
certain other industrial gases and related services to industrial and commercial
enterprises.
We supply
CO2
to industrial customers under long-term contracts. Our
compensation for supplying CO2
to our industrial customers is the effective difference between the price at
which we sell our CO2
under each contract and the price at which we acquired our CO2
pursuant to our volumetric production payments (also known as VPPs), minus
transportation costs. In addition to supplying CO2, 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 CO2 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 CO2
producers; industrial and commercial enterprises that use NaHS and caustic
soda; and businesses which use CO2 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 CO2 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.
CO2
Pipelines
We also
transport CO2 for a
fee. The Free State Pipeline is an 86-mile, 20” pipeline that extends
from CO2 source
fields at Jackson Dome, near Jackson, Mississippi, to oil fields in east
Mississippi. In addition, the NEJD Pipeline System, a 183-mile, 20”
CO2
pipeline extends from the Jackson Dome, near Jackson, Mississippi, to near
Donaldsonville, Louisiana and is currently being used to transport CO2 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 CO2 to
industrial customers, (ii) process raw CO2 and sell
that processed CO2, and (iii)
manufacture and sell syngas, a combination of carbon monoxide and
hydrogen.
CO2 –
Industrial Customers
We supply
CO2 to
industrial customers under seven long-term CO2 sales
contracts. We acquired those contracts, as well as the CO2 necessary
to satisfy substantially all of our expected obligations under those contracts,
in three separate transactions. We purchased those contracts, along
with three VPPs representing 280.0 Bcf of CO2 (in the
aggregate), from Denbury. We sell our CO2 to
customers who treat the CO2 and sell
it to end users for use for beverage carbonation and food chilling and
freezing. Our compensation for supplying CO2 to our
industrial customers is the effective difference between the price at which we
sell our CO2 under each
contract and the price at which we acquired our CO2 pursuant
to our VPPs, minus transportation costs. We expect some seasonality
in our sales of CO2. The
dominant months for beverage carbonation and freezing food are from April to
October, when warm weather increases demand for beverages and the approaching
holidays increase demand for frozen foods. At December 31, 2009, we have 127.0
Bcf of CO2 remaining
under the VPPs.
Currently,
all of our CO2
supply is from our interests – our VPPs – in fields producing naturally
occurring CO2. The
agreements we executed when we acquired the VPPs provide that we may acquire
additional CO2 from
Denbury under terms similar to the original agreements should additional volumes
be needed to meet our obligations under the 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 CO2 supply
should we choose to remain in the CO2 supply
business.
One of
the parties that we supply with CO2 under a
long-term sales contract is Sandhill Group, LLC. On April 1, 2006, we
acquired a 50% interest in Sandhill Group, LLC as discussed below.
CO2 -
Processing
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 CO2 processing
facility located in Brandon, Mississippi. Sandhill is engaged in the production
and distribution of liquid carbon dioxide for use in the food, chemicals and oil
industries. The facility acquires CO2 from us
under a long-term supply contract. 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 CO2 are with
large international companies. One of the remaining contracts is with
Sandhill Group, LLC, of which we own 50%. The remaining contract is
with a smaller company with a history in the CO2
business. 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
CO2 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 CO2
supply is from our interest – our VPPs – in fields producing naturally occurring
sources. In the future we may have to obtain our CO2 supply
from manufactured processes. Naturally-occurring CO2, like that
from the Jackson Dome area, occurs infrequently, and only in limited areas east
of the Mississippi River. Our industrial CO2 customers
have facilities that are connected to the NEJD CO2 pipeline,
which makes delivery easy and efficient. Once our existing VPPs
expire, we will have to obtain additional CO2 should we
choose to remain in the CO2 supply
business, and the competition and pricing issues we will face at that time are
uncertain.
With
regard to our CO2 supply
business, our contracts have long terms and generally include take-or-pay
provisions requiring annual minimum volumes that each customer must pay for even
if the CO2 is not
taken.
Due to
the long-term contract and location of our syngas facility, as well as the costs
involved in establishing 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 CO2. As
discussed above, the limited amounts of naturally-occurring CO2 east of
the Mississippi River makes it difficult for competitors of Sandhill to
significantly increase their production or sales and, thereby, increase their
market share.
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 CO2 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 CO2, 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 CO2 pipelines
are subject to construction, installation, operation and safety regulation by
the Department of Transportation, or DOT, and various other federal, state and
local agencies. The Pipeline Safety Act of 1992, among other things,
amends the Hazardous Liquid Pipeline Safety Act of 1979, or HLPSA, in several
important respects. It requires the Pipeline and Hazardous Materials
Safety Administration of DOT to consider environmental impacts, as well as its
traditional public safety mandates, when developing pipeline safety
regulations. In addition, the Pipeline Safety Improvement Act of 2005
mandates the establishment by DOT of pipeline operator qualification rules
requiring minimum training requirements for operators, the development of
standards and criteria to evaluate contractors’ methods to qualify their
employees and requires that pipeline operators provide maps and other records to
the DOT. It also authorizes the DOT to require that pipelines be
modified to accommodate internal inspection devices, to mandate the evaluation
of emergency flow restricting devices for pipelines in populated or sensitive
areas, and to order other changes to the operation and maintenance of petroleum
pipelines. Significant expenses could be incurred in the future if
additional safety measures are required or if safety standards are raised and
exceed the current pipeline control system capabilities.
