UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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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
period ended December 31, 2009
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OR
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR THE
SECURITIES EXCHANGE ACT OF 1934
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Commission
File number
000-51734
Calumet Specialty Products
Partners, L.P.
(Exact Name of Registrant as
Specified in Its Charter)
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Delaware
(State or Other Jurisdiction
of
Incorporation or Organization)
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2911
(Primary Standard
Industrial
Classification Code Number)
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37-1516132
(I.R.S. Employer
Identification Number)
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2780
Waterfront Pkwy E. Drive
Suite 200
Indianapolis, Indiana 46214
(317) 328-5660
(Address,
Including Zip Code, and Telephone Number,
Including Area Code, of Registrants Principal Executive
Offices)
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 representing limited partner interests
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The NASDAQ Stock Market
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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
Act. Yes o No þ
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 o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports) and (2) has been subject
to such filing requirements for the past
90 days. Yes þ No o
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 o No o
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 registrants 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. o
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. (Check one):
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Large
accelerated
filer o
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Accelerated
filer þ
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Non-accelerated
filer o
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Smaller
reporting
company o
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(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the
Act). Yes o No þ
The aggregate market value of the common units held by
non-affiliates of the registrant (treating all executive
officers and directors of the registrant and holders of 10% or
more of the common units outstanding, for this purpose, as if
they may be affiliates of the registrant) was approximately
$202.4 million on June 30, 2009, based on $15.50 per
unit, the closing price of the common units as reported on the
NASDAQ Global Select Market on such date.
At February 25, 2010, there were 22,213,778 common units
and 13,066,000 subordinated units outstanding.
DOCUMENTS
INCORPORATED BY REFERENCE
NONE.
CALUMET
SPECIALTY PRODUCTS PARTNERS, L.P.
FORM 10-K
2009 ANNUAL REPORT
Table of Contents
1
FORWARD-LOOKING
STATEMENTS
This Annual Report on
Form 10-K
(Form 10-K)
includes certain forward-looking statements within
the meaning of Section 27A of the Securities Act of 1933
and Section 21E of the Securities Exchange Act of 1934.
These statements can be identified by the use of forward-looking
terminology including may, believe,
expect, anticipate,
estimate, continue, or other similar
words. The statements regarding (i) expected settlements
with the Louisiana Department of Environmental Quality
(LDEQ) or other environmental and regulatory
liabilities, (ii) our anticipated levels of use of
derivatives to mitigate our exposure to crude oil price changes
and fuel products price changes, (iii) future compliance
with our debt covenants, and (iv) future activities
associated with our contractual arrangements with
LyondellBasell, as well as other matters discussed in this
Form 10-K
that are not purely historical data, are forward-looking
statements. These statements discuss future expectations or
state other forward-looking information and involve
risks and uncertainties. When considering these forward-looking
statements, unitholders should keep in mind the risk factors and
other cautionary statements included in this
Form 10-K.
The risk factors and other factors noted throughout this
Form 10-K
could cause our actual results to differ materially from those
contained in any forward-looking statement. These factors
include, but are not limited to, the following:
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the overall demand for specialty hydrocarbon products, fuels and
other refined products;
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our ability to produce specialty products and fuels that meet
our customers unique and precise specifications;
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the impact of fluctuations and rapid increases or decreases in
crude oil and crack spread prices, including the resulting
impact on our liquidity;
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the results of our hedging and other risk management activities;
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our ability to comply with financial covenants contained in our
credit agreements;
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the availability of, and our ability to consummate, acquisition
or combination opportunities;
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labor relations;
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our access to capital to fund expansions, acquisitions and our
working capital needs and our ability to obtain debt or equity
financing on satisfactory terms;
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successful integration and future performance of acquired
assets, businesses or third-party product supply and processing
relationships;
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environmental liabilities or events that are not covered by an
indemnity, insurance or existing reserves;
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maintenance of our credit ratings and ability to receive open
credit lines from our suppliers;
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demand for various grades of crude oil and resulting changes in
pricing conditions;
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fluctuations in refinery capacity;
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the effects of competition;
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continued creditworthiness of, and performance by,
counterparties;
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the impact of current and future laws, rulings and governmental
regulations;
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shortages or cost increases of power supplies, natural gas,
materials or labor;
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hurricane or other weather interference with business operations;
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fluctuations in the debt and equity markets;
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accidents or other unscheduled shutdowns; and
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general economic, market or business conditions.
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Other factors described herein, or factors that are unknown or
unpredictable, could also have a material adverse effect on
future results. Our forward-looking statements are not
guarantees of future performance, and actual results and future
performance may differ materially from those suggested in any
forward-looking statement. When considering forward-looking
statements, you should keep in mind the risk factors and other
cautionary statements in this
Form 10-K.
Please read Item 1A Risk Factors and
Item 6A Quantitative and Qualitative Disclosures
About Market Risk. We will not update these statements
unless securities laws require us to do so.
All subsequent written and oral forward-looking statements
attributable to us or to persons acting on our behalf are
expressly qualified in their entirety by the foregoing. We
undertake no obligation to publicly release the results of any
revisions to any such forward-looking statements that may be
made to reflect events or circumstances after the date of this
report or to reflect the occurrence of unanticipated events.
References in this
Form 10-K
to Calumet Specialty Products Partners, L.P.,
Calumet, the Partnership, the
Company, we, our, us
or like terms, when used in a historical context prior to
January 31, 2006, refer to the assets and liabilities of
Calumet Lubricants Co., Limited Partnership and its subsidiaries
of which substantially all such assets and liabilities were
contributed to Calumet Specialty Products Partners, L.P. and its
subsidiaries upon the completion of our initial public offering.
When used in the present tense or prospectively, those terms
refer to Calumet Specialty Products Partners, L.P. and its
subsidiaries. References to Predecessor in this
Form 10-K
refer to Calumet Lubricants Co., Limited Partnership. The
results of operations for the year ended December 31, 2006
for Calumet include the results of operations of the Predecessor
for the period of January 1, 2006 through January 31,
2006. References in this
Form 10-K
to our general partner refer to Calumet GP, LLC.
3
PART I
Items 1
and 2. Business and Properties
Overview
We are a leading independent producer of high-quality, specialty
hydrocarbon products in North America. We own plants located in
Princeton, Louisiana; Cotton Valley, Louisiana; Shreveport,
Louisiana; Karns City, Pennsylvania and Dickinson, Texas and a
terminal located in Burnham, Illinois. Our business is organized
into two segments: specialty products and fuel products. In our
specialty products segment, we process crude oil and other
feedstocks into a wide variety of customized lubricating oils,
white mineral oils, solvents, petrolatums and waxes. Our
specialty products are sold to domestic and international
customers who purchase them primarily as raw material components
for basic industrial, consumer and automotive goods. In our fuel
products segment, we process crude oil into a variety of fuel
and fuel-related products including gasoline, diesel and jet
fuel. In connection with our production of specialty products
and fuel products, we also produce asphalt and a limited number
of other by-products which are allocated to either the specialty
products or fuel products segment. The asphalt and other
by-products produced in connection with the production of
specialty products at our Princeton, Cotton Valley and
Shreveport refineries are included in our specialty products
segment. The by-products produced in connection with the
production of fuel products at our Shreveport refinery are
included in our fuel products segment. The fuel products
produced in connection with the production of specialty products
at our Princeton and Cotton Valley refineries and our Karns City
facility are included in our specialty products segment. For
2009, approximately 81.8% of our gross profit was generated from
our specialty products segment and approximately 18.2% of our
gross profit was generated from our fuel products segment. We
continue to focus on the growth of our specialty products
segment. The acquisition of Penreco on January 3, 2008 and
our entry into sales and processing agreements with
LyondellBasell, effective November 4, 2009, expanded our
specialty products offering and customer base. For additional
discussion of the Penreco acquisition and the LyondellBasell
contractual arrangements, please read Item 7
Managements Discussion and Analysis of Financial
Condition and Results of Operations Penreco
Acquisition and Managements Discussion and
Analysis of Financial Condition and Results of
Operations LyondellBasell Agreements.
Our operating assets and contractual agreements consist of our:
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Princeton Refinery. Our Princeton refinery,
located in northwest Louisiana and acquired in 1990, produces
specialty lubricating oils, including process oils, base oils,
transformer oils and refrigeration oils that are used in a
variety of industrial and automotive applications. The Princeton
refinery has aggregate crude oil throughput capacity of
approximately 10,000 barrels per day (bpd).
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Cotton Valley Refinery. Our Cotton Valley
refinery, located in northwest Louisiana and acquired in 1995,
produces specialty solvents that are used principally in the
manufacture of paints, cleaners and automotive products. The
Cotton Valley refinery has aggregate crude oil throughput
capacity of approximately 13,500 bpd.
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Shreveport Refinery. Our Shreveport refinery,
located in northwest Louisiana and acquired in 2001, produces
specialty lubricating oils and waxes, as well as fuel products
such as gasoline, diesel and jet fuel. The Shreveport refinery
has aggregate crude oil throughput capacity of approximately
60,000 bpd following the completion of a major expansion
project in May 2008.
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Karns City Facility. Our Karns City facility,
located in western Pennsylvania and acquired in the 2008 Penreco
acquisition, produces white mineral oils, petrolatums, solvents,
gelled hydrocarbons, cable fillers, and natural petroleum
sulfonates. The Karns City facility has aggregate feedstock
throughput capacity of approximately 5,500 bpd.
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Dickinson Facility. Our Dickinson facility,
located in southeastern Texas and acquired in the 2008 Penreco
acquisition, produces white mineral oils, compressor lubricants
and natural petroleum sulfonates. The Dickinson facility
currently has aggregate feedstock throughput capacity of
approximately 1,300 bpd.
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LyondellBasell Agreements. Effective
November 4, 2009, we entered into agreements with an
initial term of five years (the LyondellBasell
Agreements) with Houston Refining LP, a wholly-owned
subsidiary of LyondellBasell (Houston Refining), to
form a long-term exclusive specialty products affiliation. The
initial term of the LyondellBasell Agreements lasts until
October 31, 2014. After October 31, 2014 the
agreements are automatically extended for additional one-year
terms unless either party provides 24 months notice of a
desire to terminate either the initial term or any renewal term.
Under the terms of the LyondellBasell Agreements, (i) we
are the exclusive purchaser of Houston Refinings
naphthenic lubricating oil production at its Houston, Texas
refinery and are required to purchase a minimum of approximately
3,000 bpd, and (ii) Houston Refining will process a
minimum of approximately 800 bpd of white mineral oil for
us at its Houston, Texas refinery, which will supplement the
existing white mineral oil production at our Karns City,
Pennsylvania and Dickinson, Texas facilities. We also have
exclusive right to use certain LyondellBasell registered
trademarks and tradenames including Tufflo, Duoprime, Duotreat,
Crystex, Ideal and Aquamarine. The LyondellBasell Agreements
were deemed effective as of November 4, 2009 upon the
approval of LyondellBasells debtor motions before the
U.S. Bankruptcy Court.
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Distribution and Logistics Assets. We own and
operate a terminal in Burnham, Illinois with a storage capacity
of approximately 150,000 barrels that facilitates the
distribution of product in the Upper Midwest and East Coast
regions of the United States and in Canada. In addition, we
lease approximately 1,550 railcars to receive crude oil or
distribute our products throughout the United States and Canada.
We also have approximately 6.0 million barrels of aggregate
storage capacity at our facilities and leased storage locations.
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Business
Strategies
Our management team is dedicated to improving our operations by
executing the following strategies:
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Concentrate on stable cash flows. We intend to
continue to focus on businesses and assets that generate stable
cash flows. Approximately 52.6% of our sales and 81.8% of our
gross profit for 2009 were generated by the sale of specialty
products, a segment of our business which is characterized by
stable customer relationships due to our customers
requirements for highly specialized products. In addition, we
manage our exposure to crude oil price fluctuations in this
segment by passing on incremental feedstock costs to our
specialty products customers and by maintaining a shorter-term
crude oil hedging program. Also, in our fuel products segment,
which accounted for 18.2% of our gross profit in 2009, we seek
to mitigate our exposure to fuel products margin volatility by
maintaining a long-term hedging program. In 2009, fuel crack
spreads declined significantly and we partially offset this
impact with cash flows of $47.8 million in our fuel
products segment from derivatives used to hedge crack spreads.
In summary, we believe the diversity of our products, our broad
customer base and our hedging activities help contribute to the
stability of our cash flows.
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Develop and expand our customer
relationships. Due to the specialized nature of,
and the long lead-time associated with, the development and
production of many of our specialty products, our customers are
incentivized to continue their relationships with us. We believe
that our larger competitors do not work with customers as we do
from product design to delivery for smaller volume specialty
products like ours. We intend to continue to assist our existing
customers in expanding their product offerings as well as
marketing specialty product formulations to new customers. By
striving to maintain our long-term relationships with our
existing customers and by adding new customers, we seek to limit
our dependence on a small number of customers. Our Penreco
acquisition has allowed us to increase our customer base by
approximately 1,500 customers since January 1, 2008 and has
enhanced our ability to expand our product offering and to meet
our customers needs.
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Enhance profitability of our existing
assets. We continue to evaluate opportunities to
improve our existing asset base to increase our throughput,
profitability and cash flows. Following each of our asset
acquisitions, we have undertaken projects designed to maximize
the profitability of our acquired assets. We intend to further
increase the profitability of our existing asset base through
various measures which may include changing the product mix of
our processing units, debottlenecking and expanding units as
necessary to increase throughput, restarting idle assets and
reducing costs by improving operations. For example, in late
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2004 at the Shreveport refinery we recommissioned certain of its
previously idled fuels production units, refurbished existing
fuels production units, converted existing units to improve
gasoline blending profitability and expanded capacity to
approximately 42,000 bpd to increase lubricating oil and
fuels production. Also, in December 2006 we commenced
construction of an expansion project at our Shreveport refinery
that was completed and operational in May 2008 to increase its
aggregate crude oil throughput capacity from 42,000 bpd to
approximately 60,000 bpd. For additional discussion of this
project, please read Item 7 Managements
Discussion and Analysis of Financial Condition and Results of
Operations Liquidity and Capital
Resources Capital Expenditures. In 2009, we
focused on optimizing current operations including energy
savings initiatives, product quality enhancements, and product
yield improvements. We intend to continue this approach with our
existing assets in 2010.
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Pursue strategic and complementary
acquisitions. Since 1990, our management team has
demonstrated the ability to identify opportunities to acquire
assets and product lines where we can enhance operations and
improve profitability. In the future, we intend to continue to
make strategic acquisitions of assets or enter into agreements
with third parties that offer the opportunity for operational
efficiencies, the potential for increased utilization and
expansion of facilities, or the expansion of product offerings
in our specialty products segment. In addition, we may pursue
selected acquisitions in new geographic or product areas to the
extent we perceive similar opportunities. For example, on
January 3, 2008, we acquired Penreco from ConocoPhillips
Company (ConocoPhillips) and M.E. Zukerman Specialty
Oil Corporation for a purchase price of approximately
$269.1 million and effective November 4, 2009, we
entered into sales and processing agreements with LyondellBasell
related to naphthenic lubricating and white mineral oils. For
additional discussion please read Item 7
Managements Discussion and Analysis of Financial
Condition and Results of Operations Liquidity and
Capital Resources Capital Expenditures.
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Competitive
Strengths
We believe that we are well positioned to execute our business
strategies successfully based on the following competitive
strengths:
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We offer our customers a diverse range of specialty
products. We offer a wide range of over 1,000
specialty products. We believe that our ability to provide our
customers with a more diverse selection of products than our
competitors generally gives us an advantage in competing for new
business. We believe that we are the only specialty products
manufacturer that produces all four of naphthenic lubricating
oils, paraffinic lubricating oils, waxes and solvents. A
contributing factor to our ability to produce numerous specialty
products is our ability to ship products between our facilities
for product upgrading in order to meet customer specifications.
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We have strong relationships with a broad customer
base. We have long-term relationships with many
of our customers, and we believe that we will continue to
benefit from these relationships. Our customer base includes
over 2,600 companies and we are continually seeking new
customers. No single specialty products customer accounts for
more than 10% of our consolidated sales.
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Our facilities have advanced technology. Our
facilities are equipped with advanced, flexible technology that
allows us to produce high-grade specialty products and to
produce fuel products that comply with new low sulfur fuel
regulations. For example, our Shreveport and Cotton Valley
refineries have the capability to make all of their low sulfur
diesel into ultra low sulfur diesel and all of the Shreveport
refinerys gasoline production meets low sulfur standards
set by the U.S. Environmental Protection Agency
(EPA). Also, unlike larger refineries, which lack
some of the equipment necessary to achieve the narrow
distillation ranges associated with the production of specialty
products, our operations are capable of producing a wide range
of products tailored to our customers needs. We have also
upgraded the operations of many of our assets through our
investment in advanced, computerized refinery process controls.
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We have an experienced management team. Our
management has a proven track record of enhancing value through
the acquisition, exploitation and integration of refining assets
and the development and marketing of specialty products. Our
senior management team, the majority of whom have been working
together since 1990, has an average of over 25 years of
industry experience. Our teams extensive experience and
contacts
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within the refining industry provide a strong foundation and
focus for managing and enhancing our operations, accessing
strategic acquisition opportunities and constructing and
enhancing the profitability of new assets.
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Our
Operating Assets and Contractual Arrangements
General
We own and operate facilities in northwest Louisiana, which
consist of the Princeton refinery, the Cotton Valley refinery
and the Shreveport refinery, facilities in Karns City,
Pennsylvania and Dickinson, Texas, a terminal in Burnham,
Illinois. We also have contractual arrangements with
LyondellBasell and other third parties which provide us
additional volumes of finished products for our specialty
products segment.
The following table sets forth information about our combined
operations. Production volume differs from sales volume due to
changes in inventory. The following table does not include
operations of our Karns City, Pennsylvania and Dickinson, Texas
facilities for 2007, as we did not acquire these facilities
until January 3, 2008 with the acquisition of Penreco, nor
does it include LyondellBasell Agreements volumes in 2008 and
2007, as such agreements were not deemed effective until
November 4, 2009.
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Year Ended December 31,
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2009
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2008
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2007
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(In bpd)
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Total sales volume (1)
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57,086
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56,232
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47,663
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Total feedstock runs (2)
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60,081
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56,243
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48,354
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Production:
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Specialty products:
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Lubricating oils
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11,681
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12,462
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10,734
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Solvents
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7,749
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8,130
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5,104
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Waxes
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1,049
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1,736
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1,177
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Fuels
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853
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1,208
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1,951
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Asphalt and other by-products
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7,574
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6,623
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6,157
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Total
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28,906
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30,159
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25,123
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Fuel products:
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Gasoline
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9,892
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8,476
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7,780
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Diesel
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12,796
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10,407
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5,736
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Jet fuel
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6,709
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5,918
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7,749
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By-products
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489
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370
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1,348
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Total
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29,886
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25,171
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22,613
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Total production (3)
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58,792
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55,330
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47,736
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(1) |
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Total sales volume includes sales from the production of our
facilities and, beginning in 2008, certain third-party
facilities pursuant to supply and/or processing agreements, and
sales of inventories. |
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(2) |
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Total feedstock runs represents the barrels per day of crude oil
and other feedstocks processed at our facilities and, beginning
in 2008, at certain third-party facilities pursuant to supply
and/or processing agreements. The increase in feedstock runs in
2009 was due to the Shreveport refinery expansion project being
placed in service in May 2008 resulting in a full year of
increased production in 2009 compared to 2008 and the addition
of the LyondellBasell Agreements in 2009. Partially offsetting
this increase were lower overall feedstock runs at our other
facilities in 2009 compared to 2008 due to general economic
conditions. The increase in feedstock runs in 2008 compared to
2007 is primarily due to the acquisition of the Karns City and
the Dickinson facilities as part of the Penreco acquisition and
the completion of the Shreveport refinery expansion project in
May 2008. These |
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increases were partially offset by decreases in production rates
in the fourth quarter of 2008 due to scheduled turnarounds at
our Princeton, Cotton Valley and Shreveport refineries. |
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(3) |
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Total production represents the barrels per day of specialty
products and fuel products yielded from processing crude oil and
other feedstocks at our facilities and, beginning in 2008, at
certain third-party facilities pursuant to supply and/or
processing agreements. The difference between total production
and total feedstock runs is primarily a result of the time lag
between the input of feedstocks and production of finished
products and volume loss. The change in production mix to higher
fuel products production in 2009 compared to 2008 is due
primarily to reduced demand for certain specialty products due
to overall economic conditions. |
Set forth below is information regarding sales of our principal
products by segment.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Sales of specialty products:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lubricating oils
|
|
$
|
500.9
|
|
|
$
|
841.2
|
|
|
$
|
478.1
|
|
Solvents
|
|
|
260.2
|
|
|
|
419.8
|
|
|
|
199.8
|
|
Waxes
|
|
|
97.7
|
|
|
|
142.5
|
|
|
|
61.6
|
|
Fuels
|
|
|
9.0
|
|
|
|
30.4
|
|
|
|
52.5
|
|
Asphalt and other by-products
|
|
|
103.4
|
|
|
|
144.1
|
|
|
|
74.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
971.2
|
|
|
|
1,578.0
|
|
|
|
866.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of fuel products:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline
|
|
$
|
317.4
|
|
|
$
|
332.7
|
|
|
$
|
307.1
|
|
Diesel
|
|
|
372.4
|
|
|
|
379.7
|
|
|
|
203.7
|
|
Jet fuel
|
|
|
167.6
|
|
|
|
186.7
|
|
|
|
225.9
|
|
By-products
|
|
|
18.0
|
|
|
|
11.9
|
|
|
|
34.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
875.4
|
|
|
|
911.0
|
|
|
|
771.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated sales
|
|
$
|
1,846.6
|
|
|
$
|
2,489.0
|
|
|
$
|
1,637.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Princeton
Refinery
The Princeton refinery, located on a
208-acre
site in Princeton, Louisiana, has aggregate crude oil throughput
capacity of 10,000 bpd and is currently processing
naphthenic crude oil into lubricating oils, high sulfur diesel
and asphalt. The high sulfur diesel may be blended to produce
certain lubricating oils, transported to the Shreveport refinery
for further processing into ultra low sulfur diesel or sold to
third parties. The asphalt may be processed or blended for
coating and roofing applications at the Princeton refinery or
transported to the Shreveport refinery for processing into
bright stock.