On March
31, 2001, the DOT promulgated Integrity Management Plan, or IMP, regulations.
The IMP regulations require that we perform baseline assessments of all
pipelines that could affect a High Consequence Area, or HCA, including certain
populated areas and environmentally sensitive areas. Due to the
proximity of all of our pipelines to water crossings and populated areas, we
have designated all of our pipelines as affecting HCAs. The integrity
of these pipelines must be assessed by internal inspection, pressure test, or
equivalent alternative new technology.
The IMP
regulation required us to prepare an Integrity Management Plan that details the
risk assessment factors, the overall risk rating for each segment of pipe, a
schedule for completing the integrity assessment, the methods to assess pipeline
integrity, and an explanation of the assessment methods selected. The
risk factors to be considered include proximity to population areas, waterways
and sensitive areas, known pipe and coating conditions, leak history, pipe
material and manufacturer, adequacy of cathodic protection, operating pressure
levels and external damage potential. The IMP regulations 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 CO2 pipelines,
and natural gas pipelines that do not engage in interstate
operations. In practice, states vary considerably in their authority
and capacity to address pipeline safety. We do not anticipate any
significant problems in complying with applicable state laws and regulations in
those states in which we operate.
Our crude
oil pipelines are also subject to the requirements of the federal Department of
Transportation regulations requiring qualification of all pipeline
personnel. The Operator Qualification, or OQ, program 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.
Item 1A. Risk Factors
Risks
Related to Our Business
We
may not be able to fully execute our growth strategy if we are unable to raise
debt and equity capital at an affordable price.
Our
strategy contemplates substantial growth through the development and acquisition
of a wide range of midstream and other energy infrastructure assets while
maintaining a strong balance sheet. This strategy includes constructing and
acquiring additional assets and businesses to enhance our ability to compete
effectively, diversify our asset portfolio and, thereby, provide more stable
cash flow. We regularly consider and enter into discussions regarding, and are
currently contemplating, additional potential joint ventures, stand-alone
projects and other transactions that we believe will present opportunities to
realize synergies, expand our role in the energy infrastructure business, and
increase our market position and, ultimately, increase distributions to
unitholders.
We will
need new capital to finance the future development and acquisition of assets and
businesses. Limitations on our access to capital will impair our ability to
execute this strategy. Expensive capital will limit our ability to develop or
acquire accretive assets. Although we intend to continue to expand our business,
this strategy may require substantial capital, and we may not be able to raise
the necessary funds on satisfactory terms, if at all.
The
capital and credit markets have been, and 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 CO2 we
sell and the prices at which we sell
it;
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the
demand for our terminal storage
services;
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the
level of our operating costs;
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the
level of our general and administrative costs;
and
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prevailing
economic conditions.
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In
addition, the actual amount of cash we will have available for distribution will
depend on other factors that include:
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the
level of capital expenditures we make, including the cost of acquisitions
(if any);
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our
debt service requirements;
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fluctuations
in our working capital;
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restrictions
on distributions contained in our debt
instruments;
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our
ability to borrow under our working capital facility to pay distributions;
and
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the
amount of cash reserves established by our general partner in its sole
discretion in the conduct of our
business.
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Our
ability to pay distributions each quarter depends primarily on our cash flow,
including cash flow from financial reserves and working capital borrowings, and
is not solely a function of profitability, which will be affected by non-cash
items. As a result, we may make cash distributions during periods when we record
losses and we may not make distributions during periods when we record net
income.
Our
indebtedness could adversely restrict our ability to operate, affect our
financial condition, and prevent us from complying with our requirements under
our debt instruments and could prevent us from paying cash distributions to our
unitholders.
We have
outstanding debt and the ability to incur more debt. As of December 31, 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 competitive
disadvantage as compared to our competitors that have less
debt.
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We may
incur additional indebtedness (public or private) in the future, under our
existing credit facilities, by issuing debt instruments, under new credit
agreements, under joint venture credit agreements, under capital leases or
synthetic leases, on a project-finance or other basis, or a combination of any
of these. If we incur additional indebtedness in the future, it likely would be
under our existing credit facility or under arrangements which may have terms
and conditions at least as restrictive as those contained in our existing credit
facilities. Failure to comply with the terms and conditions of any existing or
future indebtedness would constitute an event of default. If an event of default
occurs, the lenders will have the right to accelerate the maturity of such
indebtedness and foreclose upon the collateral, if any, securing that
indebtedness. If an event of default occurs under our joint ventures’ credit
facilities, we may be required to repay amounts previously distributed to us and
our subsidiaries. In addition, if there is a change of control as described in
our credit facility, that would be an event of default, unless our creditors
agreed otherwise, 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 CO2
- volumes, which often depends on actions and commitments by parties
beyond our control.
Our
profitability and cash flow are dependent on our ability to increase or, at a
minimum, maintain our current commodity— oil, refined products, NaHS, caustic
soda and CO2— volumes.