The Princeton refinery currently consists of seven major
processing units, approximately 650,000 barrels of storage
capacity in 200 storage tanks and related loading and unloading
facilities and utilities. Since our acquisition of the Princeton
refinery in 1990, we have debottlenecked the crude unit to
increase production capacity to 10,000 bpd, increased the
hydrotreaters capacity to 7,000 bpd and upgraded the
refinerys fractionation unit, which has enabled us to
produce higher value specialty products. The following table
sets forth historical information about production at our
Princeton refinery.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Princeton Refinery
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In bpd)
|
|
|
Crude oil throughput capacity
|
|
|
10,000
|
|
|
|
10,000
|
|
|
|
10,000
|
|
Total feedstock runs (1)
|
|
|
6,076
|
|
|
|
6,516
|
|
|
|
7,226
|
|
Total refinery production (1)
|
|
|
5,999
|
|
|
|
6,551
|
|
|
|
7,198
|
|
8
|
|
|
(1) |
|
Total refinery production represents the barrels per day of
specialty products yielded from processing crude oil and other
feedstocks. The difference between total refinery production and
total feedstock runs is primarily a result of the time lag
between the input of feedstocks and production of finished
products and volume loss. |
The Princeton refinery has a hydrotreater and significant
fractionation capability enabling the refining of high quality
naphthenic lubricating oils at numerous distillation ranges. The
Princeton refinerys processing capabilities consist of
atmospheric and vacuum distillation, hydrotreating, asphalt
oxidation processing and clay/acid treating facilities. In
addition, we have the necessary tankage and technology to
process our asphalt into higher value applications such as
coatings and road paving.
The Princeton refinery receives crude oil via tank truck,
railcar and pipeline. Its crude oil supply primarily originates
from east Texas and north Louisiana and is purchased through
Legacy Resources Co., L.P. (Legacy Resources), a
related party. See Item 13 Certain Relationships, and
Related Transactions and Director Independence Crude
Oil Purchases for additional information regarding our
crude oil purchases from Legacy Resources. The Princeton
refinery ships its finished products throughout the country by
both truck and railcar service.
Cotton
Valley Refinery
The Cotton Valley refinery, located on a
77-acre site
in Cotton Valley, Louisiana, has aggregate crude oil throughput
capacity of 13,500 bpd, hydrotreating capacity of
5,100 bpd and is currently processing crude oil into
solvents, low sulfur diesel, fuel feedstocks and residual fuel
oil. The residual fuel oil is an important feedstock for
specialty refined products at our Shreveport refinery. We
believe the Cotton Valley refinery produces the most complete,
single-facility line of paraffinic solvents in the United States.
The Cotton Valley refinery currently consists of three major
processing units that include a crude unit, a hydrotreater and a
fractionation train, approximately 625,000 barrels of
storage capacity in 74 storage tanks and related loading and
unloading facilities and utilities. The Cotton Valley refinery
also has a utility fractionator for batch processing of narrow
distillation range specialty solvents. Since our acquisition in
1995, we have expanded the refinerys capabilities by
installing a hydrotreater that removes aromatics, increased the
crude unit processing capability to 13,500 bpd and
reconfigured the refinerys fractionation train to improve
product quality, enhance flexibility and lower utility costs.
The following table sets forth historical information about
production at our Cotton Valley refinery.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cotton Valley Refinery
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In bpd)
|
|
|
Crude oil throughput capacity
|
|
|
13,500
|
|
|
|
13,500
|
|
|
|
13,500
|
|
Total feedstock runs (1)(2)
|
|
|
5,466
|
|
|
|
6,175
|
|
|
|
6,775
|
|
Total refinery production (2)(3)
|
|
|
6,455
|
|
|
|
6,757
|
|
|
|
7,573
|
|
|
|
|
(1) |
|
Total feedstock runs do not include certain interplant solvent
feedstocks supplied by our Shreveport refinery. |
|
(2) |
|
Total refinery production represents the barrels per day of
specialty products yielded from processing crude oil and other
feedstocks. The difference between total refinery production and
total feedstock runs is primarily a result of the time lag
between the input of feedstocks and production of finished
products and volume loss. |
|
(3) |
|
Total refinery production includes certain interplant feedstocks
supplied to our Shreveport refinery. |
The Cotton Valley refinery configuration is flexible, which
allows us to respond to market changes and customer demands by
modifying its product mix. The reconfigured fractionation train
also allows the refinery to satisfy demand fluctuations
efficiently without large product inventory requirements.
The Cotton Valley refinery receives crude oil via truck and
through a pipeline system operated by a subsidiary of Plains All
American Pipeline, L.P. (Plains). Cotton
Valleys feedstock is primarily low sulfur, paraffinic
crude oil originating from north Louisiana and is purchased from
various marketers and gatherers. In addition, the refinery
9
receives feedstocks for solvent production from the Shreveport
refinery. The Cotton Valley refinery ships finished products
throughout the country by both truck and railcar service.
Shreveport
Refinery
The Shreveport refinery, located on a
240-acre
site in Shreveport, Louisiana, currently has aggregate crude oil
throughput capacity of 60,000 bpd subsequent to the
completion of a major expansion project in May 2008 and is
currently processing paraffinic crude oil and associated
feedstocks into fuel products, paraffinic lubricating oils,
waxes, residuals, and by-products.
The Shreveport refinery consists of 16 major processing units,
approximately 3.4 million barrels of storage capacity in
141 storage tanks and related loading and unloading facilities
and utilities. Since our acquisition of the Shreveport refinery
in 2001, we have expanded the refinerys capabilities by
adding additional processing and blending facilities, added a
second reactor to the high pressure hydrotreater, resumed
production of gasoline, diesel and other fuel products at the
refinery, and added both 18,000 bpd of capacity and the
capability to run up to 25,000 bpd of sour crude oil with
the expansion project completed in May 2008. The following table
sets forth historical information about production at our
Shreveport refinery.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shreveport Refinery
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In bpd)
|
|
|
Crude oil throughput capacity
|
|
|
60,000
|
|
|
|
60,000
|
|
|
|
42,000
|
|
Total feedstock runs (1)(2)
|
|
|
43,639
|
|
|
|
37,096
|
|
|
|
34,352
|
|
Total refinery production (2)(3)
|
|
|
43,467
|
|
|
|
35,566
|
|
|
|
32,819
|
|
|
|
|
(1) |
|
Total feedstock runs represents the barrels per day of crude oil
and other feedstocks processed at our Shreveport refinery. Total
feedstock runs do not include certain interplant feedstocks
supplied by our Cotton Valley refinery. The increase in
feedstock runs in 2009 compared to 2008 was due to the
Shreveport refinery expansion project being placed in service in
May 2008 resulting in a full year of increased production in
2009 compared to 2008. The increase in feedstock runs in 2008
compared to 2007 was primarily due to the completion of the
expansion project in May 2008, offset by decreases in production
rates in the fourth quarter of 2008 due to the economic downturn. |
|
(2) |
|
Total refinery production represents the barrels per day of
specialty products and fuel products yielded from processing
crude oil and other feedstocks. The difference between total
refinery production and total feedstock runs is primarily a
result of the time lag between the input of feedstocks and
production of finished products and volume loss. |
|
(3) |
|
Total refinery production includes certain interplant feedstocks
supplied to our Cotton Valley refinery and Karns City facility. |
We completed an expansion project in May 2008 that increased our
Shreveport refinerys aggregate crude oil throughput
capacity from approximately 42,000 bpd to approximately
60,000 bpd. For further discussion of this project, please
read Item 7 Managements Discussion and Analysis
of Financial Condition and Results of Operations
Liquidity and Capital Resources Capital
Expenditures.
The Shreveport refinery has a flexible operational configuration
and operating personnel that facilitate development of new
product opportunities. Product mix may fluctuate from one period
to the next to capture market opportunities. The refinery has an
idle residual fluid catalytic cracking unit, alkylation unit,
vacuum tower and a number of idle towers that can be utilized
for future project needs. Certain idle towers were utilized as a
part of the Shreveport refinery expansion project discussed
above.
The Shreveport refinery currently makes jet fuel, low sulfur
diesel and ultra low sulfur diesel and all of its gasoline
production currently meets low sulfur standards.
The Shreveport refinery receives crude oil from common carrier
pipeline systems operated by subsidiaries of Plains and Exxon
Mobil Corporation (ExxonMobil), each of which are
connected to the Shreveport refinerys
10
facilities. The Plains pipeline system delivers local supplies
of crude oil and condensates from north Louisiana and east
Texas. The ExxonMobil pipeline system delivers domestic crude
oil supplies from south Louisiana and foreign crude oil supplies
from the Louisiana Offshore Oil Port (LOOP) or other
crude oil terminals. In addition, trucks deliver crude oil
gathered from local producers to the Shreveport refinery.
The Shreveport refinery has direct pipeline access to the TEPPCO
Products Partners pipeline (TEPPCO pipeline), over
which it can ship all grades of gasoline, diesel and jet fuel.
The refinery also has direct access to the Red River Terminal
facility, which provides the refinery with barge access, via the
Red River, to major feedstock and petroleum products logistics
networks on the Mississippi River and Gulf Coast inland waterway
system. The Shreveport refinery also ships its finished products
throughout the country through both truck and railcar service.
Karns
City Facility
The Karns City facility, located on a
225-acre
site in Karns City, Pennsylvania, currently has aggregate base
oil throughput capacity of 5,500 bpd and is currently
processing white mineral oils, petrolatums, gelled hydrocarbons,
cable fillers, and natural petroleum sulfonates. The Karns City
facility consists of seven major processing units including
hydrotreating, bender treating, fractionation, acid treating,
filtering and blending, approximately 817,000 barrels of
storage capacity in 309 tanks and related loading and unloading
facilities and utilities. The facility receives its base oil
feedstocks by railcar and truck under long-term supply
agreements with various suppliers, the most significant of which
is ConocoPhillips. Please read Crude Oil and
Feedstock Supply for further discussion of the long-term
supply agreements with ConocoPhillips.
Dickinson
Facility
The Dickinson facility, located on a
28-acre site
in Dickinson, Texas, currently has aggregate base oil throughput
capacity of 1,300 bpd and is currently processing white
mineral oils, compressor lubricants, and natural petroleum
sulfonates. The Dickinson facility consists of three major
processing units including acid treating, filtering, and
blending, approximately 183,000 barrels of storage capacity
in 186 tanks and related loading and unloading facilities and
utilities. The facility receives its base oil feedstocks by
railcar and truck under long-term supply agreements with various
suppliers, the most significant of which is ConocoPhillips.
Please read Crude Oil and Feedstock
Supply for further discussion of the long-term supply
agreements with ConocoPhillips.
The following table sets forth the combined historical
information about production at our Karns City and Dickinson
facilities.
|
|
|
|
|
|
|
|
|
|
|
Combined Karns City
|
|
|
|
and Dickinson Facilities
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(in bpd)
|
|
|
Feedstock throughput capacity (1)
|
|
|
6,800
|
|
|
|
6,800
|
|
Total feedstock runs (2)
|
|
|
4,595
|
|
|
|
6,456
|
|
Total production (3)
|
|
|
4,590
|
|
|
|
6,456
|
|
|
|
|
(1) |
|
Includes Karns City and Dickinson facilities only. |
|
(2) |
|
Includes feedstock runs at our Karns City and Dickinson
facilities as well as throughput at certain third-party
facilities pursuant to supply and/or processing agreements and
includes certain interplant feedstocks supplied from our
Shreveport refinery. |
|
(3) |
|
Total production represents the barrels per day of specialty
products yielded from processing feedstocks at our Karns City
and Dickinson facilities and certain third-party facilities
pursuant to supply and/or processing agreements. The difference
between total production and total feedstock runs is primarily a
result of the time lag between the input of feedstocks and the
production of finished products. |
11
LyondellBasell
Agreements
Effective November 4, 2009, we entered into the
LyondellBasell Agreements with an initial term of five years,
with Houston Refining, a wholly-owned subsidiary of
LyondellBasell, to form a long-term exclusive specialty products
affiliation. The initial term of the LyondellBasell Agreements
lasts until October 31, 2014. After October 31, 2014
the agreements are automatically extended for additional
one-year terms unless either party provides 24 months
notice of a desire to terminate either the initial term or any
renewal term. Under the terms of the LyondellBasell Agreements,
(i) we are the exclusive purchaser of Houston
Refinings naphthenic lubricating oil production at its
Houston, Texas refinery and are required to purchase a minimum
of approximately 3,000 bpd, and (ii) Houston Refining
will process a minimum of approximately 800 bpd of white
mineral oil for us at its Houston, Texas refinery, which will
supplement the existing white mineral oil production at our
Karns City, Pennsylvania and Dickinson, Texas facilities. We
also have exclusive right to use certain LyondellBasell
registered trademarks and tradenames including Tufflo, Duoprime,
Duotreat, Crystex, Ideal and Aquamarine. The LyondellBasell
Agreements were deemed effective as of November 4, 2009
upon approval of LyondellBasells debtor motions before the
U.S. Bankruptcy Court.
The following table sets forth the combined historical
information about production under the LyondellBasell Agreements.
|
|
|
|
|
|
|
Houston Refining
|
|
|
Year Ended
|
|
|
December 31, 2009
|
|
|
(in bpd)
|
|
Feedstock throughput capacity (1)
|
|
|
4,500
|
|
Total production for Calumet (2)
|
|
|
1,994
|
|
|
|
|
(1) |
|
Estimated total capacity of the naphthenic lubricating oil and
white oil hydrotreating units at Houston Refinings
Houston, Texas refinery. |
|
(2) |
|
For 2009, represents the period from November 4, 2009
through December 31, 2009. |
Burnham
Terminal and Other Logistics Assets
We own and operate a terminal in Burnham, Illinois. The Burnham
terminal receives specialty products from each of our refineries
and distributes them by truck to our customers in the Upper
Midwest and East Coast regions of the United States and in
Canada.
The terminal includes a tank farm with 67 tanks with aggregate
lubricating oil, solvent and specialty product storage capacity
of approximately 150,000 barrels as well as blending
equipment. The Burnham terminal is complementary to our
refineries and plays a key role in moving our products to the
end-user market by providing the following services:
|
|
|
|
|
distribution;
|
|
|
|
blending to achieve specified products; and
|
|
|
|
storage and inventory management.
|
We also lease a fleet of approximately 1,550 railcars from
various lessors. This fleet enables us to receive crude oil and
distribute various specialty products throughout the United
States and Canada to and from each of our facilities.
Crude Oil
and Feedstock Supply
We purchase crude oil from major oil companies, various
gatherers and marketers in east Texas and north Louisiana and
from Legacy Resources, an affiliate of our general partner. The
Shreveport refinery also receives crude oil through the
ExxonMobil pipeline system originating in St. James, Louisiana,
which provides the refinery with access to domestic crude oils
and foreign crude oils through the LOOP or other terminal
locations.
12
In 2009, we purchased 23.6% of our crude oil supply through
evergreen crude oil supply contracts, which are typically
terminable on 30 days notice by either party,
approximately 39.8% of our crude oil supply from a subsidiary of
Plains under a term contract that became evergreen in July 2008,
and 5.1% of our crude oil supply on the spot market. Legacy
Resources supplied us with the remaining 31.5% of our crude oil
in 2009. Refer to Item 13, Certain Relationships and
Related Transactions and Director Independence Crude
Oil Purchases for further information on our related party
crude oil purchases. We also purchase foreign crude oil when its
spot market price is attractive relative to the price of crude
oil from domestic sources. We believe that adequate supplies of
crude oil will continue to be available to us.
Our cost to acquire crude oil and feedstocks and the prices for
which we ultimately can sell refined products depend on a number
of factors beyond our control, including regional and global
supply of and demand for crude oil and other feedstocks and
specialty and fuel products. These in turn are dependent upon,
among other things, the availability of imports, overall
economic conditions, the production levels of domestic and
foreign suppliers, U.S. relationships with foreign
governments, political affairs and the extent of governmental
regulation. We have historically been able to pass on the costs
associated with increased crude oil and feedstock prices to our
specialty products customers, although the increase in selling
prices for specialty products typically lags the rising cost of
crude oil. We use a hedging program to manage a portion of this
commodity price risk. Please read Item 7A
Quantitative and Qualitative Disclosures About Market
Risk Commodity Price Risk Crude Oil
Hedging Policy for a discussion of our crude oil hedging
program.
We have various long-term supply agreements with ConocoPhillips,
with remaining terms ranging from 1 to 8 years, with some
agreements operating under the option to continue on a
month-to-month
basis thereafter, for feedstocks that are key to the operations
of our Karns City and Dickinson facilities. In addition, certain
products of our refineries can be used as feedstocks by these
facilities. We believe that adequate supplies of feedstocks are
available for these facilities.
Markets
and Customers
We produce a full line of specialty products, including
lubricating oils, solvents and waxes. Our customers purchase
these products primarily as raw material components for basic
industrial, consumer and automotive goods. We also produce a
variety of fuel products.
We have an experienced marketing department with an average
industry tenure of 20 years. Our salespeople regularly
visit customers and our marketing department works closely with
both the laboratories at our refineries and our technical
department to help create specialized blends that will work
optimally for our customers.
Markets
Specialty Products. The specialty products
market represents a small portion of the overall petroleum
refining industry in the United States. Of the nearly 150
refineries currently in operation in the United States, only a
small number of the refineries are considered specialty products
producers and only a few compete with us in terms of the number
of products produced.
Our specialty products are utilized in applications across a
broad range of industries, including in:
|
|
|
|
|
industrial goods such as metal working fluids, belts, hoses,
sealing systems, batteries, hot melt adhesives, pressure
sensitive tapes, electrical transformers and refrigeration
compressors;
|
|
|
|
consumer goods such as candles, petroleum jelly, creams, tonics,
lotions, coating on paper cups, chewing gum base, automotive
aftermarket car-care products (fuel injection cleaners, tire
shines and polishes), lamp oils, charcoal lighter fluids,
camping fuel and various aerosol products; and
|
|
|
|
automotive goods such as motor oils, greases, transmission fluid
and tires.
|
We have the capability to ship our specialty products worldwide.
In the United States and Canada, we ship our specialty products
via railcars, trucks and barges. In 2009, about 35.3% of our
specialty products were shipped in our fleet of approximately
1,550 leased railcars, about 63.2% of our specialty products
shipped in trucks owned and operated by several different
third-party carriers and the remaining 1.5% were shipped via
water transportation. For
13
shipments outside of North America, which accounted for less
than 10% of our consolidated sales in 2009, we ship railcars and
trucks to several ports where the product is loaded on ships for
the customer.
Fuel Products. We produce a variety of fuel
and fuel-related products, primarily at our Shreveport refinery.
Fuel products produced at the Shreveport refinery can be sold
locally or through the TEPPCO pipeline. Local sales are made in
the TEPPCO terminal in Bossier City, Louisiana, which is
approximately 15 miles from the Shreveport refinery, as
well as from our own refinery terminal. Any excess volumes are
sold to marketers further up the TEPPCO pipeline.
During 2009, we sold approximately 10,200 bpd of gasoline
into the Louisiana, Texas and Arkansas markets, and any excess
volumes to marketers further up the TEPPCO pipeline. Should the
appropriate market conditions arise, we have the capability to
redirect and sell additional volumes into the Louisiana, Texas
and Arkansas markets rather than transport them to the Midwest.
Similar market conditions exist for our diesel production. We
sell the majority of our diesel locally but, similar to
gasoline, we occasionally sell the excess volumes to marketers
further up the TEPPCO pipeline during times of high diesel
production or for competitive reasons.
The Shreveport refinery also has the capacity to produce about
9,000 bpd of commercial jet fuel that can be marketed to
the Barksdale Air Force Base in Bossier City, Louisiana, sold as
Jet-A locally or via the TEPPCO pipeline, or transferred to the
Cotton Valley refinery to be processed further as a feedstock to
produce solvents. Jet fuel sales volumes change as the margins
between diesel and jet fuel change. We have a sales contract
with the U.S. Department of Defense covering the Barksdale
Air Force Base for approximately 5,200 bpd of jet fuel.
This contract is effective until April 2010 and is bid annually.
Additionally, we produce a number of fuel-related products
including fluid catalytic cracking (FCC) feedstock,
asphalt vacuum residuals and mixed butanes.
Vacuum residuals are blended or processed further to make
specialty asphalt products. Volumes of vacuum residuals which we
cannot process are sold locally into the fuel oil market or sold
via railcar to other producers. FCC feedstock is sold to other
refiners as a feedstock for their FCC units to make fuel
products. Butanes are primarily available in the summer months
and are primarily sold to local marketers. If the butanes are
not sold they are blended into our gasoline production.
Customers
Specialty Products. We have a diverse customer
base for our specialty products, with approximately 2,600 active
accounts. Most of our customers are long-term customers who use
our products in specialty applications which require six months
to two years to gain approval for use in their products. No
single customer of our specialty products segment accounted for
more that 10% of our consolidated sales in each of the three
years ended December 31, 2009, 2008 and 2007.
Fuel Products. We have a diverse customer base
for our fuel products, with approximately 90 active accounts. We
are able to sell the majority of the fuel products we produce to
the local markets of Louisiana, east Texas and Arkansas. We also
have the ability to ship our fuel products to the Midwest
through the TEPPCO pipeline should the need arise. During the
year ended December 31, 2008, the fuel products segment had
one customer, Murphy Oil U.S.A., which represented approximately
10.5% of consolidated sales due to rising gasoline and diesel
prices and increased fuel products sales to this customer. No
other fuel products segment customer represented 10% or greater
of consolidated sales in each of the three years ended
December 31, 2009, 2008 and 2007.
Competition
Competition in our markets is from a combination of large,
integrated petroleum companies, independent refiners and wax
production companies. Many of our competitors are substantially
larger than us and are engaged on a national or international
basis in many segments of the petroleum products business,
including refining, transportation and marketing. These
competitors may have greater flexibility in responding to or
absorbing market changes occurring in one or more of these
business segments. We distinguish our competitors according to
the
14
products that they produce. Set forth below is a description of
our significant competitors according to product category.
Naphthenic Lubricating Oils. Our primary
competitor in producing naphthenic lubricating oils is Ergon
Refining, Inc. We also compete with Cross Oil Refining and
Marketing, Inc. and San Joaquin Refining Co., Inc.
Paraffinic Lubricating Oils. Our primary
competitors in producing paraffinic lubricating oils include
ExxonMobil, Motiva Enterprises, LLC, ConocoPhillips,
Petro-Canada, Holly Corporation and Sonneborn Refined Products.
Paraffin Waxes. Our primary competitors in
producing paraffin waxes include ExxonMobil and The
International Group Inc.
Solvents. Our primary competitors in producing
solvents include Citgo Petroleum Corporation, Exxon Chemical and
ConocoPhillips.
Fuel Products. Our competitors in producing
fuels products in the local markets in which we operate include
Delek Refining, Ltd. and Lion Oil Company.
Our ability to compete effectively depends on our responsiveness
to customer needs and our ability to maintain competitive prices
and product offerings. We believe that our flexibility and
customer responsiveness differentiate us from many of our larger
competitors. However, it is possible that new or existing
competitors could enter the markets in which we operate, which
could negatively affect our financial performance.
Environmental,
Health and Safety Matters
We operate crude oil and specialty hydrocarbon refining and
terminal operations, which are subject to stringent and complex
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
can impair our operations that affect the environment in many
ways, such as requiring the acquisition of permits to conduct
regulated activities; restricting the manner in which the
Company can release materials into the environment; requiring
remedial activities or capital expenditures to mitigate
pollution from former or current operations; and imposing
substantial liabilities on us for pollution resulting from our
operations. Certain environmental laws impose joint and several,
strict liability for costs required to remediate and restore
sites where petroleum hydrocarbons, wastes, or other materials
have been released or disposed.
Failure to comply with environmental laws and regulations may
result in the triggering of administrative, civil and criminal
measures, including the assessment of monetary penalties, the
imposition of remedial obligations, and the issuance of
injunctions limiting or prohibiting some or all of our
operations. On occasion, we receive notices of violation,
enforcement and other complaints from regulatory agencies
alleging non-compliance with applicable environmental laws and
regulations. In particular, the Louisiana Department of
Environmental Quality (LDEQ) has proposed penalties
totaling approximately $0.4 million and supplemental
projects for the following alleged violations: (i) a May
2001 notification received by the Cotton Valley refinery from
the LDEQ regarding several alleged violations of various air
emission regulations, as identified in the course of our Leak
Detection and Repair program, and also for failure to submit
various reports related to the facilitys air emissions;
(ii) a December 2002 notification received by the Cotton
Valley refinery from the LDEQ regarding alleged violations for
excess emissions, as identified in the LDEQs file review
of the Cotton Valley refinery; (iii) a December 2004
notification received by the Cotton Valley refinery from the
LDEQ regarding alleged violations for the construction of a
multi-tower pad and associated pump pads without a permit issued
by the agency; and (iv) an August 2005 notification
received by the Princeton refinery from the LDEQ regarding
alleged violations of air emissions regulations, as identified
by LDEQ following performance of a compliance review, due to
excess emissions and failures to continuously monitor and record
air emission levels. We anticipate that any penalties that may
be assessed due to the alleged violations at our Princeton
refinery as well as the aforementioned penalties related to the
Cotton Valley refinery will be consolidated in a settlement
agreement that we anticipate executing with the LDEQ in
connection with the agencys Small Refinery and
Single Site Refinery Initiative described below.
15
The clear trend in environmental regulation is to place more
restrictions and limitations on activities that may affect the
environment, and thus, any changes in environmental laws and
regulations that result in more stringent and costly waste
handling, storage, transport, disposal, or remediation
requirements could have a material adverse effect on our
operations and financial position. Moreover, in connection with
accidental spills or releases associated with our operations, we
cannot assure our unitholders that we will not incur substantial
costs and liabilities as a result of such spills or releases,
including those relating to claims for damage to property and
persons. In the event of future increases in costs, we may be
unable to pass on those increases to our customers. While we
believe that we are in substantial compliance with existing
environmental laws and regulations and that continued compliance
with these requirements will not have a material adverse effect
on us, there can be no assurance that our environmental
compliance expenditures will not become material in the future.
Air
Our operations are subject to the federal Clean Air Act, as
amended, and comparable state and local laws. The Clean Air Act
Amendments of 1990 require most industrial operations in the
U.S. to incur capital expenditures to meet the air emission
control standards that are developed and implemented by the EPA
and state environmental agencies. Under the Clean Air Act,
facilities that emit volatile organic compounds or nitrogen
oxides face increasingly stringent regulations, including
requirements to install various levels of control technology on
sources of pollutants. In addition, the petroleum refining
sector has come under stringent new EPA regulations, imposing
maximum achievable control technology (MACT) on
refinery equipment emitting certain listed hazardous air
pollutants. Some of our facilities have been included within the
categories of sources regulated by MACT rules. In addition, air
permits are required for our refining and terminal operations
that result in the emission of regulated air contaminants. These
permits incorporate stringent control technology requirements
and are subject to extensive review and periodic renewal.
Excluding consideration of the alleged air violations discussed
in this Environmental, Health and Safety Matters section for
which we are currently discussing settlement with the LDEQ, we
believe that we are in substantial compliance with the Clean Air
Act and similar state and local laws.
The Clean Air Act authorizes the EPA to require modifications in
the formulation of the refined transportation fuel products we
manufacture in order to limit the emissions associated with the
fuel products final use. For example, in December 1999,
the EPA promulgated regulations limiting the sulfur content
allowed in gasoline. These regulations required the phase-in of
gasoline sulfur standards beginning in 2004, with special
provisions for small refiners and for refiners serving those
Western states exhibiting lesser air quality problems.
Similarly, the EPA promulgated regulations that limit the sulfur
content of highway diesel beginning in 2006 from its former
level of 500 parts per million (ppm) to 15 ppm
(the ultra low sulfur standard). The Shreveport
refinery has implemented the sulfur standard with respect to
gasoline in its production and produces diesel meeting the ultra
low sulfur standard.
We are party to ongoing discussions on a voluntary basis with
the LDEQ regarding the Companys participation in that
agencys Small Refinery and Single Site Refinery
Initiative. This state initiative is patterned after the
EPAs National Petroleum Refinery Initiative,
which is a coordinated, integrated compliance and enforcement
strategy to address federal Clean Air Act compliance issues at
the nations largest petroleum refineries. We expect that
the LDEQs primary focus under the state initiative will be
on four compliance and enforcement concerns: (i) Prevention
of Significant Deterioration/New Source Review; (ii) New
Source Performance Standards for fuel gas combustion devices,
including flares, heaters and boilers; (iii) Leak Detection
and Repair requirements; and (iv) Benzene Waste Operations
National Emission Standards for Hazardous Air Pollutants. We are
in discussions with the LDEQ regarding our participation in this
regulatory initiative and anticipate that we will be entering
into a settlement agreement with the LDEQ pursuant to which we
will be required to make emissions reductions requiring capital
investments between approximately $1.0 million and
$3.0 million in total over a three to five year period at
our three Louisiana refineries. Because the settlement agreement
is also expected to resolve the alleged air emissions issues at
our Cotton Valley and Princeton refineries and consolidate any
penalties associated with such issues, we further anticipate
that a penalty of approximately $0.4 million will be
assessed in connection with this settlement agreement.
16
Climate
Change
Recent studies suggest that emissions of carbon dioxide and
certain other gases, referred to as greenhouse gases
(GHG) may be contributing to warming of the
earths atmosphere and other climatic changes. On
June 26, 2009, the U.S. House of Representatives
passed the American Clean Energy and Security Act of
2009, or ACESA, which would establish an
economy-wide
cap-and-trade
program to reduce U.S. emissions of carbon dioxide and
other GHG. ACESA would require a 17 percent reduction in
GHG emissions from 2005 levels by 2020 and just over an
80 percent reduction of such emissions by 2050. Under this
legislation, the U.S. Environmental Protection Agency
(EPA) would issue a capped and steadily declining
number of tradable emissions allowances to certain major sources
of GHG emissions so that such sources could continue to emit
GHGs into the atmosphere. These allowances would be expected to
escalate significantly in cost over time. The net effect of
ACESA would be to impose increasing costs on the combustion of
carbon-based fuels such as refined petroleum products, oil and
natural gas. The U.S. Senate has begun work on its own
legislation for restricting domestic GHG emissions and President
Obama has indicated his support of legislation to reduce GHG
emissions through an emission allowance system. In addition,
more than one-third of U.S. states, either individually or
through multi-state regional initiatives, have already begun
implementing legal measures to reduce emissions of GHGs.
If an upstream
cap-and-trade
system were to be adopted at either the state, regional, or
federal level, we could be required to purchase and surrender
emissions allowances for the GHG emissions attributable to the
combustion of the fuels we produce. Although we would not be
impacted to a greater degree than other similarly situated
refiners of oil, a stringent GHG control program could have an
adverse effect on our operations, financial condition, and cash
flows.
Also, on December 15, 2009, the EPA published its findings
that emissions of GHGs constitute an endangerment to public
health and the environment. These findings allow the EPA to
adopt and implement regulations that would restrict emissions of
GHGs under existing provisions of the federal Clean Air Act.
Accordingly, the EPA has already proposed two sets of
regulations that would require a reduction in emissions of GHGs
from motor vehicles and could trigger permit review for GHG
emissions from certain stationary sources. In addition, on
September 22, 2009, the EPA issued a final rule requiring
the reporting of GHG emissions from specified large GHG emission
sources in the United States, including petroleum refineries, on
an annual basis beginning in 2011 for emissions occurring after
January 1, 2010. Although it is not possible at this time
to predict how legislation or new regulations imposing GHG
reporting obligations on, or limiting emissions of GHGs from,
our equipment or operations would impact our business, any such
new federal, regional or state restrictions on emissions of
carbon dioxide or other greenhouse gases that may be imposed in
areas in which we conduct business could also have an adverse
effect on our cost of doing business and demand for the oil we
refine.
Hazardous
Substances and Wastes
The Comprehensive Environmental Response, Compensation and
Liability Act, as amended (CERCLA), also known as
the Superfund law, and comparable state laws impose
liability without regard to fault or the legality of the
original conduct, on certain classes of persons who are
considered to be responsible for the release of a hazardous
substance into the environment. Such classes of persons include
the current and past owners and operators of sites where a
hazardous substance was released, and companies that disposed or
arranged for disposal of hazardous substances at offsite
locations, such as landfills. Under CERCLA, these
responsible persons may be subject to joint and
several, strict 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. It is not uncommon for neighboring
landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the release of
hazardous substances into the environment. In the course of our
operations, we generate wastes or handle substances that may be
regulated as hazardous substances, and we could become subject
to liability under CERCLA and comparable state laws.
We also may incur liability under the Resource Conservation and
Recovery Act (RCRA), and comparable state laws,
which impose requirements related to the handling, storage,
treatment, and disposal of solid and hazardous wastes. In the
course of our operations, we generate petroleum product wastes
and ordinary industrial wastes, such as paint wastes, waste
solvents, and waste oils, that may be regulated as hazardous
wastes. In addition, our operations also generate solid wastes,
which are regulated under RCRA and state law. We believe that we
are in
17
substantial compliance with the existing requirements of RCRA
and similar state and local laws, and the cost involved in
complying with these requirements is not material.
We currently own or operate, and have in the past owned or
operated, properties that for many years have been used for
refining and terminal activities. These properties have in the
past been operated by third parties whose treatment and disposal
or release of petroleum hydrocarbons and wastes was not under
our control. Although we used operating and disposal practices
that were standard in the industry at the time, petroleum
hydrocarbons or wastes have been released on or under the
properties owned or operated by us. These properties and the
materials disposed or released on them may be subject to CERCLA,
RCRA and analogous state laws. Under such laws, we could be
required to remove or remediate previously disposed wastes or
property contamination, or to perform remedial activities to
prevent future contamination.
Voluntary remediation of subsurface contamination is in process
at each of our refinery sites. The remedial projects are being
overseen by the appropriate state agencies. Based on current
investigative and remedial activities, we believe that the
groundwater contamination at these refineries can be controlled
or remedied without having a material adverse effect on our
financial condition. However, such costs are often unpredictable
and, therefore, there can be no assurance that the future costs
will not become material. We currently anticipate that we will
incur approximately $0.7 million of costs at our Cotton
Valley refinery in connection with continued remediation of
groundwater impacts at that site, the majority of which are
expected to be incurred during 2010.
Water
The Federal Water Pollution Control Act of 1972, as amended,
also known as the Clean Water Act, and analogous state laws
impose restrictions and stringent controls on the discharge of
pollutants, including oil, into federal and state waters. Such
discharges are prohibited, except in accordance with the terms
of a permit issued by the EPA or the appropriate state agencies.
Any unpermitted release of pollutants, including crude or
hydrocarbon specialty oils as well as refined products, could
result in penalties, as well as significant remedial
obligations. Spill prevention, control, and countermeasure
requirements of federal laws require appropriate containment
berms and similar structures to help prevent the contamination
of navigable waters in the event of a petroleum hydrocarbon tank
spill, rupture, or leak. We believe that we are in substantial
compliance with the requirements of the Clean Water Act.
The primary federal law for oil spill liability is the Oil
Pollution Act of 1990, as amended (OPA), which
addresses three principal areas of oil pollution
prevention, containment, and cleanup. OPA applies to vessels,
offshore facilities, and onshore facilities, including
refineries, terminals, and associated facilities that may affect
waters of the U.S. Under OPA, responsible parties,
including owners and operators of onshore facilities, may be
subject to oil cleanup costs and natural resource damages as
well as a variety of public and private damages from oil spills.
We believe that we are in substantial compliance with OPA and
similar state laws.
Health,
Safety and Maintenance
We are subject to the requirements of the Federal Occupational
Safety and Health Act (OSHA) and comparable state
occupational safety statutes. These laws and the implementing
regulations strictly govern the protection of the health and
safety of employees. In addition, OSHAs hazard
communication standard requires that information be maintained
about hazardous materials used or produced in our operations and
that this information be available to employees and contractors
and, where required, to state and local government authorities
and to local residents. We provide all required information to
employees and contractors on how to avoid or protect against
exposure to hazardous materials present in our operations. Also,
we maintain safety, training, and maintenance programs as part
of our ongoing efforts to ensure compliance with applicable laws
and regulations. While the nature of our business may result in
industrial accidents from time to time, we believe that we have
operated in substantial compliance with OSHA and similar state
laws, including general industry standards, recordkeeping and
reporting, hazard communication and process safety management.
We have implemented an internal program of inspection designed
to monitor and enforce compliance with worker safety
requirements as well as a quality system that meets the
requirements of the
ISO-9001-2000
Standard. The integrity of our
ISO-9001-2000
Standard certification is maintained through surveillance audits
by our registrar at regular intervals designed to ensure
adherence to the
18
standards. In April 2010, we expect to receive our certification
to the
ISO-9001-2008
Standard. Our compliance with applicable health and safety laws
and regulations has required and continues to require
substantial expenditures. Changes in safety and health laws and
regulations or a finding of non-compliance with current laws and
regulations could result in additional capital expenditures or
operating expenses, as well as civil penalties and, in the case
of a fatality, criminal charges.
We have commissioned studies, some of which have been recently
received, to assess the adequacy of our process safety
management practices at our Shreveport refinery with respect to
certain consensus codes and standards. We expect to have fully
reviewed the findings made in these studies during the first
quarter of 2010 and may incur capital expenditures over the next
several years to enhance our programs and equipment in order to
maintain our compliance with applicable requirements at the
Shreveport refinery. We believe the related findings will not
have a material adverse impact on our financial position,
results of operations or cash flow.
We also perform preventive and normal maintenance on all of our
refining and logistics assets and make repairs and replacements
when necessary or appropriate. We also conduct inspections of
these assets as required by law or regulation.
Other
Environmental Items
We are indemnified by Shell Oil Company, as successor to
Pennzoil-Quaker State Company and Atlas Processing Company, for
specified environmental liabilities arising from operations of
the Shreveport refinery prior to our acquisition of the
facility. The indemnity is unlimited in amount and duration, but
requires us to contribute up to $1.0 million of the first
$5.0 million of indemnified costs for certain of the
specified environmental liabilities.
We are indemnified on a limited basis by ConocoPhillips and M.E.
Zuckerman Specialty Oil Corporation, former owners of Penreco,
for pending, threatened, contemplated or contingent
environmental claims against Penreco of which we were unaware
upon our acquisition of Penreco. A significant portion of these
indemnifications expired in January 2010 without any claims
having been asserted by us and were generally subject to a
$2.0 million limit.
Insurance
Our operations are subject to certain hazards of operations,
including fire, explosion and weather-related perils. We
maintain insurance policies, including business interruption
insurance for each of our facilities, with insurers in amounts
and with coverage and deductibles that we, with the advice of
our insurance advisors and brokers, believe are reasonable and
prudent. We cannot, however, ensure that this insurance will be
adequate to protect us from all material expenses related to
potential future claims for personal and property damage or that
these levels of insurance will be available in the future at
economical prices. We are not fully insured against certain
risks because such risks are not fully insurable, coverage is
unavailable, or premium costs, in our judgment, do not justify
such expenditures.
Seasonality
The operating results for the fuel products segment and the
selling prices of asphalt products we produce can be seasonal.
Asphalt demand is generally lower in the first and fourth
quarters of the year as compared to the second and third
quarters due to the seasonality of annual road construction.
Demand for gasoline is generally higher during the summer months
than during the winter months due to seasonal increases in
highway traffic. In addition, our natural gas costs can be
higher during the winter months. As a result, our operating
results for the first and fourth calendar quarters may be lower
than those for the second and third calendar quarters of each
year due to this seasonality.
19
Title to
Properties
We own the following properties, which are pledged as collateral
under our existing credit facilities as discussed in Item 7
Managements Discussion and Analysis of Financial
Condition and Results of Operations Liquidity and
Capital Resources Debt and Credit Facilities.
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Acres
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Location
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Shreveport refinery
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240
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Shreveport, Louisiana
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Princeton refinery
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208
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Princeton, Louisiana
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Cotton Valley refinery
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77
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Cotton Valley, Louisiana
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Burnham terminal
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11
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Burnham, Illinois
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Karns City facility
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225
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Karns City, Pennsylvania
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Dickinson facility
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28
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Dickinson, Texas
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Office
Facilities
In addition to our refineries and terminal discussed above, we
occupy approximately 26,900 square feet of office space in
Indianapolis, Indiana under a lease. We also lease but are not
currently using approximately 14,500 square feet of office
space in The Woodlands, Texas under a lease as a result of the
2008 Penreco acquisition. While we may require additional office
space as our business expands, we believe that our existing
facilities are adequate to meet our needs for the immediate
future and that additional facilities will be available on
commercially reasonable terms as needed. We expect that we will
not renew our lease of our facility in The Woodlands, Texas at
its expiration on April 30, 2012 and are actively engaged
in efforts to sublease this office space for the remainder of
the lease term.
Employees
As of February 23, 2010, our general partner employs
approximately 620 people who provide direct support to the
Companys operations. Of these employees, approximately 330
are covered by collective bargaining agreements. Employees at
the Princeton and Cotton Valley refineries are covered by
separate collective bargaining agreements with the International
Union of Operating Engineers, having expiration dates of
October 31, 2011 and March 31, 2010, respectively.
Employees at the Shreveport refinery are covered by a collective
bargaining agreement with the United Steel, Paper and Forestry,
Rubber, Manufacturing, Energy, Allied-Industrial, and Service
Workers International Union which expires on April 30,
2010. The Karns City, Pennsylvania facility employees are
covered by a collective bargaining agreement with United Steel
Workers that will expire on January 31, 2012. The
Dickinson, Texas facility employees are covered by a collective
bargaining agreement with the International Union of Operating
Engineers that will expire on March 31, 2013. None of the
employees at the Burnham terminal are covered by collective
bargaining agreements. Our general partner considers its
employee relations to be good, with no history of work stoppages.
Address,
Internet Website and Availability of Public Filings
Our principal executive offices are located at 2780 Waterfront
Parkway East Drive, Suite 200, Indianapolis, Indiana 46214
and our telephone number is
(317) 328-5660.
Our website is located at
http://www.calumetspecialty.com.
We make the following information available free of charge on
our website:
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Annual Report on
Form 10-K;
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Quarterly Reports on
Form 10-Q;
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Current Reports on
Form 8-K;
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Amendments to those reports filed or furnished pursuant to
Section 13(a) or 15(d) of the Securities Exchange Act of
1934;
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Charters for the Audit, Compensation and Conflicts
Committees; and
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Code of Business Conduct and Ethics.
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Our Securities and Exchange Commission (SEC) filings
are available on our website as soon as reasonably practicable
after we electronically file such material with, or furnish such
material to, the SEC. The above information is available to
anyone who requests it and is free of charge either in print
from our website or upon request by contacting investor
relations using the contact information listed above.
We may
not have sufficient cash from operations to enable us to pay the
minimum quarterly distribution following the establishment of
cash reserves and payment of fees and expenses, including
payments to our general partner.
We may not have sufficient available cash from operations each
quarter to enable us to pay the minimum quarterly distribution.
Under the terms of our partnership agreement, we must pay
expenses, including payments to our general partner, and set
aside any cash reserve amounts before making a distribution to
our unitholders. The amount of cash we can distribute on our
units principally depends upon the amount of cash we generate
from our operations, which is primarily dependent upon our
producing and selling quantities of fuel and specialty products,
or refined products, at margins that are high enough to cover
our fixed and variable expenses. Crude oil costs, fuel and
specialty products prices and, accordingly, the cash we generate
from operations, will fluctuate from quarter to quarter based
on, among other things:
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overall demand for specialty hydrocarbon products, fuel and
other refined products;
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the level of foreign and domestic production of crude oil and
refined products;
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our ability to produce fuel and specialty products that meet our
customers unique and precise specifications;
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the marketing of alternative and competing products;
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the extent of government regulation;
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results of our hedging activities; and
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overall economic and local market conditions.
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In addition, the actual amount of cash we will have available
for distribution will depend on other factors, some of which are
beyond our control, including:
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the level of capital expenditures we make, including those for
acquisitions, if any;
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our debt service requirements;
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fluctuations in our working capital needs;
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our ability to borrow funds and access capital markets;
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restrictions on distributions and on our ability to make working
capital borrowings for distributions contained in our credit
facilities; and
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the amount of cash reserves established by our general partner
for the proper conduct of our business.
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The
amount of cash we have available for distribution to unitholders
depends primarily on our cash flow and not solely on
profitability.
Unitholders should be aware that the amount of cash we have
available for distribution depends primarily upon our cash flow,
including cash flow from financial reserves and working capital
borrowings, and not solely on profitability, which will be
affected by non-cash items. As a result, we may make cash
distributions during periods when we record net losses and may
not make cash distributions during periods when we record net
income.
21
Decreases
in the price of crude oil may lead to a reduction in the
borrowing base under our revolving credit facility or the
requirement that we post substantial amounts of cash collateral
for derivative instruments , either of which would adversely
affect our liquidity, financial condition and our ability to
distribute cash to our unitholders.