We access commodity volumes through two sources, producers and service providers
(including gatherers, shippers, marketers and other aggregators). Depending on
the needs of each customer and the market in which it operates, we can either
provide a service for a fee (as in the case of our pipeline transportation
operations) or we can purchase the commodity from our customer and resell it to
another party.
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 CO2 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 CO2 operations
involves us supplying CO2
to industrial customers using reserves attributable to our volumetric production
payment interests, which are a finite resource and projected to terminate around
2015.
The cash
flow from our CO2 operations
involves us supplying CO2 to
industrial customers using reserves attributable to our volumetric production
payments. Unless we are able to obtain a replacement supply of CO2 and enter
into sales arrangements that generate substantially similar economics, our cash
flow could decline significantly around 2015 as some of our CO2 industrial
sales contracts expire.
Fluctuations
in demand for CO2 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 CO2.
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, CO2, 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 CO2 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 CO2 industrial
operations are dependent on five customers and our syngas operations are
dependent on one customer.
If one or
more of those customers experience financial difficulties 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
CO2
operations are exposed to risks related to Denbury’s operation of its CO2 fields,
equipment and pipeline as well as any of our facilities that Denbury
operates.
Because
Denbury produces the CO2 and
transports the CO2 to our
customers (including Denbury), any major failure of its operations could have an
impact on our ability to meet our obligations to our CO2 customers.
We have no other supply of CO2 or method
to transport it to our customers. Sandhill relies on us for its
supply of CO2 therefore
our share of the earnings of Sandhill would also be impacted by any major
failure of Denbury’s CO2-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 CO2 pipeline
and the operator of the fields that produce our CO2
reserves. We are also parties to agreements with Denbury,
including the lease of the NEJD CO2 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.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
See Item
1. Business. We also have various operating leases for
rental of office space, office and field equipment, and vehicles. See
“Commitments and Off-Balance Sheet Arrangements” in Management’s Discussion and
Analysis of Financial Condition and Results of Operations, and Note 20 of the
Notes to the Consolidated Financial Statements for the future minimum rental
payments. Such information is incorporated herein by
reference.
Item 3. Legal Proceedings
We are
involved from time to time in various claims, lawsuits and administrative
proceedings incidental to our business. In our opinion, the ultimate
outcome, if any, of such proceedings is not expected to have a material adverse
effect on our financial condition, results of operations or cash
flows. (See Note 20 of the Notes to the Consolidated Financial
Statements.)
Item 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.
PART
II
Item 5. Market for Registrant’s Common Equity, Related
Stockholder Matters and Issuer Purchases of Equity Securities
Our
common units are listed on the 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.
Item 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 | |||||||||||||||
|
CO2
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 | |||||||||||||||
|
CO2
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 | |||||||||||||||
|
CO2
pipeline (Mcf per day) (5)
|
154,271 | 160,220 | - | - | - | |||||||||||||||
|
CO2
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)Our 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 CO2
pipeline in 2008.
|
|
|
(6)Volumes
relate to operations acquired in July
2007.
|
Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operation
Included
in Management’s Discussion and Analysis are the following sections:
|
|
·
|
Overview
of 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 CO2 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 CO2 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 CO2 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
CO2 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 CO2 pipeline
in Mississippi to transport CO2 to
Brookhaven oil field. Denbury has the exclusive right to use this
CO2
pipeline. This arrangement has been accounted for as a direct
financing lease.
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 CO2
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 CO2 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 CO2
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 CO2 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 CO2
marketing
|
$ | 16,206 | $ | 17,649 | $ | 16,158 | ||||||
|
CO2
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:
|
||||||||||||
|
CO2
marketing - Mcf
|
73,328 | 78,058 | 77,309 | |||||||||
CO2 –
Industrial Customers
We supply
CO2 to
industrial customers under seven long-term CO2 sales
contracts. The terms of our contracts with the industrial CO2 customers
include minimum take-or-pay and maximum delivery volumes. The maximum daily
contract quantity per year in the contracts totals 97,625 Mcf. Under
the minimum take-or-pay volumes, the customers must purchase a total of 51,048
Mcf per day whether received or not. Any volume purchased under the
take-or-pay provision in any year can then be recovered in a future year as long
as the minimum requirement is met in that year. 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 CO2. The
dominant months for beverage carbonation and freezing food are from April to
October, when warm weather increases demand for beverages and the approaching
holidays increase demand for frozen foods. The table below depicts
these seasonal fluctuations. The average daily sales (in Mcfs) of
CO2
for each quarter in 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 CO2 to our
customer. Volumes declined 6% between the periods as customers
reduced purchases. The average sales price of CO2 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 CO2 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 CO2. 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 CO2
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 CO2 volumetric
payments is based on the units-of-production method. We acquired
three volumetric production payments totaling 280 Mcf of CO2 from
Denbury between 2003 and 2005. Amortization is based on volumes sold
in relation to the volumes acquired. Amortization of CO2 volumetric
payments decreased in 2009 as a result of a slight decrease in the volume of
CO2
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 CO2 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 CO2 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