The borrowing base under our revolving credit facility is
redetermined weekly or monthly depending upon availability
levels. Reductions in the value of our inventories as a result
of lower crude oil prices could result in a reduction in our
borrowing base, which would reduce our amount of financial
resources available to meet our capital requirements. Further,
if at any time our available capacity under our revolving credit
facility falls below $35.0 million, we may be required by
our lenders to take steps to reduce our leverage, pay off our
debts on an accelerated basis, limit or eliminate distributions
to our unitholders or take other similar measures. In addition,
decreases in the price of crude oil, may require us to post
substantial amounts of cash collateral to our hedging
counterparties in order to maintain our hedging positions. At
December 31, 2009, we had $107.3 million in
availability under our revolving credit facility. Please read
Item 7 Managements Discussion and Analysis of
Financial Condition and Results of Operations
Liquidity and Capital Resources Debt and Credit
Facilities for additional information. If the borrowing
base under our revolving credit facility decreases or we are
required to post substantial amounts of cash collateral to our
hedging counterparties, it would have a material adverse effect
on our liquidity, financial condition and our ability to
distribute cash to our unitholders.
Our
credit agreements contain operating and financial restrictions
that may restrict our business and financing
activities.
The operating and financial restrictions and covenants in our
credit agreements and any future financing agreements could
restrict our ability to finance future operations or capital
needs or to engage, expand or pursue our business activities.
For example, our credit agreements restrict our ability to:
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pay distributions;
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incur indebtedness;
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grant liens;
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make certain acquisitions and investments;
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make capital expenditures above specified amounts;
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redeem or prepay other debt or make other restricted payments;
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enter into transactions with affiliates;
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enter into a merger, consolidation or sale of assets; and
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cease our crack spread hedging program.
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Our ability to comply with the covenants and restrictions
contained in our credit agreements may be affected by events
beyond our control. If market or other economic conditions
deteriorate, our ability to comply with these covenants may be
impaired. If we violate any of the restrictions, covenants,
ratios or tests in our credit agreements, a significant portion
of our indebtedness may become immediately due and payable, our
ability to make distributions may be inhibited and our
lenders commitment to make further loans to us may
terminate. We might not have, or be able to obtain, sufficient
funds to make these accelerated payments. In addition, our
obligations under our credit agreements are secured by
substantially all of our assets and if we are unable to repay
our indebtedness under our credit agreements, the lenders could
seek to foreclose on our assets.
The senior secured term loan credit agreement and amendment to
our existing revolving credit facility that we executed on
January 3, 2008 contain operating and financial
restrictions similar to the above listed items. Financial
covenants in the term loan credit agreement and the amended
revolving credit facility agreement include a maximum
consolidated leverage ratio of not more than 3.75 to 1.00 and a
minimum consolidated interest coverage ratio of 2.75 to 1.00.
The failure to comply with any of these or other covenants would
cause a default under the credit facilities. A default, if not
waived, could result in acceleration of our debt, in which case
the debt would become immediately due and payable. If this
occurs, we may not be able to repay our debt or borrow
sufficient funds
22
to refinance it. Even if new financing were available, it may be
on terms that are less attractive to us than our then existing
credit facilities or it may not be on terms that are acceptable
to us.
From time to time, our cash needs may exceed our internally
generated cash flows, and our business could be materially and
adversely affected if we were unable to obtain necessary funds
from financing activities. From time to time, we may need to
supplement our cash generation with proceeds from financing
activities. Our revolving credit facility provides us with
available financing to meet our ongoing cash needs. Uncertainty
and illiquidity continues to exist in the financial markets that
may materially impact the ability of the participating financial
institutions to fund their commitments to us under our revolving
credit facility. In light of these uncertainties and the
volatile current market environment, we can make no assurances
that we will be able to obtain the full amount of the funds
available under our financing facilities to satisfy our cash
requirements. Our failure to do so could have a material adverse
effect on our operations and financial position.
Due to these factors, we cannot be certain that funding will be
available if needed and to the extent required, on acceptable
terms. If funding is not available when needed, or is available
only on unfavorable terms, we may be unable to meet our
obligations as they come due or be required to post collateral
to support our obligations, or we may be unable to implement our
business development plans, enhance our existing business
opportunities or respond to competitive pressures, any of which
could have a material adverse effect on our production, revenues
and results of operations.
Refining
margins are volatile, and a reduction in our refining margins
will adversely affect the amount of cash we will have available
for distribution to our unitholders.
Historically, refining margins have been volatile, and they are
likely to continue to be volatile in the future. Our financial
results are primarily affected by the relationship, or margin,
between our specialty products prices and fuel products prices
and the prices for crude oil and other feedstocks. The cost to
acquire our feedstocks and the price at which we can ultimately
sell our refined products depend upon numerous factors beyond
our control.
A widely used benchmark in the fuel products industry to measure
market values and margins is the Gulf Coast
3/2/1 crack
spread, which represents the approximate gross margin
resulting from refining crude oil, assuming that three barrels
of a benchmark crude oil are converted, or cracked, into two
barrels of gasoline and one barrel of heating oil. The Gulf
Coast 3/2/1
crack spread, as reported by Bloomberg L.P., has averaged as
follows:
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Time Period
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Crack spread
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1990 to 1999
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$
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3.04
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2000 to 2004
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$
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4.61
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2005
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$
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10.63
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2006
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$
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10.70
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2007
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$
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14.27
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2008
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$
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9.98
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First quarter 2009
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$
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10.38
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Second quarter 2009
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$
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9.93
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Third quarter 2009
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$
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8.51
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Fourth quarter 2009
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$
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5.92
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Calendar year 2009
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$
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8.68
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Our actual refining margins vary from the Gulf Coast
3/2/1 crack
spread due to the actual crude oil used and products produced,
transportation costs, regional differences, and the timing of
the purchase of the feedstock and sale of the refined products,
but we use the Gulf Coast
3/2/1 crack
spread as an indicator of the volatility and general levels of
refining margins.
The prices at which we sell specialty products are strongly
influenced by the commodity price of crude oil. If crude oil
prices increase, our specialty products segments margins
will fall unless we are able to pass along these price increases
to our customers. Increases in selling prices for specialty
products typically lag the rising cost of crude oil and may be
difficult to implement when crude oil costs increase
dramatically over a short period of time.
23
For example, in the first six months of 2008, excluding the
effects of hedges, we experienced a 31.3% increase in the cost
of crude oil per barrel as compared to a 18.3% increase in the
average sales price per barrel of our specialty products. It is
possible we may not be able to pass on all or any portion of the
increased crude oil costs to our customers. In addition, we will
not be able to completely eliminate our commodity risk through
our hedging activities.
Because refining margins are volatile, unitholders should not
assume that our current margins will be sustained. If our
refining margins fall, it will adversely affect the amount of
cash we will have available for distribution to our unitholders.
Because
of the volatility of crude oil and refined products prices, our
method of valuing our inventory may result in decreases in net
income.
The nature of our business requires us to maintain substantial
quantities of crude oil and refined product inventories. Because
crude oil and refined products are essentially commodities, we
have no control over the changing market value of these
inventories. Because our inventory is valued at the lower of
cost or market value, if the market value of our inventory were
to decline to an amount less than our cost, we would record a
write-down of inventory and a non-cash charge to cost of sales.
In a period of decreasing crude oil or refined product prices,
our inventory valuation methodology may result in decreases in
net income.
The
price volatility of fuel and utility services may result in
decreases in our earnings, profitability and cash
flows.
The volatility in costs of fuel, principally natural gas, and
other utility services, principally electricity, used by our
refinery and other operations affect our net income and cash
flows. Fuel and utility prices are affected by factors outside
of our control, such as supply and demand for fuel and utility
services in both local and regional markets. Natural gas prices
have historically been volatile. For example, daily prices for
natural gas as reported on the New York Mercantile Exchange
(NYMEX) ranged between $2.51 and $6.07 per million
British thermal unit, or MMBtu, in 2009 and between $5.29 and
$13.58 per MMBtu in 2008. Typically, electricity prices
fluctuate with natural gas prices. Future increases in fuel and
utility prices may have a material adverse effect on our results
of operations. Fuel and utility costs constituted approximately
20.7% and 36.5% of our total operating expenses included in cost
of sales for the years ended December 31, 2009 and 2008,
respectively. If our natural gas costs rise, it will adversely
affect the amount of cash we will have available for
distribution to our unitholders.
Our
hedging activities may not be effective in reducing the
volatility of our cash flows and may reduce our earnings,
profitability and cash flows.
We are exposed to fluctuations in the price of crude oil, fuel
products, natural gas and interest rates. We utilize derivative
financial instruments related to the future price of crude oil,
natural gas and fuel products with the intent of reducing
volatility in our cash flows due to fluctuations in commodity
prices and derivative instruments related to interest rates for
future periods with the intent of reducing volatility in our
cash flows due to fluctuations in interest rates. We are not
able to enter into derivative financial instruments to reduce
the volatility of the prices of the specialty hydrocarbon
products we sell as there is no established derivative market
for such products.
The extent of our commodity price exposure is related largely to
the effectiveness and scope of our hedging activities. For
example, the derivative instruments we utilize are based on
posted market prices, which may differ significantly from the
actual crude oil prices, natural gas prices or fuel products
prices that we incur or realize in our operations. Accordingly,
our commodity price risk management policy may not protect us
from significant and sustained increases in crude oil or natural
gas prices or decreases in fuel products prices. Conversely, our
policy may limit our ability to realize cash flows from crude
oil and natural gas price decreases.
We have a policy to enter into derivative transactions related
to only a portion of the volume of our expected purchase and
sales requirements and, as a result, we will continue to have
direct commodity price exposure to the unhedged portion of our
expected purchase and sales requirements. For example, during
2009 we entered into monthly crude oil collars to hedge up to
8,000 bpd of crude oil purchases related to our specialty
products segment, which had average total daily production for
2009 of approximately 29,000 bpd. As of December 31,
2009, we had significantly
24
reduced the volume and duration of our crude oil collars
position and were hedging approximately 6,000 bpd of crude
oil purchases through January 31, 2010. Thus, we could be
exposed to significant crude oil cost increases on a portion of
our purchases. Please read Item 7A Quantitative and
Qualitative Disclosures About Market Risk.
Our actual future purchase and sales requirements may be
significantly higher or lower than we estimate at the time we
enter into derivative transactions for such period. If the
actual amount is higher than we estimate, we will have greater
commodity price exposure than we intended. If the actual amount
is lower than the amount that is subject to our derivative
financial instruments, we might be forced to satisfy all or a
portion of our derivative transactions without the benefit of
the cash flow from our sale or purchase of the underlying
physical commodity, which may result in a substantial diminution
of our liquidity. As a result, our hedging activities may not be
as effective as we intend in reducing the volatility of our cash
flows. In addition, our hedging activities are subject to the
risks that a counterparty may not perform its obligation under
the applicable derivative instrument, the terms of the
derivative instruments are imperfect, and our hedging policies
and procedures are not properly followed. It is possible that
the steps we take to monitor our derivative financial
instruments may not detect and prevent violations of our risk
management policies and procedures, particularly if deception or
other intentional misconduct is involved.
Our
acquisition, asset reconfiguration and enhancement initiatives
may not result in revenue or cash flow increases, may be subject
to significant cost overruns and are subject to regulatory,
environmental, political, legal and economic risks, which could
adversely affect our business, operating results, cash flows and
financial condition.
We plan to grow our business in part through acquisition and the
reconfiguration and enhancement of our existing refinery assets.
As a specific example, we completed an expansion project at our
Shreveport refinery to increase throughput capacity and crude
oil processing flexibility in May 2008. This expansion project
and the construction of other additions or modifications to our
existing refineries have and will continue to involve numerous
regulatory, environmental, political, legal, labor and economic
uncertainties beyond our control, which could cause delays in
construction or require the expenditure of significant amounts
of capital, which we may finance with additional indebtedness or
by issuing additional equity securities. For example, the total
cost of the Shreveport refinery expansion project was
approximately $375.0 million and was significantly over
budget due to increased construction labor costs. Future
acquisition, reconfiguration and enhancement projects may not be
completed at the budgeted cost, on schedule, or at all due to
the risks described above which would significantly affect our
cash flows and financial condition.
Our
debt levels may limit our flexibility in obtaining additional
financing and in pursuing other business
opportunities.
We had approximately $411.1 million of outstanding
indebtedness under our credit facilities as of December 31,
2009 and availability for borrowings of $107.3 million
under our senior secured revolving credit facility. We continue
to have the ability to incur additional debt, including the
ability to borrow up to $375.0 million under our senior
secured revolving credit facility, subject to the borrowing base
limitations in that credit agreement. For further discussion of
our term loan and revolving credit facilities, please read
Item 7 Managements Discussion and Analysis of
Financial Condition and Results of Operations
Liquidity and Capital Resources Debt and Credit
Facilities. Our level of indebtedness could have important
consequences to us, including the following:
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our ability to obtain additional financing, if necessary, for
working capital, capital expenditures, acquisitions or other
purposes may be impaired or such financing may not be available
on favorable terms;
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covenants contained in our existing and future credit and debt
arrangements will require us to meet financial tests that may
affect our flexibility in planning for and reacting to changes
in our business, including possible acquisition opportunities;
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we will need a substantial portion of our cash flow to make
principal and interest payments on our indebtedness, reducing
the funds that would otherwise be available for operations,
future business opportunities and distributions to
unitholders; and
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our debt level will make us more vulnerable than our competitors
with less debt to competitive pressures or a downturn in our
business or the economy generally.
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Our ability to service our indebtedness will depend upon, among
other things, our future financial and operating performance,
which will be affected by prevailing economic conditions and
financial, business, regulatory and other factors, some of which
are beyond our control. If our operating results are not
sufficient to service our current or future indebtedness, we
will be forced to take actions such as reducing distributions,
reducing or delaying our business activities, acquisitions,
investments
and/or
capital expenditures, selling assets, restructuring or
refinancing our indebtedness, or seeking additional equity
capital or bankruptcy protection. We may not be able to effect
any of these remedies on satisfactory terms, or at all.
We may
be unable to consummate potential acquisitions we identify or
successfully integrate such acquisitions.
We regularly consider and enter into discussions regarding
potential acquisitions that we believe are complementary to our
business. Any such purchase is subject to substantial due
diligence, the negotiation of a definitive purchase and sale
agreement and ancillary agreements, including, but not limited
to supply, transition services and licensing agreements, and the
receipt of various board of directors, governmental and other
approvals. In the alternative, if we are successful in closing
any such acquisitions, we will be subject to many risks
including integration risks and the risk that a substantial
portion of an acquired business may not produce qualifying
income for purposes of the Internal Revenue Code. If our
non-qualifying income exceeds 10% we would lose our election to
be treated as a partnership for tax purposes and will be taxed
as a corporation.
If our
general financial condition deteriorates, we may be limited in
our ability to issue letters of credit which may affect our
ability to enter into hedging arrangements, to enter into
leasing arrangements, or to purchase crude oil.
We rely on our ability to issue letters of credit to enter into
hedging arrangements in an effort to reduce our exposure to
adverse fluctuations in the prices of crude oil, natural gas and
crack spreads. We also rely on our ability to issue letters of
credit to purchase crude oil for our refineries, lease certain
precious metals for use in our refinery operations and enter
into cash flow hedges of crude oil and natural gas purchases and
fuel products sales. If, due to our financial condition or other
reasons, we are limited in our ability to issue letters of
credit or we are unable to issue letters of credit at all, we
may be required to post substantial amounts of cash collateral
to our hedging counterparties, lessors or crude oil suppliers in
order to continue these activities, which would adversely affect
our liquidity and our ability to distribute cash to our
unitholders.
We
depend on certain key crude oil and other feedstock suppliers
for a significant portion of our supply of crude oil and other
feedstocks, and the loss of any of these key suppliers or a
material decrease in the supply of crude oil and other
feedstocks generally available to our refineries could
materially reduce our ability to make distributions to
unitholders.
We purchase crude oil and other feedstocks from major oil
companies as well as from various crude oil gatherers and
marketers in east Texas and north Louisiana. In 2009,
subsidiaries of Plains and Genesis Crude Oil, L.P. supplied us
with approximately 56.4% and 4.4%, respectively, of our total
crude oil supplies under term contracts and evergreen crude oil
supply contracts. In addition, we purchased 31.5% of our total
crude oil purchases in 2009 from Legacy Resources, an affiliate
of our general partner, to supply crude oil to our Princeton and
Shreveport refineries. Each of our refineries is dependent on
one or all of these suppliers and the loss of any of these
suppliers would adversely affect our financial results to the
extent we were unable to find another supplier of this
substantial amount of crude oil. We do not maintain long-term
contracts with most of our suppliers. Please read Items 1
and 2 Business and Properties Crude Oil and
Feedstock Supply.
To the extent that our suppliers reduce the volumes of crude oil
and other feedstocks that they supply us as a result of
declining production or competition or otherwise, our revenues,
net income and cash available for distribution to unitholders
would decline unless we were able to acquire comparable supplies
of crude oil and other feedstocks on comparable terms from other
suppliers, which may not be possible in areas where the supplier
that reduces its volumes is the primary supplier in the area. A
material decrease in crude oil production from the fields that
supply our refineries, as a result of depressed commodity
prices, lack of drilling activity, natural production declines
or otherwise, could result in a decline in the volume of crude
oil we refine. Fluctuations in crude oil prices
26
can greatly affect production rates and investments by third
parties in the development of new oil reserves. Drilling
activity generally decreases as crude oil prices decrease. We
have no control over the level of drilling activity in the
fields that supply our refineries, the amount of reserves
underlying the wells in these fields, the rate at which
production from a well will decline or the production decisions
of producers, which are affected by, among other things,
prevailing and projected energy prices, demand for hydrocarbons,
geological considerations, governmental regulation and the
availability and cost of capital.
We are
dependent on certain third-party pipelines for transportation of
crude oil and refined products, and if these pipelines become
unavailable to us, our revenues and cash available for
distribution could decline.
Our Shreveport refinery is interconnected to pipelines that
supply most of its crude oil and ship a portion of its refined
fuel products to customers, such as pipelines operated by
subsidiaries of TEPPCO Partners, L.P. and ExxonMobil. Since we
do not own or operate any of these pipelines, their continuing
operation is not within our control. If any of these third-party
pipelines become unavailable to transport crude oil or our
refined fuel products because of accidents, government
regulation, terrorism or other events, our revenues, net income
and cash available for distribution to unitholders could decline.
Distributions
to unitholders could be adversely affected by a decrease in the
demand for our specialty products.
Changes in our customers products or processes may enable
our customers to reduce consumption of the specialty products
that we produce or make our specialty products unnecessary.
Should a customer decide to use a different product due to
price, performance or other considerations, we may not be able
to supply a product that meets the customers new
requirements. In addition, the demand for our customers
end products could decrease, which would reduce their demand for
our specialty products. Our specialty products customers are
primarily in the industrial goods, consumer goods and automotive
goods industries and we are therefore susceptible to overall
economic conditions, changing demand patterns and products in
those industries. Consequently, it is important that we develop
and manufacture new products to replace the sales of products
that mature and decline in use. If we are unable to manage
successfully the maturation of our existing specialty products
and the introduction of new specialty products our revenues, net
income and cash available for distribution to unitholders could
be reduced.
Distributions
to unitholders could be adversely affected by a decrease in
demand for fuel products in the markets we serve.
Any sustained decrease in demand for fuel products in the
markets we serve could result in a significant reduction in our
cash flows, reducing our ability to make distributions to
unitholders. Factors that could lead to a decrease in market
demand include:
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a recession or other adverse economic condition that results in
lower spending by consumers on gasoline, diesel, and travel;
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higher fuel taxes or other governmental or regulatory actions
that increase, directly or indirectly, the cost of fuel products;
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an increase in fuel economy or the increased use of alternative
fuel sources;
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an increase in the market price of crude oil that lead to higher
refined product prices, which may reduce demand for fuel
products;
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competitor actions; and
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availability of raw materials.
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27
We
could be subject to damages based on claims brought against us
by our customers or lose customers as a result of the failure of
our products to meet certain quality
specifications.
Our specialty products provide precise performance attributes
for our customers products. If a product fails to perform
in a manner consistent with the detailed quality specifications
required by the customer, the customer could seek replacement of
the product or damages for costs incurred as a result of the
product failing to perform as guaranteed. A successful claim or
series of claims against us could result in a loss of one or
more customers and reduce our ability to make distributions to
unitholders.
We are
subject to compliance with stringent environmental, health and
safety laws and regulations that may expose us to substantial
costs and liabilities.
Our crude oil and specialty hydrocarbon refining and terminal
operations are subject to stringent and complex federal, state
and local environmental, health and safety laws and regulations
governing the discharge of materials into the environment or
otherwise relating to environmental protection, worker health
and safety. These laws and regulations impose numerous
obligations that are applicable to our operations, including the
acquisition of permits to conduct regulated activities, the
incurrence of significant capital expenditures to limit or
prevent releases of materials from our refineries, terminal, and
related facilities, and the incurrence of substantial costs and
liabilities for pollution resulting from our operations or from
those of prior owners. Numerous governmental authorities, such
as the EPA, OSHA, and state agencies, such as the LDEQ, have the
power to enforce compliance with these laws and regulations and
the permits issued under them, often requiring difficult and
costly actions. Failure to comply with laws, regulations,
permits and orders may result in the assessment of
administrative, civil, and criminal penalties, the imposition of
remedial obligations, and the issuance of injunctions limiting
or preventing some or all of our operations.
We are in discussions with the LDEQ regarding our participation
in the Small Refinery and Single Site Refinery Initiative and
anticipate that we will be entering into a settlement agreement
with the LDEQ early in 2010 pursuant to which we will be
required to make emissions reductions requiring capital
investments between approximately $1.0 million and
$3.0 million over a three to five year period at our three
Louisiana refineries. Because the settlement agreement is also
expected to resolve alleged air emissions issues at our Cotton
Valley and Princeton refineries and consolidate any penalties
associated with such issues, we further anticipate that a
penalty of approximately $0.4 million will be assessed in
connection with this settlement agreement.
The workplaces associated with the facilities we operate are
subject to the requirements of federal OSHA and comparable state
statutes that regulate the protection of the health and safety
of workers. In addition, the OSHA hazard communication standard
requires that we maintain information about hazardous materials
used or produced in our operations and that we provide this
information to employees, state and local government
authorities, and local residents. Failure to comply with OSHA
requirements, including general industry standards, record
keeping requirements and monitoring of occupational exposure to
regulated substances could reduce our ability to make
distributions to our unitholders if we are subjected to fines or
significant compliance costs.
We have commissioned studies to assess the adequacy of our
process safety management practices at our Shreveport refinery
with respect to certain consensus codes and standards, some of
which have been recently received. We expect to have fully
reviewed the findings made in these studies during the first
quarter of 2010 and may incur capital expenditures over the next
several years to enhance our programs and equipment so that we
may maintain our compliance with applicable requirements at the
Shreveport refinery. We believe that our operations are in
substantial compliance with OSHA and similar state laws.
Our
business subjects us to the inherent risk of incurring
significant environmental liabilities in the operation of our
refineries and related facilities.
There is inherent risk of incurring significant environmental
costs and liabilities in the operation of our refineries,
terminal, and related facilities due to our handling of
petroleum hydrocarbons and wastes, air emissions and water
discharges related to our operations, and historical operations
and waste disposal practices by prior owners. We currently own
or operate properties that for many years have been used for
industrial activities, including refining or terminal storage
operations. Petroleum hydrocarbons or wastes have been released
on or under
28
the properties owned or operated by us. Joint and several strict
liability may be incurred in connection with such releases of
petroleum hydrocarbons and wastes on, under or from our
properties and facilities. Private parties, including the owners
of properties adjacent to our operations and facilities where
our petroleum hydrocarbons or wastes are taken for reclamation
or disposal, may also have the right to pursue legal actions to
enforce compliance as well as to seek damages for non-compliance
with environmental laws and regulations or for personal injury
or property damage. We may not be able to recover some or any of
these costs from insurance or other sources of indemnity.
Increasingly stringent environmental laws and regulations,
unanticipated remediation obligations or emissions control
expenditures and claims for penalties or damages could result in
substantial costs and liabilities, and our ability to make
distributions to our unitholders could suffer as a result.
Neither the owners of our general partner nor their affiliates
have indemnified us for any environmental liabilities, including
those arising from non-compliance or pollution, that may be
discovered at, or arise from operations on, the assets they
contributed to us in connection with the closing of our initial
public offering. As such, we can expect no economic assistance
from any of them in the event that we are required to make
expenditures to investigate or remediate any petroleum
hydrocarbons, wastes or other materials.
Climate
change laws or regulations restricting emissions of
greenhouse gases could result in increased operating
costs and a decreased demand for our refining
services.
On June 26, 2009, the U.S. House of Representatives
passed the American Clean Energy and Security Act of 2009
(ACESA), which would establish an economy-wide
cap-and-trade
program to reduce U.S. emissions of carbon dioxide and
other greenhouse gases (GHG) that may contribute to
warming of the earths atmosphere and other climatic
changes. ACESA would require a 17 percent reduction in GHG
emissions from 2005 levels by 2020 and just over an
80 percent reduction of such emissions by 2050. Under this
legislation, the EPA would issue a capped and steadily declining
number of tradable emissions allowances to certain major sources
of GHG emissions so that such sources could continue to emit
GHGs into the atmosphere. These allowances would be expected to
escalate significantly in cost over time. The net effect of
ACESA would be to impose increasing costs on the combustion of
carbon-based fuels such as refined petroleum products, oil and
natural gas. The U.S. Senate has begun work on its own
legislation for restricting domestic GHG emissions and President
Obama has indicated his support of legislation to reduce GHG
emissions through an emission allowance system. Also, on
December 15, 2009, the EPA published its findings that
emissions of GHGs present an endangerment to public health and
the environment. These findings allow the EPA to adopt and
implement regulations that would restrict emissions of GHGs
under existing provisions of the federal Clean Air Act.
Accordingly, the EPA has already proposed two sets of
regulations that would require a reduction in emissions of GHGs
from motor vehicles and, also, could trigger permit review for
GHG emissions from certain stationary sources. In addition, on
September 22, 2009, the EPA issued a final rule requiring
the reporting of GHG emissions from specified large GHG emission
sources in the United States, including petroleum refineries, on
an annual basis, beginning in 2011 for emissions occurring after
January 1, 2010. The adoption and implementation of any
regulations imposing GHG reporting obligations on, or limiting
emissions of GHGs from, our equipment and operations could
require us to incur costs to reduce emissions of GHGs associated
with our operations or could adversely affect demand for our
refining services.
We are
exposed to trade credit risk in the ordinary course of our
business activities.
We are exposed to risks of loss in the event of nonperformance
by our customers and by counterparties of our forward contracts,
options and swap agreements. Some of our customers and
counterparties may be highly leveraged and subject to their own
operating and regulatory risks. Even if our credit review and
analysis mechanisms work properly, we may experience financial
losses in our dealings with other parties. Any increase in the
nonpayment or nonperformance by our customers
and/or
counterparties could reduce our ability to make distributions to
our unitholders.
If we
do not make acquisitions on economically acceptable terms, our
future growth will be limited.
Our ability to grow depends on our ability to make acquisitions
that result in an increase in the cash generated from operations
per unit. If we are unable to make these accretive acquisitions
either because we are: (1) unable to
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identify attractive acquisition candidates or negotiate
acceptable purchase contracts with them, (2) unable to
obtain financing for these acquisitions on economically
acceptable terms, or (3) outbid by competitors, then our
future growth and ability to increase distributions to our
unitholders will be limited. Furthermore, any acquisition
involves potential risks, including, among other things:
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performance from the acquired assets and businesses that is
below the forecasts we used in evaluating the acquisition;
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a significant increase in our indebtedness and working capital
requirements;
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an inability to timely and effectively integrate the operations
of recently acquired businesses or assets, particularly those in
new geographic areas or in new lines of business;
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the incurrence of substantial unforeseen environmental and other
liabilities arising out of the acquired businesses or assets;
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the diversion of managements attention from other business
concerns; and
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customer or key employee losses at the acquired businesses.
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If we consummate any future acquisitions, our capitalization and
results of operations may change significantly, and our
unitholders will not have the opportunity to evaluate the
economic, financial and other relevant information that we will
consider in determining the application of our funds and other
resources.
Our
refineries, facilities and terminal operations face operating
hazards, and the potential limits on insurance coverage could
expose us to potentially significant liability
costs.
Our operations are subject to significant interruption, and our
cash from operations could decline if any of our facilities
experiences a major accident or fire, is damaged by severe
weather or other natural disaster, or otherwise is forced to
curtail its operations or shut down. These hazards could result
in substantial losses due to personal injury
and/or loss
of life, severe damage to and destruction of property and
equipment and pollution or other environmental damage and may
result in curtailment or suspension of our related operations.
We are not fully insured against all risks incident to our
business. Furthermore, we may be unable to maintain or obtain
insurance of the type and amount we desire at reasonable rates.
As a result of market conditions, premiums and deductibles for
certain of our insurance policies have increased and could
escalate further. In some instances, certain insurance could
become unavailable or available only for reduced amounts of
coverage. Our business interruption insurance will not apply
unless a business interruption exceeds 90 days. We are not
insured for environmental accidents. If we were to incur a
significant liability for which we were not fully insured, it
could diminish our ability to make distributions to unitholders.
Downtime
for maintenance at our refineries and facilities will reduce our
revenues and cash available for distribution.
Our refineries and facilities consist of many processing units,
a number of which have been in operation for a long time. One or
more of the units may require additional unscheduled downtime
for unanticipated maintenance or repairs that are more frequent
than our scheduled turnaround for each unit every one to five
years. Scheduled and unscheduled maintenance reduce our revenues
during the period of time that our processing units are not
operating and could reduce our ability to make distributions to
our unitholders.
We are
subject to strict regulations at many of our facilities
regarding employee safety, and failure to comply with these
regulations could reduce our ability to make distributions to
our unitholders.
The workplaces associated with the facilities we operate are
subject to the requirements of the federal OSHA and comparable
state statutes that regulate the protection of the health and
safety of workers. In addition, the OSHA hazard communication
standard requires that we maintain information about hazardous
materials used or produced in our operations and that we provide
this information to employees, state and local government
authorities, and local residents. Failure to comply with OSHA
requirements, including general industry standards, record
keeping
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requirements and monitoring of occupational exposure to
regulated substances could reduce our ability to make
distributions to our unitholders if we are subjected to fines or
significant compliance costs.
We
face substantial competition from other refining
companies.
The refining industry is highly competitive. Our competitors
include large, integrated, major or independent oil companies
that, because of their more diverse operations, larger
refineries and stronger capitalization, may be better positioned
than we are to withstand volatile industry conditions, including
shortages or excesses of crude oil or refined products or
intense price competition at the wholesale level. If we are
unable to compete effectively, we may lose existing customers or
fail to acquire new customers. For example, if a competitor
attempts to increase market share by reducing prices, our
operating results and cash available for distribution to our
unitholders could be reduced.
An
increase in interest rates will cause our debt service
obligations to increase.
Borrowings under our revolving credit facility bear interest at
a floating rate (3.75% as of December 31, 2009). Borrowings
under our term loan facility bear interest at a floating rate
(6.15% as of December 31, 2009). The interest rates are
subject to adjustment based on fluctuations in the London
Interbank Offered Rate (LIBOR) or prime rate. The
interest rate under our term loan credit facility, entered into
on January 3, 2008, is LIBOR plus 4.0%. An increase in the
interest rates associated with our floating-rate debt would
increase our debt service costs and affect our results of
operations and cash flow available for distribution to our
unitholders. In addition, an increase in interest rates could
adversely affect our future ability to obtain financing or
materially increase the cost of any additional financing.
Due to
our lack of asset and geographic diversification, adverse
developments in our operating areas would reduce our ability to
make distributions to our unitholders.
We rely exclusively on sales generated from products processed
at the facilities we own. Furthermore, the majority of our
assets and operations are located in northwest Louisiana. Due to
our lack of diversification in asset type and location, an
adverse development in these businesses or areas, including
adverse developments due to catastrophic events or weather,
decreased supply of crude oil and feedstocks
and/or
decreased demand for refined petroleum products, would have a
significantly greater impact on our financial condition and
results of operations than if we maintained more diverse assets
in more diverse locations.
We
depend on key personnel for the success of our business and the
loss of those persons could adversely affect our business and
our ability to make distributions to our
unitholders.
The loss of the services of any member of senior management or
key employee could have an adverse effect on our business and
reduce our ability to make distributions to our unitholders. We
may not be able to locate or employ on acceptable terms
qualified replacements for senior management or other key
employees if their services were no longer available. Except
with respect to Mr. Grube and Mr. Moyes, neither we,
our general partner nor any affiliate thereof has entered into
an employment agreement with any member of our senior management
team or other key personnel. Furthermore, we do not maintain any
key-man life insurance.
We
depend on unionized labor for the operation of our refineries.
Any work stoppages or labor disturbances at these facilities
could disrupt our business.
Substantially all of our operating personnel at our Princeton,
Cotton Valley and Shreveport refineries are employed under
collective bargaining agreements that expire in October 2011,
March 2010 and April 2010, respectively. Substantially all of
the operating personnel acquired through the Penreco acquisition
are employed under collective bargaining agreements that expire
in January 2012 and March 2013. Our inability to renegotiate
these agreements as they expire, any work stoppages or other
labor disturbances at these facilities could have an adverse
effect on our business and reduce our ability to make
distributions to our unitholders. In addition, employees who are
not currently represented by labor unions may seek union
representation in the future, and any renegotiation of current
collective bargaining agreements may result in terms that are
less favorable to us.
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The
operating results for our fuel products segment and the asphalt
we produce and sell are seasonal and generally lower in the
first and fourth quarters of the year.
The operating results for the fuel products segment and the
selling prices of asphalt products we produce can be seasonal.
Asphalt demand is generally lower in the first and fourth
quarters of the year as compared to the second and third
quarters due to the seasonality of road construction. Demand for
gasoline is generally higher during the summer months than
during the winter months due to seasonal increases in highway
traffic. In addition, our natural gas costs can be higher during
the winter months. Our operating results for the first and
fourth calendar quarters may be lower than those for the second
and third calendar quarters of each year as a result of this
seasonality.
The
adoption of derivatives legislation by Congress could have an
adverse impact on our ability to hedge risks associated with our
business.
Congress currently is considering broad financial regulatory
reform legislation that among other things would impose
comprehensive regulation on the
over-the-counter
(OTC) derivatives marketplace and could affect the use of
derivatives in hedging transactions. The financial regulatory
reform bill adopted by the House of Representatives on
December 11, 2009, would subject swap dealers and
major swap participants to substantial supervision
and regulation, including capital standards, margin
requirements, business conduct standards and recordkeeping and
reporting requirements. It also would require central clearing
for transactions entered into between swap dealers or major swap
participants. For these purposes, a major swap participant
generally would be someone other than a dealer who maintains a
substantial net position in outstanding swaps,
excluding swaps used for commercial hedging or for reducing or
mitigating commercial risk, or whose positions create
substantial net counterparty exposure that could have serious
adverse effects on the financial stability of the
U.S. banking system or financial markets. The House-passed
bill also would provide the Commodity Futures Trading Commission
(CFTC) with express authority to impose position limits for OTC
derivatives related to energy commodities. Separately, in late
January, 2010, the CFTC proposed regulations that would impose
speculative position limits for certain futures and option
contracts in natural gas, crude oil, heating oil, and gasoline.
These proposed regulations would make an exemption available for
certain bona fide hedging of commercial risks. Although
it is not possible at this time to predict whether or when
Congress will act on derivatives legislation or the CFTC will
finalize its proposed regulations, any laws or regulations that
subject us to additional capital or margin requirements relating
to, or to additional restrictions on, our trading and commodity
positions could have an adverse effect on our ability to hedge
risks associated with our business or on the cost of our hedging
activity.
If
Houston Refining is unable to perform its obligations under the
LyondellBasell Agreements, our results of operations and cash
flows could be adversely affected.
Under the LyondellBasell Agreements, we are the exclusive
purchaser of Houston Refinings naphthenic lubricating oil
production at its Houston, Texas refinery and are required to
purchase a minimum of approximately 3,000 bpd. In addition,
Houston Refining is required to process a minimum of
approximately 800 bpd of white mineral oil for us at its
Houston, Texas refinery. Houston Refinings parent,
LyondellBasell, is currently in bankruptcy reorganization
proceedings under Chapter 11 of the U.S. Bankruptcy
Code and there is no guarantee that LyondellBasell will
successfully emerge from bankruptcy. If LyondellBasell is unable
to complete the bankruptcy proceedings in a timely manner or if
it abandons the proceedings, it may be required to liquidate its
operations, which could materially adversely impact Houston
Refinings ability to perform its obligations under the
LyondellBasell Agreements and, in turn, could adversely impact
our results of operations and cash flows.
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Risks
Inherent in an Investment in Us
The
families of our chairman and chief executive officer and
president, The Heritage Group and certain of their affiliates
own a 54.3% limited partner interest in us and own and control
our general partner, which has sole responsibility for
conducting our business and managing our operations. Our general
partner and its affiliates have conflicts of interest and
limited fiduciary duties, which may permit them to favor their
own interests to other unitholders
detriment.
The families of our chairman and chief executive officer and
president, the Heritage Group, and certain of their affiliates
own a 54.3% limited partner interest in us. In addition, The
Heritage Group and the families of our chairman and chief
executive officer and president own our general partner.
Conflicts of interest may arise between our general partner and
its affiliates, on the one hand, and us and our unitholders, on
the other hand. As a result of these conflicts, the general
partner may favor its own interests and the interests of its
affiliates over the interests of our unitholders. These
conflicts include, among others, the following situations:
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our general partner is allowed to take into account the
interests of parties other than us, such as its affiliates, in
resolving conflicts of interest, which has the effect of
limiting its fiduciary duty to our unitholders;
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our general partner has limited its liability and reduced its
fiduciary duties under our partnership agreement and has also
restricted the remedies available to our unitholders for actions
that, without the limitations, might constitute breaches of
fiduciary duty. As a result of purchasing common units,
unitholders consent to some actions and conflicts of interest
that might otherwise constitute a breach of fiduciary or other
duties under applicable state law;
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our general partner determines the amount and timing of asset
purchases and sales, borrowings, issuance of additional
partnership securities, and reserves, each of which can affect
the amount of cash that is distributed to unitholders;
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our general partner determines which costs incurred by it and
its affiliates are reimbursable by us;
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our general partner determines the amount and timing of any
capital expenditures and whether a capital expenditure is a
maintenance capital expenditure, which reduces operating
surplus, or a capital expenditure for acquisitions or capital
improvements, which does not. This determination can affect the
amount of cash that is distributed to our unitholders and the
ability of the subordinated units to convert to common units;
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our general partner has the flexibility to cause us to enter
into a broad variety of derivative transactions covering
different time periods, the net cash receipts from which will
increase operating surplus and adjusted operating surplus, with
the result that our general partner may be able to shift the
recognition of operating surplus and adjusted operating surplus
between periods to increase the distributions it and its
affiliates receive on their subordinated units and incentive
distribution rights or to accelerate the expiration of the
subordination period; and
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in some instances, our general partner may cause us to borrow
funds in order to permit the payment of cash distributions, even
if the purpose or effect of the borrowing is to make a
distribution on the subordinated units, to make incentive
distributions or to accelerate the expiration of the
subordination period.
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The
Heritage Group and certain of its affiliates may engage in
limited competition with us.
Pursuant to the omnibus agreement we entered into in connection
with our initial public offering, The Heritage Group and its
controlled affiliates have agreed not to engage in, whether by
acquisition or otherwise, the business of refining or marketing
specialty lubricating oils, solvents and wax products as well as
gasoline, diesel and jet fuel products in the continental United
States (restricted business) for so long as it
controls us. This restriction does not apply to certain assets
and businesses which are more fully described under Item 13
Certain Relationships and Related Transactions and
Director Independence Omnibus Agreement.
Although Mr. Grube is prohibited from competing with us
pursuant to the terms of his employment agreement, the owners of
our general partner, other than The Heritage Group, are not
prohibited from competing with us.
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Our
partnership agreement limits our general partners
fiduciary duties to our unitholders and restricts the remedies
available to unitholders for actions taken by our general
partner that might otherwise constitute breaches of fiduciary
duty.
Our partnership agreement contains provisions that reduce the
standards to which our general partner would otherwise be held
by state fiduciary duty law. For example, our partnership
agreement:
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Permits our general partner to make a number of decisions in its
individual capacity, as opposed to in its capacity as our
general partner. This entitles our general partner to consider
only the interests and factors that it desires, and it has no
duty or obligation to give any consideration to any interest of,
or factors affecting, us, our affiliates or any limited partner.
Examples include the exercise of its limited call right, its
voting rights with respect to the units it owns, its
registration rights and its determination whether or not to
consent to any merger or consolidation of our partnership or
amendment of our partnership agreement;
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Provides that our general partner will not have any liability to
us or our unitholders for decisions made in its capacity as a
general partner so long as it acted in good faith, meaning it
believed the decision was in the best interests of our
partnership;
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Generally provides that affiliated transactions and resolutions
of conflicts of interest not approved by the conflicts committee
of the board of directors of our general partner and not
involving a vote of unitholders must be on terms no less
favorable to us than those generally being provided to or
available from unrelated third parties or be fair and
reasonable to us. In determining whether a transaction or
resolution is fair and reasonable, our general
partner may consider the totality of the relationships between
the parties involved, including other transactions that may be
particularly advantageous or beneficial to us; and
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Provides that our general partner and its officers and directors
will not be liable for monetary damages to us or our limited
partners for any acts or omissions unless there has been a final
and non-appealable judgment entered by a court of competent
jurisdiction determining that the general partner or those other
persons acted in bad faith or engaged in fraud or willful
misconduct or, in the case of a criminal matter, acted with
knowledge that such persons conduct was criminal.
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In order to become a limited partner of our partnership, a
common unitholder is required to agree to be bound by the
provisions in the partnership agreement, including the
provisions discussed above.
Unitholders
have limited voting rights and are not entitled to elect our
general partner or its directors.
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
managements decisions regarding our business. Unitholders
do not elect our general partner or its board of directors, and
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 members of our
general partner. Furthermore, if the unitholders are
dissatisfied with the performance of our general partner, they
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.
Even
if unitholders are dissatisfied, they cannot remove our general
partner without its consent.
The unitholders are unable to remove the general partner without
its consent because the general partner and its affiliates own
sufficient units to be able to prevent its removal. The vote of
the holders of at least
662/3%
of all outstanding units voting together as a single class is
required to remove the general partner. At February 23,
2010, the owners of our general partner and certain of their
affiliates own 54.3% of our common and subordinated units. Also,
if our general partner is removed without cause during the
subordination period and units held by our general partner and
its affiliates are not voted in favor of that removal, all
remaining subordinated units will automatically convert into
common units and any existing arrearages on the common units
will be extinguished. A removal of the general partner under
these circumstances would adversely affect the common units by
prematurely eliminating their distribution and liquidation
preference over the subordinated units, which would otherwise
have continued until we had met certain distribution and
performance tests.
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Cause is narrowly defined in our partnership agreement to mean
that a court of competent jurisdiction has entered a final,
non-appealable judgment finding our general partner liable for
actual fraud or willful misconduct in its capacity as our
general partner. Cause does not include most cases of charges of
poor management of the business, so the removal of our general
partner during the subordination period because of the
unitholders dissatisfaction with our general
partners performance in managing our partnership will most
likely result in the termination of the subordination period.
Our
partnership agreement restricts the voting rights of those
unitholders owning 20% or more of our common
units.
Unitholders voting rights are further restricted by the
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 any matter. Our partnership agreement also
contains provisions limiting the ability of unitholders to call
meetings or to acquire information about our operations, as well
as other provisions limiting the unitholders ability to
influence the manner or direction of management.
Control
of our general partner may be transferred to a third party
without unitholder consent.
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, our partnership agreement does not restrict the
ability of the members of our general partner from transferring
their respective membership interests in our general partner to
a third party. The new members of our general partner would then
be in a position to replace the board of directors and officers
of our general partner with their own choices and thereby
control the decisions taken by the board of directors.
We do
not have our own officers and employees and rely solely on the
officers and employees of our general partner and its affiliates
to manage our business and affairs.
We do not have our own officers and employees and rely solely on
the officers and employees of our general partner and its
affiliates to manage our business and affairs. We can provide no
assurance that our general partner will continue to provide us
the officers and employees that are necessary for the conduct of
our business nor that such provision will be on terms that are
acceptable to us. If our general partner fails to provide us
with adequate personnel, our operations could be adversely
impacted and our cash available for distribution to unitholders
could be reduced.
We may
issue additional common units without unitholder approval, which
would dilute our current unitholders existing ownership
interests.
In general, during the subordination period, we may issue up to
3,485,222 additional common units without obtaining unitholder
approval, which units we refer to as the basket. Our
general partner can also issue an unlimited number of common
units in connection with accretive acquisitions and capital
improvements that increase cash flow from operations per unit on
an estimated pro forma basis. We can also issue additional
common units if the proceeds are used to repay certain of our
indebtedness.
The issuance of additional common units or other equity
securities of equal or senior rank to the common units will have
the following effects:
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our unitholders proportionate ownership interest in us may
decrease;
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the amount of cash available for distribution on each unit may
decrease;
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because a lower percentage of total outstanding units will be
subordinated units, the risk that a shortfall in the payment of
the minimum quarterly distribution will be borne by our common
unitholders will increase;
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the relative voting strength of each previously outstanding unit
may be diminished;
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the market price of the common units may decline; and
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the ratio of taxable income to distributions may increase.
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After the end of the subordination period, we may issue an
unlimited number of limited partner interests of any type
without the approval of our unitholders. Our partnership
agreement does not give our unitholders the right to approve our
issuance of equity securities ranking junior to the common units
at any time. In addition, our partnership agreement does not
prohibit the issuance by our subsidiaries of equity securities,
which may effectively rank senior to the common units.
Our
general partners determination of the level of cash
reserves may reduce the amount of available cash for
distribution to unitholders.
Our partnership agreement requires our general partner to deduct
from operating surplus cash reserves that it establishes are
necessary to fund our future operating expenditures. In
addition, our partnership agreement also permits our general
partner to reduce available cash by establishing cash reserves
for the proper conduct of our business, to comply with
applicable law or agreements to which we are a party, or to
provide funds for future distributions to partners. These
reserves will affect the amount of cash available for
distribution to unitholders.
Cost
reimbursements due to our general partner and its affiliates
will reduce cash available for distribution to
unitholders.
Prior to making any distribution on the common units, we will
reimburse our general partner and its affiliates for all
expenses they incur on our behalf. Any such reimbursement will
be determined by our general partner and will reduce the cash
available for distribution to unitholders. These expenses will
include all costs incurred by our general partner and its
affiliates in managing and operating us. Please read
Item 13 Certain Relationships and Related
Transactions and Director Independence.
Our
general partner has a limited call right that may require
unitholders to sell their units at an undesirable time or
price.
If at any time our general partner and its affiliates own more
than 80% of the issued and outstanding common units, our general
partner will have the right, but not the obligation, which right
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 to our general partner, its affiliates or us 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 common units. At February 23, 2010,
our general partner and its affiliates own approximately 27.4%
of the common units. At the end of the subordination period,
assuming no additional issuances of common units, our general
partner and its affiliates will own approximately 54.3% of the
common units.
Unitholder
liability may not be limited if a court finds that unitholder
action constitutes control of our business.
A general partner of a partnership generally has unlimited
liability for the obligations of the partnership, except for
those contractual obligations of the partnership that are
expressly made without recourse to the general partner. Our
partnership is organized under Delaware law and we conduct
business in a number of other states. The limitations on the
liability of holders of limited partner interests for the
obligations of a limited partnership have not been clearly
established in some of the other states in which we do business.
Unitholders could be liable for any and all of our obligations
as if they were a general partner if:
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a court or government agency determined that we were conducting
business in a state but had not complied with that particular
states partnership statute; or
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unitholders right to act with other unitholders to remove
or replace the general partner, to approve some amendments to
our partnership agreement or to take other actions under our
partnership agreement constitute control of our
business.
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Unitholders
may have liability to repay distributions that were wrongfully
distributed to them.
Under certain circumstances, unitholders may have to repay
amounts wrongfully returned or distributed to them. Under
Section 17-607
of the Delaware Revised Uniform Limited Partnership Act, which
we call the Delaware Act, we may not make a distribution to our
unitholders if the distribution would cause our liabilities to
exceed the fair value of our assets. Delaware law provides that
for a period of three years from the date of the impermissible
distribution, limited partners who received the distribution and
who knew at the time of the distribution that it violated
Delaware law will be liable to the limited partnership for the
distribution amount. Purchasers of units who become limited
partners are liable for the obligations of the transferring
limited partner to make contributions to the partnership that
are known to the purchaser of the units at the time it became a
limited partner and for unknown obligations if the liabilities
could be determined from the partnership agreement. Liabilities
to partners on account of their partnership interest and
liabilities that are non-recourse to the partnership are not
counted for purposes of determining whether a distribution is
permitted.
Our
common units have a low trading volume compared to other units
representing limited partner interests.
Our common units are traded publicly on the NASDAQ Global Market
under the symbol CLMT. However, our common units
have a low average daily trading volume compared to many other
units representing limited partner interests quoted on the
NASDAQ. The price of our common units may continue to be
volatile.
The market price of our common units may also be influenced by
many factors, some of which are beyond our control, including:
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our quarterly distributions;
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our quarterly or annual earnings or those of other companies in
our industry;
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changes in commodity prices or refining margins;
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loss of a large customer;
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announcements by us or our competitors of significant contracts
or acquisitions;
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changes in accounting standards, policies, guidance,
interpretations or principles;
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general economic conditions;
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the failure of securities analysts to cover our common units or
changes in financial estimates by analysts;
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future sales of our common units; and
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the other factors described in Item 1A Risk
Factors of this
Form 10-K.
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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.
If the Internal Revenue Service, or IRS, treats us as a
corporation or we become subject to additional amounts of
entity-level
taxation for state tax purposes, it would substantially reduce
the amount of cash available for distribution to common
unitholders.
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. We have not
requested a ruling from the IRS with respect to our treatment as
a partnership for federal income tax purposes.
Despite the fact that we are a limited partnership under
Delaware law, it is possible in certain circumstances for a
partnership such as ours to be treated as a corporation for
federal income tax purposes. Although we do not believe based
upon our current operations that we are so treated, 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.
37
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 likely pay state income tax at varying rates.
Distributions to unitholders would generally be taxed again as
corporate distributions, and no income, gains, losses or
deductions would flow through to the unitholders. Because a tax
would be imposed upon us as a corporation, our cash available
for distribution to our unitholders would be substantially
reduced. Therefore, our treatment as a corporation would result
in a material reduction in the anticipated cash flow and
after-tax return to the 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. At a state level, because of
widespread state budget deficits, 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, beginning in 2008, we are required to pay
Texas franchise tax at a maximum effective rate of 0.7% of our
gross income apportioned to Texas in the prior year. Imposition
of such a tax on us by Texas and, if applicable, by any other
state will reduce the cash available for distribution to
unitholders.
Our partnership agreement provides that if a law is enacted or
existing law is modified or interpreted in a manner that
subjects us to taxation as a corporation or otherwise subjects
us to entity-level taxation for federal, state or local income
tax purposes, the minimum quarterly distribution amount and the
target distribution levels will be adjusted to reflect the
impact of that law on us.
The
tax treatment of publicly traded partnerships or an investment
in our common units could be subject to potential legislative,
judicial or administrative changes and differing
interpretations, possibly on a retroactive basis.
The present federal income tax treatment of publicly traded
partnerships, including us, or an investment in our common units
may be modified by administrative, legislative or judicial
interpretation at any time. For example, members of Congress are
considering substantive changes to the existing federal income
tax laws that affect certain publicly traded partnerships. Any
modification to the federal income tax laws and interpretations
thereof may or may not be applied retroactively. Although the
considered legislation would not appear to affect our tax
treatment as a partnership, we are unable to predict whether any
of these changes, or other proposals, will ultimately be
enacted. Any such changes could negatively impact the value of
an investment in our common units.
If the
IRS contests the federal income tax positions we take, the
market for our common units may be adversely impacted and the
cost of any IRS contest will reduce our cash available for
distribution.
We have not requested a ruling from the IRS with respect to our
treatment as a partnership for federal income tax purposes. 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
the costs will reduce our cash available for distribution.
Unitholders
may be required to pay taxes on income from us even if they do
not receive any cash distributions from us.
Because our unitholders will be treated as partners to whom we
will allocate taxable income which could be different in amount
than the cash we distribute, unitholders will be required to pay
any federal income taxes and, in some cases, state and local
income taxes on their share of our taxable income even if they
receive no cash distributions from us. Unitholders may not
receive cash distributions from us equal to their share of our
taxable income or even equal to the actual tax liability that
results from that income.
Tax
gain or loss on disposition of 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 they
realized and their tax basis in those common units. Because
distributions in excess of their allocable
38
share of our net taxable income decrease their tax basis in
their common units, the amount, if any, of such prior excess
distributions with respect to the units sold will, in effect,
become taxable income to unitholders if they sell such units at
a price greater than their tax basis in those units, even if the
price they receive is less than their original cost.
Furthermore, a substantial portion of the amount realized,
whether or not representing gain, may be taxed as ordinary
income due to potential recapture items, including depreciation
recapture. In addition, because the amount realized includes a
unitholders share of our nonrecourse 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-United
States persons face unique tax issues from owning our common
units that may result in adverse tax consequences to
them.
Investment in our common units by tax-exempt entities, such as
individual retirement accounts (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 United States federal 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
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 the common units.
Due to a number of factors including our inability to match
transferors and transferees of common units and because of other
reasons, we take depreciation and amortization positions that
may not conform to all aspects of existing Treasury Regulations.
A successful IRS challenge to those positions could adversely
affect the amount of tax benefits available to our unitholders.
It also could affect the timing of these tax benefits or the
amount of gain from the sale of common units and could have a
negative impact on the value of our common units or result in
audit adjustments to our unitholders tax returns.
We
have a subsidiary that is treated as a corporation for federal
income tax purposes and subject to corporate-level income
taxes.
We conduct all or a portion of our operations in which we market
finished petroleum products to certain end-users through a
subsidiary that is organized as a corporation. We may elect to
conduct additional operations through this corporate subsidiary
in the future. This corporate subsidiary is 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 this corporation has 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 units each month based upon
the ownership of our units on the first day of each month,
instead of on the basis of the date a particular unit is
transferred. The IRS may challenge this treatment, which could
change the allocation of items of income, gain, loss and
deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between
transferors and transferees of our units each month based upon
the ownership of our 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 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.
Recently, however, the Department of the Treasury and the IRS
issued proposed Treasury Regulations that provide a safe harbor
pursuant to which a publicly traded partnership may use a
similar monthly simplifying convention to allocate tax items
among transferor and transferee unitholders. Although publicly
traded partnerships are entitled to rely on these proposed
Treasury Regulations, they are not binding on the IRS and are
subject to change until final Treasury Regulations are issued.
39
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, he 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, he 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 the general
partner and the unitholders. The IRS may challenge this
treatment, which could adversely affect the value of the common
units.
When we issue additional 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
the general partner, which may be unfavorable to such
unitholders. Moreover, under our valuation methodologies,
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 the
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 our unitholders sale of common units and could
have a negative impact on the value of the common units or
result in audit adjustments to our unitholders tax returns
without the benefit of additional deductions.
The
sale or exchange of 50% or more of our capital and profits
interests during any twelve-month period will result in the
termination of our partnership for federal income tax
purposes.
We will be considered to have terminated for federal income tax
purposes if there is a sale or exchange of 50% or more of the
total interests in our capital and profits within a twelve-month
period. For purposes of determining whether the 50% threshold
has been met, multiple sales of the same interest will be
counted only once. Our termination would, among other things,
result in the closing of our taxable year for all unitholders
which could result in us filing two tax returns (and unitholders
receiving two
Schedule K-1s)
for one fiscal year. Our termination could also result in a
deferral of depreciation deductions allowable in computing our
taxable income. In the case of a unitholder reporting on a
taxable year other than a fiscal year ending December 31,
the closing of our taxable year may also 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.
Unitholders
may be subject to state and local taxes and return filing
requirements.
In addition to federal income taxes, our common 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. Our
common 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
40
to penalties for failure to comply with those requirements. We
own assets
and/or do
business in Arkansas, Arizona, California, Connecticut,
Delaware, Florida, Georgia, Indiana, Illinois, Kansas, Kentucky,
Louisiana, Massachusetts, Michigan, Minnesota, Mississippi,
Missouri, New Jersey, New York, North Carolina, Ohio, Oregon,
Pennsylvania, South Carolina, Tennessee, Texas, Utah, Virginia,
Washington and Wisconsin. Each of these states, other than Texas
and Florida, currently imposes a personal income tax as well as
an income tax on corporations and other entities. As we make
acquisitions or expand our business, we may own assets or do
business in additional states that impose a personal income tax.
It is the responsibility of our common unitholders to file all
United States federal, foreign, state and local tax returns.
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Item 1B.
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Unresolved
Staff Comments
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None.
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Item 3.
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Legal
Proceedings
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We are not a party to any material litigation. Our operations
are subject to a variety of risks and disputes normally incident
to our business. As a result, we may, at any given time, be a
defendant in various legal proceedings and litigation arising in
the ordinary course of business. Please see Items 1 and 2
Business and Properties Environmental, Health
and Safety Matters for a description of our current
regulatory matters related to the environment.
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Item 4.
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Submission
of Matters to a Vote of Security Holders
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None.
PART II
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Item 5.
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Market
for Registrants Common Equity, Related Unitholder Matters
and Issuer Purchases of Equity Securities
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Market
Information
Our common units are quoted and traded on the NASDAQ Global
Select Market under the symbol CLMT. Our common
units began trading on January 26, 2006 at an initial
public offering price of $21.50. Prior to that date, there was
no public market for our common units. The following table shows
the low and high sales prices per common unit, as reported by
NASDAQ, for the periods indicated. Cash distributions presented
below represent amounts declared subsequent to each respective
quarter end based on the results of that quarter. During each
quarter in the years ended December 31, 2009 and 2008,
identical cash distributions per unit were paid among all
outstanding common and subordinated units.
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Cash Distribution
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Low
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High
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per Unit
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Year ended December 31, 2008:
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First quarter
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$
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22.60
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$
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37.88
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$
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0.45
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Second quarter
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$
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11.19
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$
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23.50
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$
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0.45
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Third quarter
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$
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11.46
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$
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15.40
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$
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0.45
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Fourth quarter
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|
$
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5.77
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$
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15.35
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$
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0.45
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Year ended December 31, 2009:
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First quarter
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$
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8.11
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$
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13.44
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$
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0.45
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Second quarter
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$
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9.45
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$
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16.84
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$
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0.45
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Third quarter
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$
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13.20
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$
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18.53
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$
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0.45
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Fourth quarter
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$
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14.75
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$
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19.87
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$
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0.455
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As of February 23, 2010, there were approximately
24 unitholders of record of our common units. This number
does not include unitholders whose units are held in trust by
other entities. The actual number of unitholders is
41
greater than the number of holders of record. As of
February 23, 2010, there were 35,279,778 units
outstanding. The number of units outstanding on this date
includes the 13,066,000 subordinated units for which there is no
established trading market. The last reported sale price of our
common units by NASDAQ on February 23, 2010 was $19.31.
On December 14, 2009, we completed a public equity offering
in which we sold 3,000,000 common units to the underwriters at a
price to the public of $18.00 per common unit and received net
proceeds of approximately $51.2 million. In addition, on
January 7, 2010 we sold an additional 47,778 common units
to the underwriters at a price to the public of $18.00 per
common unit pursuant to the underwriters over-allotment
option. In connection with this offering, our general partner
contributed an additional $1.1 million to us to retain its
2% general partner interest.
Cash
Distribution Policy
General. Within 45 days after the end of
each quarter, we distribute our available cash (as defined in
our partnership agreement) to unitholders of record on the
applicable record date.
Available Cash. Available cash generally
means, for any quarter, all cash on hand at the end of the
quarter:
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less the amount of cash reserves established by our general
partner to:
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provide for the proper conduct of our business;
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comply with applicable law, any of our debt instruments or other
agreements; or
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provide funds for distributions to our unitholders and to our
general partner for any one or more of the next four quarters.
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plus all cash on hand on the date of determination of available
cash for the quarter resulting from working capital borrowings
made after the end of the quarter for which the determination is
being made. Working capital borrowings are generally borrowings
that will be made under our revolving credit facility and in all
cases are used solely for working capital purposes or to pay
distributions to partners.
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Intent to Distribute the Minimum Quarterly
Distribution. We distribute to the holders of
common units and subordinated units on a quarterly basis at
least the minimum quarterly distribution of $0.45 per unit, or
$1.80 per year, to the extent we have sufficient cash from our
operations after establishment of cash reserves and payment of
fees and expenses, including payments to our general partner.
However, there is no guarantee that we will pay the minimum
quarterly distribution on the units in any quarter. Even if our
cash distribution policy is not modified or revoked, the amount
of distributions paid under our policy and the decision to make
any distribution is determined by our general partner, taking
into consideration the terms of our partnership agreement. We
will be prohibited from making any distributions to unitholders
if it would cause an event of default, or an event of default is
existing, under our credit agreements. Please read Item 7
Managements Discussion and Analysis of Financial
Condition and Results of Operations Liquidity and
Capital Resources Debt and Credit Facilities
for a discussion of the restrictions in our credit agreements
that restrict our ability to make distributions. On
February 12, 2010, we paid a quarterly cash distribution of
$0.455 per unit on all outstanding units totaling
$16.4 million for the quarter ended December 31, 2009
to all unitholders of record as of the close of business on
February 2, 2010.
General Partner Interest and Incentive Distribution
Rights. Our general partner is entitled to 2% of
all quarterly distributions since inception that we make prior
to our liquidation. This general partner interest is represented
by 719,995 general partner units. Our general partner has the
right, but not the obligation, to contribute a proportionate
amount of capital to us to maintain its current general partner
interest. The general partners 2% interest in these
distributions may be reduced if we issue additional units in the
future and our general partner does not contribute a
proportionate amount of capital to us to maintain its 2% general
partner interest. Our general partner also currently holds
incentive distribution rights that entitle it to receive
increasing percentages, up to a maximum of 50%, of the cash we
distribute from operating surplus (as defined below) in excess
of $0.495 per unit. The maximum distribution of 50% includes
distributions paid to our general partner on its 2% general
partner interest, and assumes that our general partner maintains
its general partner interest at 2%. The maximum distribution of
50% does not include any distributions that our general partner
may receive on units that it owns. We paid $1.0 million to
our
42
general partner in incentive distributions pursuant to its
incentive distribution rights during the year ended
December 31, 2008. Our general partner did not earn
incentive distribution rights during the year ended
December 31, 2009.
The Companys general partner is entitled to incentive
distributions if the amount it distributes to unitholders with
respect to any quarter exceeds specified target levels shown
below:
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Marginal Percentage
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Total Quarterly
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Interest in
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Distribution
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Distributions
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Target Amount
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Unitholders
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General Partner
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Minimum Quarterly Distribution
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$0.45
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98
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%
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2
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%
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First Target Distribution
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up to $0.495
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98
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%
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2
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%
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Second Target Distribution
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above $0.495 up to $0.563
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85
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%
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15
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%
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Third Target Distribution
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above $0.563 up to $0.675
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75
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%
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25
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%
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Thereafter
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above $0.675
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50
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%
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50
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%
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Equity
Compensation Plans
The equity compensation plan information required by
Item 201(d) of
Regulation S-K
in response to this item is incorporated by reference into
Item 12 Security Ownership of Certain Beneficial
Owners and Management and Related Unitholder Matters, of
this
Form 10-K.
Sales of
Unregistered Securities
None.
Issuer
Purchases of Equity Securities
None.
43
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Item 6.
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Selected
Financial Data
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The following table shows selected historical consolidated
financial and operating data of Calumet Specialty Products
Partners, L.P. and its consolidated subsidiaries
(Calumet) and Calumet Lubricants Co., Limited
Partnership (Predecessor). The selected historical
financial data as of and after December 31, 2008 includes
the operations acquired as part of the Penreco acquisition from
their date of acquisition, January 3, 2008. The selected
historical financial data as of December 31, 2005 and for
the year ended December 31, 2005 are derived from the
consolidated financial statements of the Predecessor. The
results of operations for the years ended December 31, 2006
for Calumet include the results of operations of the Predecessor
for the period of January 1, 2006 through January 31,
2006.
The following table includes the non-GAAP financial measures
EBITDA and Adjusted EBITDA. For a reconciliation of EBITDA and
Adjusted EBITDA to net income and net cash provided by (used in)
operating activities, our most directly comparable financial
performance and liquidity measures calculated in accordance with
GAAP, please read Non-GAAP Financial Measures.
We derived the information in the following table from, and that
information should be read together with and is qualified in its
entirety by reference to, the historical consolidated financial
statements and the accompanying notes included in Item 8
Financial Statements and Supplementary Data of this
Form 10-K
except for operating data such as sales volume, feedstock runs
and production. The table also should be read together with
Item 7 Managements Discussion and Analysis of
Financial Condition and Results of Operations.
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Calumet
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Predecessor
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Year Ended December 31,
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2009
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2008
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2007
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2006
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2005
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( In millions, except unit, per unit and operations data)
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Summary of Operations Data:
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Sales
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$
|
1,846.6
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$
|
2,489.0
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$
|
1,637.8
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$
|
1,641.0
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$
|
1,289.1
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Cost of sales
|
|
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1,673.5
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|
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2,235.1
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|
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1,456.4
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1,436.1
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|
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1,147.1
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Gross profit
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173.1
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|
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253.9
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181.4
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204.9
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142.0
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Operating costs and expenses:
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Selling, general and administrative
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32.6
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34.3
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19.6
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|
|
|
20.4
|
|
|
|
22.1
|
|
Transportation
|
|
|
68.0
|
|
|
|
84.7
|
|
|
|
54.0
|
|
|
|
56.9
|
|
|
|
46.8
|
|
Taxes other than income taxes
|
|
|
3.8
|
|
|
|
4.6
|
|
|
|
3.7
|
|
|
|
3.6
|
|
|
|
2.6
|
|
Other
|
|
|
1.3
|
|
|
|
1.6
|
|
|
|
2.9
|
|
|
|
0.9
|
|
|
|
0.9
|
|
Restructuring, decommissioning and asset impairments (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
67.4
|
|
|
|
128.7
|
|
|
|
101.2
|
|
|
|
123.1
|
|
|
|
67.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(33.6
|
)
|
|
|
(33.9
|
)
|
|
|
(4.7
|
)
|
|
|
(9.0
|
)
|
|
|
(23.0
|
)
|
Interest income
|
|
|
0.2
|
|
|
|
0.4
|
|
|
|
1.9
|
|
|
|
3.0
|
|
|
|
0.2
|
|
Debt extinguishment costs
|
|
|
|
|
|
|
(0.9
|
)
|
|
|
(0.4
|
)
|
|
|
(3.0
|
)
|
|
|
(6.9
|
)
|
Realized gain (loss) on derivative instruments
|
|
|
8.3
|
|
|
|
(58.8
|
)
|
|
|
(12.5
|
)
|
|
|
(30.3
|
)
|
|
|
2.8
|
|
Unrealized gain (loss) on derivative instruments
|
|
|
23.7
|
|
|
|
3.5
|
|
|
|
(1.3
|
)
|
|
|
12.3
|
|
|
|
(27.6
|
)
|
Gain on sale of mineral rights
|
|
|
|
|
|
|
5.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
(4.1
|
)
|
|
|
(0.1
|
)
|
|
|
(0.8
|
)
|
|
|
(0.3
|
)
|
|
|
0.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expense
|
|
|
(5.5
|
)
|
|
|
(84.0
|
)
|
|
|
(17.8
|
)
|
|
|
(27.3
|
)
|
|
|
(54.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income before income taxes
|
|
|
61.9
|
|
|
|
44.7
|
|
|
|
83.4
|
|
|
|
95.8
|
|
|
|
12.9
|
|
Income tax expense
|
|
|
0.1
|
|
|
|
0.3
|
|
|
|
0.5
|
|
|
|
0.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
61.8
|
|
|
$
|
44.4
|
|
|
$
|
82.9
|
|
|
$
|
95.6
|
|
|
$
|
12.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
44
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Calumet
|
|
|
Predecessor
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
( In millions, except unit, per unit and operations data)
|
|
|
Weighted average limited partner units outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
32,372,000
|
|
|
|
32,232,000
|
|
|
|
29,744,000
|
|
|
|
27,708,000
|
|
|
|
|
|
Diluted
|
|
|
32,372,000
|
|
|
|
32,232,000
|
|
|
|
29,746,000
|
|
|
|
27,708,000
|
|
|
|
|
|
Common and subordinated unitholders basic and diluted net
income per unit
|
|
$
|
1.87
|
|
|
$
|
1.35
|
|
|
$
|
2.61
|
|
|
$
|
3.19
|
|
|
|
|
|
Cash distributions declared per common and subordinated unit
|
|
$
|
1.81
|
|
|
$
|
1.98
|
|
|
$
|
2.43
|
|
|
$
|
1.30
|
|
|
|
|
|
Balance Sheet Data (at period end):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
$
|
629.3
|
|
|
$
|
659.7
|
|
|
$
|
442.9
|
|
|
$
|
191.7
|
|
|
$
|
127.8
|
|
Total assets
|
|
|
1,031.9
|
|
|
|
1,081.1
|
|
|
|
678.9
|
|
|
|
531.7
|
|
|
|
401.9
|
|
Accounts payable
|
|
|
110.0
|
|
|
|
93.9
|
|
|
|
168.0
|
|
|
|
78.8
|
|
|
|
44.8
|
|
Long-term debt
|
|
|
401.1
|
|
|
|
465.1
|
|
|
|
39.9
|
|
|
|
49.5
|
|
|
|
268.0
|
|
Total partners capital
|
|
|
485.3
|
|
|
|
473.2
|
|
|
|
399.6
|
|
|
|
385.3
|
|
|
|
43.9
|
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flow provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
100.9
|
|
|
$
|
130.3
|
|
|
$
|
167.5
|
|
|
$
|
166.8
|
|
|
$
|
(34.0
|
)
|
Investing activities
|
|
|
(22.7
|
)
|
|
|
(480.5
|
)
|
|
|
(260.9
|
)
|
|
|
(75.8
|
)
|
|
|
(12.9
|
)
|
Financing activities
|
|
|
(78.1
|
)
|
|
|
350.1
|
|
|
|
12.4
|
|
|
|
(22.2
|
)
|
|
|
41.0
|
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA
|
|
$
|
157.6
|
|
|
$
|
135.6
|
|
|
$
|
102.7
|
|
|
$
|
119.6
|
|
|
$
|
53.2
|
|
Adjusted EBITDA
|
|
|
146.0
|
|
|
|
128.1
|
|
|
|
104.3
|
|
|
|
104.5
|
|
|
|
85.8
|
|
Operating Data (bpd):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total sales volume (2)
|
|
|
57,086
|
|
|
|
56,232
|
|
|
|
47,663
|
|
|
|
50,345
|
|
|
|
46,953
|
|
Total feedstock runs (3)
|
|
|
60,081
|
|
|
|
56,243
|
|
|
|
48,354
|
|
|
|
51,598
|
|
|
|
50,213
|
|
Total production (4)
|
|
|
58,792
|
|
|
|
55,330
|
|
|
|
47,736
|
|
|
|
50,213
|
|
|
|
48,331
|
|
|
|
|
(1) |
|
Incurred in connection with the decommissioning of the
Rouseville, Pennsylvania facility, the termination of the Bareco
joint venture and the closing of the Reno, Pennsylvania
facility, none of which were contributed to Calumet Specialty
Products Partners, L.P. in connection with the closing of our
initial public offering on January 31, 2006. |
|
(2) |
|
Total sales volume includes sales from the production of our
facilities and, beginning in 2008, certain third-party
facilities pursuant to supply and/or processing agreements, and
sales of inventories. |
|
(3) |
|
Feedstock runs represents the barrels per day of crude oil and
other feedstocks processed at our facilities and, beginning in
2008, certain third-party facilities pursuant to supply and/or
processing agreements. |
|
(4) |
|
Total production represents the barrels per day of specialty
products and fuel products yielded from processing crude oil and
other feedstocks at our facilities and, beginning in 2008,
certain third-party facilities pursuant to supply and/or
processing agreements. The difference between total production
and total feedstock runs is primarily a result of the time lag
between the input of feedstock and production of finished
products and volume loss. |
45
Non-GAAP Financial
Measures
We include in this
Form 10-K
the non-GAAP financial measures EBITDA and Adjusted EBITDA, and
provide reconciliations of EBITDA and Adjusted EBITDA to net
income and net cash provided by (used in) operating activities,
our most directly comparable financial performance and liquidity
measures calculated and presented in accordance with GAAP.
EBITDA and Adjusted EBITDA are used as supplemental financial
measures by our management and by external users of our
financial statements such as investors, commercial banks,
research analysts and others, to assess:
|
|
|
|
|
the financial performance of our assets without regard to
financing methods, capital structure or historical cost basis;
|
|
|
|
the ability of our assets to generate cash sufficient to pay
interest costs, support our indebtedness, and meet minimum
quarterly distributions;
|
|
|
|
our operating performance and return on capital as compared to
those of other companies in our industry, without regard to
financing or capital structure; and
|
|
|
|
the viability of acquisitions and capital expenditure projects
and the overall rates of return on alternative investment
opportunities.
|
We believe that these non-GAAP measures are useful to our
analysts and investors as they exclude transactions not related
to our core cash operating activities. We believe that excluding
these transactions allows investors to meaningfully trend and
analyze the performance of our core cash operations.
We define EBITDA as net income plus interest expense (including
debt issuance and extinguishment costs), taxes and depreciation
and amortization. We define Adjusted EBITDA to be Consolidated
EBITDA as defined in our credit facilities. Consistent with that
definition, Adjusted EBITDA means, for any period: (1) net
income plus (2)(a) interest expense; (b) taxes;
(c) depreciation and amortization; (d) unrealized
losses from mark to market accounting for hedging activities;
(e) unrealized items decreasing net income (including the
non-cash impact of restructuring, decommissioning and asset
impairments in the periods presented); and (f) other
non-recurring expenses reducing net income which do not
represent a cash item for such period; minus (3)(a) tax credits;
(b) unrealized items increasing net income (including the
non-cash impact of restructuring, decommissioning and asset
impairments in the periods presented); (c) unrealized gains
from mark to market accounting for hedging activities; and
(d) other non-recurring expenses and unrealized items that
reduced net income for a prior period, but represent a cash item
in the current period.
We are required to report Adjusted EBITDA to our lenders under
our credit facilities and it is used to determine our compliance
with the consolidated leverage and consolidated interest
coverage tests thereunder. Please refer to Item 7
Managements Discussion and Analysis of Financial
Condition and Results of Operations Liquidity and
Capital Resources Debt and Credit Facilities
within this item for additional details regarding our credit
agreements.
EBITDA and Adjusted EBITDA should not be considered alternatives
to net income, operating income, net cash provided by (used in)
operating activities or any other measure of financial
performance presented in accordance with GAAP. In evaluating our
performance as measured by EBITDA and Adjusted EBITDA,
management recognizes and considers the limitations of this
measurement. EBITDA and Adjusted EBITDA do not reflect our
obligations for the payment of income taxes, interest expense or
other obligations such as capital expenditures. Accordingly,
EDITDA and Adjusted EBITDA are only two of the measurements that
management utilizes. Moreover, our EBITDA and Adjusted EBITDA
may not be comparable to similarly titled measures of another
company because all companies may not calculate EBITDA and
Adjusted EBITDA in the same manner. The following table presents
a reconciliation of both net income to EBITDA and Adjusted
EBITDA and Adjusted
46
EBITDA and EBITDA to net cash provided by (used in) operating
activities, our most directly comparable GAAP financial
performance and liquidity measures, for each of the periods
indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Calumet
|
|
|
Predecessor
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In millions)
|
|
|
Reconciliation of net income to EBITDA and Adjusted
EBITDA:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
61.8
|
|
|
$
|
44.4
|
|
|
$
|
82.9
|
|
|
$
|
95.6
|
|
|
$
|
12.9
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense and debt extinguishment costs
|
|
|
33.6
|
|
|
|
34.8
|
|
|
|
5.0
|
|
|
|
12.0
|
|
|
|
29.9
|
|
Depreciation and amortization
|
|
|
62.1
|
|
|
|
56.1
|
|
|
|
14.3
|
|
|
|
11.8
|
|
|
|
10.4
|
|
Income tax expense
|
|
|
0.1
|
|
|
|
0.3
|
|
|
|
0.5
|
|
|
|
0.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA
|
|
$
|
157.6
|
|
|
$
|
135.6
|
|
|
$
|
102.7
|
|
|
$
|
119.6
|
|
|
$
|
53.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized losses (gains) from mark to market accounting for
hedging activities
|
|
$
|
(14.5
|
)
|
|
$
|
(11.5
|
)
|
|
$
|
3.5
|
|
|
$
|
(13.1
|
)
|
|
$
|
27.6
|
|
Non-cash impact of restructuring, decommissioning and asset
impairments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1.7
|
|
Prepaid non-recurring expenses and accrued non-recurring
expenses, net of cash outlays
|
|
|
2.9
|
|
|
|
4.0
|
|
|
|
(1.9
|
)
|
|
|
(2.0
|
)
|
|
|
3.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
146.0
|
|
|
$
|
128.1
|
|
|
$
|
104.3
|
|
|
$
|
104.5
|
|
|
$
|
85.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
47
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Calumet
|
|
|
Predecessor
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In millions)
|
|
|
Reconciliation of Adjusted EBITDA and
EBITDA to net cash provided by (used in)
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
146.0
|
|
|
$
|
128.1
|
|
|
$
|
104.3
|
|
|
$
|
104.5
|
|
|
$
|
85.8
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized (losses) gains from mark to market accounting for
hedging activities
|
|
|
14.5
|
|
|
|
11.5
|
|
|
|
(3.5
|
)
|
|
|
13.1
|
|
|
|
(27.6
|
)
|
Non-cash impact of restructuring, decommissioning and asset
impairments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1.7
|
)
|
Prepaid non-recurring expenses and accrued non-recurring
expenses, net of cash outlays
|
|
|
(2.9
|
)
|
|
|
(4.0
|
)
|
|
|
1.9
|
|
|
|
2.0
|
|
|
|
(3.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA
|
|
$
|
157.6
|
|
|
$
|
135.6
|
|
|
$
|
102.7
|
|
|
$
|
119.6
|
|
|
$
|
53.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash interest expense and debt extinguishment costs
|
|
|
(29.9
|
)
|
|
|
(31.4
|
)
|
|
|
(4.6
|
)
|
|
|
(12.0
|
)
|
|
|
(29.8
|
)
|
Unrealized (gains) losses on derivative instruments
|
|
|
(23.7
|
)
|
|
|
(3.5
|
)
|
|
|
1.3
|
|
|
|
(12.3
|
)
|
|
|
27.6
|
|
Income taxes
|
|
|
(0.1
|
)
|
|
|
(0.3
|
)
|
|
|
(0.5
|
)
|
|
|
(0.2
|
)
|
|
|
|
|
Restructuring charge
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1.7
|
|
Provision for doubtful accounts
|
|
|
(0.9
|
)
|
|
|
1.5
|
|
|
|
|
|
|
|
0.2
|
|
|
|
0.3
|
|
Debt extinguishment costs
|
|
|
|
|
|
|
0.9
|
|
|
|
0.4
|
|
|
|
3.0
|
|
|
|
4.2
|
|
Changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(12.3
|
)
|
|
|
45.0
|
|
|
|
(15.0
|
)
|
|
|
16.0
|
|
|
|
(56.9
|
)
|
Inventory
|
|
|
(18.7
|
)
|
|
|
55.5
|
|
|
|
3.3
|
|
|
|
(2.6
|
)
|
|
|
(25.4
|
)
|
Other current assets
|
|
|
(2.8
|
)
|
|
|
1.8
|
|
|
|
(4.1
|
)
|
|
|
16.2
|
|
|
|
0.5
|
|
Derivative activity
|
|
|
8.5
|
|
|
|
41.8
|
|
|
|
2.1
|
|
|
|
(0.9
|
)
|
|
|
4.0
|
|
Accounts payable
|
|
|
16.0
|
|
|
|
(103.1
|
)
|
|
|
89.2
|
|
|
|
34.0
|
|
|
|
(13.3
|
)
|
Accrued liabilities
|
|
|
(1.0
|
)
|
|
|
(1.3
|
)
|
|
|
(4.2
|
)
|
|
|
0.7
|
|
|
|
5.3
|
|
Other, including changes in noncurrent assets and liabilities
|
|
|
8.2
|
|
|
|
(12.2
|
)
|
|
|
(3.1
|
)
|
|
|
5.1
|
|
|
|
(5.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
$
|
100.9
|
|
|
$
|
130.3
|
|
|
$
|
167.5
|
|
|
$
|
166.8
|
|
|
$
|
(34.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
48
|
|
Item 7.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
|
The historical consolidated financial statements included in
this
Form 10-K
reflect all of the assets, liabilities and results of operations
of Calumet Specialty Products Partners, L.P.
(Calumet). The following discussion analyzes the
financial condition and results of operations of Calumet for the
years ended December 31, 2009, 2008, and 2007. Unitholders
should read the following discussion and analysis of the
financial condition and results of operations for Calumet in
conjunction with the historical consolidated financial
statements and notes of Calumet included elsewhere in this
Form 10-K.
Overview
We are a leading independent producer of high-quality, specialty
hydrocarbon products in North America. We own plants located in
Princeton, Louisiana, Cotton Valley, Louisiana, Shreveport,
Louisiana, Karns City, Pennsylvania, and Dickinson, Texas, and a
terminal located in Burnham, Illinois. Our business is organized
into two segments: specialty products and fuel products. In our
specialty products segment, we process crude oil and other
feedstocks into a wide variety of customized lubricating oils,
white mineral oils, solvents, petrolatums and waxes. Our
specialty products are sold to domestic and international
customers who purchase them primarily as raw material components
for basic industrial, consumer and automotive goods. In our fuel
products segment, we process crude oil into a variety of fuel
and fuel-related products, including gasoline, diesel and jet
fuel. In connection with our production of specialty products
and fuel products, we also produce asphalt and a limited number
of other by-products which are allocated to either the specialty
products or fuel products segment. The asphalt and other
by-products produced in connection with the production of
specialty products at our Princeton, Cotton Valley and
Shreveport refineries are included in our specialty products
segment. The by-products produced in connection with the
production of fuel products at our Shreveport refinery are
included in our fuel products segment. The fuels produced in
connection with the production of specialty products at our
Princeton refinery, Cotton Valley refinery and our Karns City
facility are included in our specialty products segment. For
2009, approximately 81.8% of our gross profit was generated from
our specialty products segment and approximately 18.2% of our
gross profit was generated from our fuel products segment. We
continue to focus on the growth of our specialty products
segment. Our acquisition of Penreco on January 3, 2008 and
our entry into sales and processing agreements with
LyondellBasell, effective November 4, 2009, expanded our
specialty products offering and customer base. For additional
discussion of the Penreco acquisition and the LyondellBasell
contractual arrangements, please read Penreco
Acquisition and LyondellBasell Agreements.
Industry
Dynamics
The specialty petroleum products refining industry and, in
general, the overall refining industry continues to experience
economic challenges. Fuel products crack spreads declined
significantly during 2009, especially during the second half of
the year and, as a result, numerous refiners have announced
reductions in refinery throughput rates, the idling of refinery
assets and refinery closures. The relative stability in crude
oil prices during the second half of 2009 allowed Calumets
specialty products segment gross profit to remain fairly stable
but lower in 2009 compared to 2008. Overall demand for specialty
products did show some signs of strengthening during the last
six months of 2009 as compared to the fourth quarter of 2008 and
first quarter of 2009, but total specialty products segment
sales volume for 2009 declined approximately 9% compared to
2008. These market conditions led to lower gross profit per
barrel of product as compared to the prior year for many
refiners, including Calumet. We believe the majority of refiners
have continued to see an overall reduction in demand for their
products due to the weakness in the overall economic
environment, especially in demand for products closely tied to
the automotive and construction industries. Given these factors,
upcoming quarters will likely continue to be challenging for
refiners, including specialty products refiners like us.
We seek to differentiate ourself from our competitors,
especially in this continued challenging economic environment,
through a continued focus on a wide range of specialty products
sold in many different industries and enhancing our operations,
including increasing throughput rates at our recently expanded
Shreveport refinery and controlling plant operating costs.
Despite the continuing economic weakness during 2009, we were
able to (i) pay quarterly distributions totaling
approximately $59.3 million to our unitholders,
(ii) maintain compliance with the financial covenants of
our credit agreements and (iii) improve our liquidity
position at the end of 2009 as compared
49
to 2008 through cash flow from operations, reduced capital
expenditures and the completion of a public equity offering in
December 2009. In addition, we entered into new agreements with
a subsidiary of LyondellBasell to expand our specialty products
business related to naphthenic lubricating oils and white
mineral oils. For further discussion of these new agreements,
which were effective on November 4, 2009, please read
LyondellBasell Agreements.
LyondellBasell
Agreements
Effective November 4, 2009, we entered into the
LyondellBasell Agreements with an initial term of five years,
with Houston Refining, a wholly-owned subsidiary of
LyondellBasell, to form a long-term exclusive specialty products
affiliation. The initial term of the LyondellBasell Agreements
lasts until October 31, 2014. After October 31, 2014
the agreements are automatically extended for additional
one-year terms unless either party provides 24 months
notice of a desire to terminate either the initial term or any
renewal term. Under the terms of the LyondellBasell Agreements,
(i) we are the exclusive purchaser of Houston
Refinings naphthenic lubricating oil production at its
Houston, Texas refinery and are required to purchase a minimum
of approximately 3,000 bpd, and (ii) Houston Refining
will process a minimum of approximately 800 bpd of white
mineral oil for us at its Houston, Texas refinery, which will
supplement the existing white mineral oil production at our
Karns City, Pennsylvania and Dickinson, Texas facilities. We
also have exclusive rights to use certain LyondellBasell
registered trademarks and tradenames including Tufflo, Duoprime,
Duotreat, Crystex, Ideal and Aquamarine. The LyondellBasell
Agreements were deemed effective as of November 4, 2009
upon the approval of LyondellBasells debtor motions before
the U.S. Bankruptcy Court.
While no fixed assets were purchased under the LyondellBasell
Agreements, we expect these agreements to increase our working
capital requirements by approximately $30 million at
current market prices. Please refer to discussion within
Liquidity and Capital Resources for further
information.
Penreco
Acquisition
On January 3, 2008, we acquired Penreco, a Texas general
partnership, for $269.1 million. Penreco was owned by
ConocoPhillips and M.E. Zukerman Specialty Oil Corporation.
Penreco manufactures and markets highly refined products and
specialty solvents including white mineral oils, petrolatums,
natural petroleum sulfonates, cable-filling compounds,
refrigeration oils, food-grade compressor lubricants and gelled
products. The acquisition included facilities in Karns City,
Pennsylvania and Dickinson, Texas, as well as several long-term
supply agreements with ConocoPhillips. We funded the transaction
through a portion of the combined proceeds from a public equity
offering and a new senior secured first lien term loan facility.
For further discussion, please read Liquidity and Capital
Resources Debt and Credit Facilities. We
believe that this acquisition has provided several key long-term
strategic benefits, including market synergies within our
solvents and lubricating oil product lines, additional
operational and logistics flexibility and overhead cost
reductions. The acquisition has broadened our customer base and
has given us access to new specialty product markets.
Shreveport
Refinery Expansion
In the second quarter of 2008, we completed a
$374.0 million expansion project at our Shreveport refinery
to increase aggregate crude oil throughput capacity from
approximately 42,000 bpd to approximately 60,000 bpd
and improve feedstock flexibility. For further discussion of
this project, please read Liquidity and Capital
Resources Capital Expenditures.
Key
Performance Measures
Our sales and net income are principally affected by the price
of crude oil, demand for specialty and fuel products, prevailing
crack spreads for fuel products, the price of natural gas used
as fuel in our operations and our results from derivative
instrument activities.
Our primary raw materials are crude oil and other specialty
feedstocks and our primary outputs are specialty petroleum and
fuel products. The prices of crude oil, specialty products and
fuel products are subject to fluctuations in response to changes
in supply, demand, market uncertainties and a variety of
additional factors beyond our
50
control. We monitor these risks and enter into financial
derivatives designed to mitigate the impact of commodity price
fluctuations on our business. The primary purpose of our
commodity risk management activities is to economically hedge
our cash flow exposure to commodity price risk so that we can
meet our cash distribution, debt service and capital expenditure
requirements despite fluctuations in crude oil and fuel products
prices. We enter into derivative contracts for future periods in
quantities that do not exceed our projected purchases of crude
oil and natural gas and sales of fuel products. Please read
Item 7A Quantitative and Qualitative Disclosures
About Market Risk Commodity Price Risk. As of
December 31, 2009, we have hedged approximately
12.9 million barrels of fuel products through December 2011
at an average refining margin of $11.68 per barrel with average
refining margins ranging from a low of $11.32 in 2010 to a high
of $12.16 in 2011. During the first quarter of 2009, we entered
into derivative transactions for 1,500 bpd in 2010 to sell
crude oil and buy gasoline, which economically secured existing
gains on the derivative position of $6.52 per barrel. As a
result of these positions, we are now economically exposed to
deterioration of gasoline crack spreads below $0.17 per barrel
for 1,500 bpd in 2010. As of December 31, 2009, we
have 0.2 million barrels of crude oil options through
January 2010 to hedge our purchases of crude oil for specialty
products production. The strike prices and types of crude oil
options vary. Please refer to Item 7A Quantitative
and Qualitative Disclosures About Market Risk
Existing Commodity Derivative Instruments and
Quantitative and Qualitative Disclosures About Market
Risk Existing Interest Rate Derivative
Instruments for detailed information regarding our
derivative instruments.
Our management uses several financial and operational
measurements to analyze our performance. These measurements
include the following:
|
|
|
|
|
sales volumes;
|
|
|
|
production yields; and
|
|
|
|
specialty products and fuel products gross profit.
|
Sales volumes. We view the volumes of
specialty products and fuels products sold as an important
measure of our ability to effectively utilize our refining
assets. Our ability to meet the demands of our customers is
driven by the volumes of crude oil and feedstocks that we run at
our facilities. Higher volumes improve profitability both
through the spreading of fixed costs over greater volumes and
the additional gross profit achieved on the incremental volumes.
Production yields. In order to maximize our
gross profit and minimize lower margin by-products, we seek the
optimal product mix for each barrel of crude oil we refine,
which we refer to as production yield.
Specialty products and fuel products gross
profit. Specialty products and fuel products
gross profit are important measures of our ability to maximize
the profitability of our specialty products and fuel products
segments. We define specialty products and fuel products gross
profit as sales less the cost of crude oil and other feedstocks
and other production-related expenses, the most significant
portion of which include labor, plant fuel, utilities, contract
services, maintenance, depreciation and processing materials. We
use specialty products and fuel products gross profit as
indicators of our ability to manage our business during periods
of crude oil and natural gas price fluctuations, as the prices
of our specialty products and fuel products generally do not
change immediately with changes in the price of crude oil and
natural gas. The increase in selling prices typically lags
behind the rising costs of crude oil feedstocks for specialty
products. Other than plant fuel, production-related expenses
generally remain stable across broad ranges of throughput
volumes, but can fluctuate depending on maintenance activities
performed during a specific period.
In addition to the foregoing measures, we also monitor our
selling, general and administrative expenditures, substantially
all of which are incurred through our general partner, Calumet
GP, LLC.
51
High crude oil prices and the volatility of crude oil prices
have historically provided us with significant challenges.
During 2009, crude oil prices were less volatile than in 2008.
The average of the first nearby month NYMEX contract for crude
oil, which approximates our cost of crude oil, has fluctuated
significantly throughout 2009 and 2008 as follows:
|
|
|
|
|
|
|
Average
|
|
|
NYMEX Price
|
Quarter Ended:
|
|
of Crude Oil Per Barrel
|
|
March 31, 2008
|
|
$
|
97.82
|
|
June 30, 2008
|
|
|
123.80
|
|
September 30, 2008
|
|
|
118.22
|
|
December 31, 2008
|
|
|
59.42
|
|
March 31, 2009
|
|
|
43.31
|
|
June 30, 2009
|
|
|
58.86
|
|
September 30, 2009
|
|
|
68.25
|
|
December 31, 2009
|
|
|
76.11
|
|
Despite the relative stability of crude oil prices and specialty
product sales prices in 2009, we have experienced significant
volatility in our gross profit and realized hedging results
throughout the last two years. In response to this volatility,
we implemented multiple rounds of specialty product price
increases to customers during the first three quarters of 2008
and implemented reductions in our specialty products pricing
starting in the fourth quarter of 2008 in line with the
substantial decline in the price of crude oil. Also, we continue
to work diligently on other strategic initiatives. These
initiatives include optimizing our assets from our Shreveport
refinery expansion project and the Penreco acquisition and our
performance under the LyondellBasell Agreements. In addition,
they include using derivative instruments to mitigate the risk
of price fluctuations in crude oil input prices and maintaining
the working capital reductions we achieved during the past two
years. While we are taking steps to mitigate the adverse impact
of this volatile environment on our operating results, we can
provide no assurances as to the sustainability of the
improvements in our operating results and to the extent we
experience periods of rapidly escalating or declining crude oil
prices, our operating results and liquidity could be adversely
affected.
52
Results
of Operations
The following table sets forth information about our combined
operations. Production volume differs from sales volume due to
changes in inventory. The table does not include operations of
our Karns City, Pennsylvania and Dickinson, Texas facilities for
2007, as they were not acquired until January 3, 2008 with
the acquisition of Penreco, nor does it include LyondellBasell
Agreements volumes in 2008 and the majority of 2009, as such
agreements were not deemed effective until November 4, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In bpd)
|
|
|
Total sales volume (1)
|
|
|
57,086
|
|
|
|
56,232
|
|
|
|
47,663
|
|
Total feedstock runs (2)
|
|
|
60,081
|
|
|
|
56,243
|
|
|
|
48,354
|
|
Facility production (3):
|
|
|
|
|
|
|
|
|
|
|
|
|
Specialty products:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lubricating oils
|
|
|
11,681
|
|
|
|
12,462
|
|
|
|
10,734
|
|
Solvents
|
|
|
7,749
|
|
|
|
8,130
|
|
|
|
5,104
|
|
Waxes
|
|
|
1,049
|
|
|
|
1,736
|
|
|
|
1,177
|
|
Fuels
|
|
|
853
|
|
|
|
1,208
|
|
|
|
1,951
|
|
Asphalt and other by-products
|
|
|
7,574
|
|
|
|
6,623
|
|
|
|
6,157
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
28,906
|
|
|
|
30,159
|
|
|
|
25,123
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel products:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline
|
|
|
9,892
|
|
|
|
8,476
|
|
|
|
7,780
|
|
Diesel
|
|
|
12,796
|
|
|
|
10,407
|
|
|
|
5,736
|
|
Jet fuel
|
|
|
6,709
|
|
|
|
5,918
|
|
|
|
7,749
|
|
By-products
|
|
|
489
|
|
|
|
370
|
|
|
|
1,348
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
29,886
|
|
|
|
25,171
|
|
|
|
22,613
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total facility production
|
|
|
58,792
|
|
|
|
55,330
|
|
|
|
47,736
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Total sales volume includes sales from the production of our
facilities and, certain third-party facilities pursuant to
supply and/or processing agreements, and sales of inventories. |
|
(2) |
|
Total feedstock runs represents the barrels per day of crude oil
and other feedstocks processed at our facilities and, beginning
in 2008, at certain third-party facilities pursuant to supply
and/or processing agreements. The increase in feedstock runs in
2009 was due to the Shreveport refinery expansion project being
placed in service in May 2008 resulting in a full year of
increased production in 2009 compared to 2008 and the addition
of the LyondellBasell Agreements in November 2009. Partially
offsetting this increase were lower overall feedstock runs at
our other facilities in 2009 compared to 2008 due to general
economic conditions. The increase in feedstock runs in 2008
compared to 2007 is primarily due to the acquisition of the
Karns City and the Dickinson facilities as part of the Penreco
acquisition and the completion of the Shreveport refinery
expansion project in May 2008. These increases were offset by
decreases in production rates in the fourth quarter of 2008 due
to scheduled turnarounds at our Princeton, Cotton Valley and
Shreveport refineries. |
|
(3) |
|
Total facility production represents the barrels per day of
specialty products and fuel products yielded from processing
crude oil and other feedstocks at our facilities and, beginning
in 2008, certain third-party facilities pursuant to supply
and/or processing agreements. The difference between total
production and total feedstock runs is primarily a result of the
time lag between the input of feedstock and production of
finished products and volume loss. The change in production mix
to higher fuel products production in 2009 compared to 2008 is
due primarily to reduced demand for certain specialty products. |
53
The following table reflects our consolidated results of
operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Sales
|
|
$
|
1,846.6
|
|
|
$
|
2,489.0
|
|
|
$
|
1,637.8
|
|
Cost of sales
|
|
|
1,673.5
|
|
|
|
2,235.1
|
|
|
|
1,456.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
173.1
|
|
|
|
253.9
|
|
|
|
181.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Selling, general and administrative
|
|
|
32.6
|
|
|
|
34.3
|
|
|
|
19.6
|
|
Transportation
|
|
|
68.0
|
|
|
|
84.7
|
|
|
|
54.0
|
|
Taxes other than income taxes
|
|
|
3.8
|
|
|
|
4.6
|
|
|
|
3.7
|
|
Other
|
|
|
1.3
|
|
|
|
1.6
|
|
|
|
2.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
67.4
|
|
|
|
128.7
|
|
|
|
101.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(33.6
|
)
|
|
|
(33.9
|
)
|
|
|
(4.7
|
)
|
Interest income
|
|
|
0.2
|
|
|
|
0.4
|
|
|
|
1.9
|
|
Debt extinguishment costs
|
|
|
|
|
|
|
(0.9
|
)
|
|
|
(0.4
|
)
|
Realized gain (loss) on derivative instruments
|
|
|
8.3
|
|
|
|
(58.8
|
)
|
|
|
(12.5
|
)
|
Unrealized gain (loss) on derivative instruments
|
|
|
23.7
|
|
|
|
3.5
|
|
|
|
(1.3
|
)
|
Gain on sale of mineral rights
|
|
|
|
|
|
|
5.8
|
|
|
|
|
|
Other
|
|
|
(4.1
|
)
|
|
|
(0.1
|
)
|
|
|
(0.8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expense
|
|
|
(5.5
|
)
|
|
|
(84.0
|
)
|
|
|
(17.8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income before income taxes
|
|
|
61.9
|
|
|
|
44.7
|
|
|
|
83.4
|
|
Income tax expense
|
|
|
(0.1
|
)
|
|
|
(0.3
|
)
|
|
|
(0.5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
61.8
|
|
|
$
|
44.4
|
|
|
$
|
82.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
54
Year
Ended December 31, 2009 Compared to Year Ended
December 31, 2008
Sales. Sales decreased $642.4 million, or
25.8%, to $1,846.6 million in 2009 from
$2,489.0 million in 2008. Sales for each of our principal
product categories in these periods were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
% Change
|
|
|
|
(Dollars in millions)
|
|
|
Sales by segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
Specialty products:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lubricating oils
|
|
$
|
500.9
|
|
|
$
|
841.2
|
|
|
|
(40.5
|
)%
|
Solvents
|
|
|
260.2
|
|
|
|
419.8
|
|
|
|
(38.0
|
)%
|
Waxes
|
|
|
97.7
|
|
|
|
142.5
|
|
|
|
(31.5
|
)%
|
Fuels (1)
|
|
|
9.0
|
|
|
|
30.4
|
|
|
|
(70.5
|
)%
|
Asphalt and by-products (2)
|
|
|
103.4
|
|
|
|
144.1
|
|
|
|
(28.2
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total specialty products
|
|
|
971.2
|
|
|
|
1,578.0
|
|
|
|
(38.5
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total specialty products sales volume (in barrels)
|
|
|
9,370,000
|
|
|
|
10,289,000
|
|
|
|
(8.9
|
)%
|
Fuel products:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline
|
|
$
|
317.4
|
|
|
$
|
332.7
|
|
|
|
(4.6
|
)%
|
Diesel
|
|
|
372.4
|
|
|
|
379.7
|
|
|
|
(1.9
|
)%
|
Jet fuel
|
|
|
167.6
|
|
|
|
186.7
|
|
|
|
(10.2
|
)%
|
By-products (3)
|
|
|
18.0
|
|
|
|
11.9
|
|
|
|
51.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total fuel products
|
|
|
875.4
|
|
|
|
911.0
|
|
|
|
(3.9
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total fuel products sales volume (in barrels)
|
|
|
11,466,000
|
|
|
|
10,292,000
|
|
|
|
11.4
|
%
|
Total sales
|
|
$
|
1,846.6
|
|
|
$
|
2,489.0
|
|
|
|
(25.8
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total sales volume (in barrels)
|
|
|
20,836,000
|
|
|
|
20,581,000
|
|
|
|
1.2
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents fuels produced in connection with the production of
specialty products at the Princeton and Cotton Valley refineries. |
|
(2) |
|
Represents asphalt and other by-products produced in connection
with the production of specialty products at the Princeton,
Cotton Valley and Shreveport refineries. |
|
(3) |
|
Represents by-products produced in connection with the
production of fuels at the Shreveport refinery. |
The $642.4 million decrease in consolidated sales resulted
from a $606.8 million decrease in sales in the specialty
products segment and a $35.6 million decrease in sales in
the fuel products segment. Specialty products segment sales in
2009 decreased 38.5% primarily due to a 32.4% decrease in the
average selling price per barrel, with prices decreasing across
all specialty product categories in response to the 40.7%
decrease in the average cost of crude oil per barrel from 2008.
In addition, specialty products segment volumes sold decreased
by 8.9% from approximately 10.3 million barrels in 2008 to
9.4 million barrels in 2009. This decrease was primarily
due to lower demand for lubricating oils, solvents and waxes as
a result of the economic downturn. Asphalt and other by-products
sales volume increased slightly due to higher production of
these products resulting from increased throughput of sour crude
oil at our Shreveport refinery.
Fuel products segment sales in 2009 decreased 3.9% due to a
40.5% decrease in the average selling price per barrel as
compared to a 41.1% decrease in the overall cost of crude oil
per barrel, partially offset by an 11.4% increase in sales
volumes. Selling prices decreased across all fuel products
categories. Fuel products sales volumes increased from
approximately 10.3 million barrels in 2008 to
11.5 million barrels in 2009, primarily due to increases in
diesel and jet fuel sales volume as a result of the startup of
the Shreveport refinery expansion project during the second
quarter of 2008. Further offsetting the decrease in selling
prices was a $371.9 million increase in
55
derivative gains on our fuel products cash flow hedges, which is
recorded in sales. Please read Gross Profit below
for the net impact of our crude oil and fuel products derivative
instruments designated as hedges.
Gross Profit. Gross profit decreased
$80.8 million, or 31.8%, to $173.1 million in 2009
from $253.9 million in 2008. Gross profit for each of our
specialty and fuel products segments was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
% Change
|
|
|
|
(Dollars in millions)
|
|
|
Gross profit by segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
Specialty products
|
|
$
|
141.6
|
|
|
$
|
187.6
|
|
|
|
(24.5
|
)%
|
Percentage of sales
|
|
|
14.6
|
%
|
|
|
11.9
|
%
|
|
|
|
|
Fuel products
|
|
$
|
31.5
|
|
|
$
|
66.3
|
|
|
|
(52.5
|
)%
|
Percentage of sales
|
|
|
3.6
|
%
|
|
|
7.3
|
%
|
|
|
|
|
Total gross profit
|
|
$
|
173.1
|
|
|
$
|
253.9
|
|
|
|
(31.8
|
)%
|
Percentage of sales
|
|
|
9.4
|
%
|
|
|
10.2
|
%
|
|
|
|
|
The $80.8 million decrease in total gross profit includes a
decrease in gross profit of $46.0 million in the specialty
products segment and a $34.8 million decrease in gross
profit in the fuel products segment.
The decrease in specialty products segment gross profit was
primarily due to the 8.9% decrease in sales volume, as discussed
above, as well as a 32.4% decrease in the average selling price
per barrel partially offset by a 40.7% reduction in the cost of
crude oil per barrel. Further lowering our gross profit was a
reduction in the cost of sales benefit of $1.8 million in
2009 as compared to 2008 from the liquidation of lower cost
inventory layers. In addition, there were decreased derivative
gains of $21.4 million in 2009 as compared to 2008.
Fuel products segment gross profit was negatively impacted by a
40.5% decrease in the average fuel products selling price per
barrel as compared to a 41.1% decrease in the crude oil cost per
barrel, resulting in a reduction of approximately 36.4% in our
gross profit per barrel. Also lowering fuel products gross
profit was a reduction in the cost of sales benefit of
$16.6 million in 2009 as compared to 2008 for the
liquidation of lower cost inventory layers. Partially offsetting
these decreases in gross profit were increased sales volumes of
fuel products of 1.2 million barrels from 10.3 million
barrels in 2008 to 11.5 million barrels in 2009 and
increased derivative gains of $30.9 million from our crack
spread cash flow hedges.
Selling, general and administrative. Selling,
general and administrative expenses decreased $1.7 million,
or 5.0%, to $32.6 million in 2009 from $34.3 million
in 2008. This decrease was due primarily to reduced bad debt
expense of $2.4 million.
Transportation. Transportation expenses
decreased $16.7 million, or 19.8%, to $68.0 million in
2009 from $84.7 million in 2008. This decrease is as a
result of reduced sales volumes of lubricating oils, solvents
and waxes as well as cost reductions achieved in 2009 from
improvements in rail car leasing, lower fuel surcharges and
variable rail rates being reduced on certain routes.
Realized gain (loss) on derivative
instruments. Realized gain on derivative
instruments increased $67.2 million to a gain of
$8.3 million in 2009 from a $58.8 million loss in
2008. This increased gain was primarily the result of realized
gains on our crack spread derivatives that were executed to lock
in gains on a portion of our fuel products segment derivative
hedging activity in 2009 with no comparable activity in 2008. In
addition, we experienced significant losses in the third quarter
of 2008 on derivatives used to hedge our specialty products
segment crude oil purchases with no comparable activity in 2009.
Unrealized gain (loss) on derivative
instruments. Unrealized gain on derivative
instruments increased $20.3 million, to $23.7 million
in 2009 from $3.5 million in 2008. This increased gain is
primarily due to the derivatives used to economically hedge our
specialty products crude oil purchases experiencing significant
losses in 2008 as market prices declined in the third quarter of
2008 with no comparable losses in 2009.
Gain on sale of mineral rights. We recorded a
$5.8 million gain in 2008 resulting from the lease of
mineral rights on the real property at our Shreveport and
Princeton refineries to an unaffiliated third party, which was
56
accounted for as a sale, with no comparable activity in 2009. We
have retained a royalty interest in any future production
associated with these mineral rights.
Year
Ended December 31, 2008 Compared to Year Ended
December 31, 2007
Sales. Sales increased $851.1 million, or
52.0%, to $2,849.0 million in 2008 from
$1,637.8 million in 2007. Sales for each of our principal
product categories in these periods were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
% Change
|
|
|
|
(Dollars in millions)
|
|
|
Sales by segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
Specialty products:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lubricating oils
|
|
$
|
841.2
|
|
|
$
|
478.1
|
|
|
|
75.9
|
%
|
Solvents
|
|
|
419.8
|
|
|
|
199.8
|
|
|
|
110.1
|
%
|
Waxes
|
|
|
142.5
|
|
|
|
61.6
|
|
|
|
131.3
|
%
|
Fuels (1)
|
|
|
30.4
|
|
|
|
52.5
|
|
|
|
(42.1
|
)%
|
Asphalt and by-products (2)
|
|
|
144.1
|
|
|
|
74.7
|
|
|
|
92.9
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total specialty products
|
|
|
1,578.0
|
|
|
|
866.7
|
|
|
|
82.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total specialty products sales volume (in barrels)
|
|
|
10,289,000
|
|
|
|
8,410,000
|
|
|
|
22.3
|
%
|
Fuel products:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline
|
|
$
|
332.7
|
|
|
$
|
307.1
|
|
|
|
8.3
|
%
|
Diesel
|
|
|
379.7
|
|
|
|
203.7
|
|
|
|
86.5
|
%
|
Jet fuel
|
|
|
186.7
|
|
|
|
225.9
|
|
|
|
(17.4
|
)%
|
By-products (3)
|
|
|
11.9
|
|
|
|
34.4
|
|
|
|
(65.5
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total fuel products
|
|
|
911.0
|
|
|
|
771.1
|
|
|
|
18.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total fuel products sales volume (in barrels)
|
|
|
10,292,000
|
|
|
|
8,987,000
|
|
|
|
14.5
|
%
|
Total sales
|
|
$
|
2,489.0
|
|
|
$
|
1,637.8
|
|
|
|
52.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total sales volume (in barrels)
|
|
|
20,581,000
|
|
|
|
17,397,000
|
|
|
|
18.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents fuels produced in connection with the production of
specialty products at the Princeton and Cotton Valley refineries. |
|
(2) |
|
Represents asphalt and other by-products produced in connection
with the production of specialty products at the Princeton,
Cotton Valley and Shreveport refineries. |
|
(3) |
|
Represents by-products produced in connection with the
production of fuels at the Shreveport refinery. |
This $851.1 million increase in consolidated sales resulted
from a $711.3 million increase in sales in the specialty
products segment and a $139.8 million increase in sales in
the fuel products segment. Specialty products segment sales in
2008 increased $711.3 million, or 82.1%, primarily due to a
22.3% increase in volumes sold, from approximately
8.4 million barrels in 2007 to 10.3 million barrels in
2008 primarily due to an additional 2.4 million barrels of
sales volume of lubricating oils, solvents and waxes from our
operations acquired in the Penreco acquisition. Excluding sales
volume associated with Penreco, our specialty products sales
volume decreased 6.0% primarily due to lower fuels and solvents
sales volume due to lower production. These decreases were
partially offset by increased asphalt and by-products sales due
to increased production from the Shreveport refinery expansion
project. Specialty products segment sales were also positively
affected by a 39.2% increase in the average selling price per
barrel of specialty products at our Shreveport, Princeton and
Cotton Valley refineries compared to the prior period due to
price increases in all specialty products, with lubricating oils
and asphalt and by-products experiencing the largest sales price
increases. The sales price increases were implemented in
response to the rising cost of crude oil experienced early in
2008 as the cost of crude oil per barrel increased 40.2% over
2007.
57
Fuel products segment sales in 2008 increased
$139.8 million, or 18.1%, due to a 31.1% increase in the
average selling price per barrel as compared to 2007. This
increase compares to a 40.3% increase in the average cost of
crude oil per barrel over 2007. The increased sales price per
barrel was a result of increases in all fuel products prices as
prices increased in relation to the increase in the price of
crude oil. Gasoline prices increased at rates lower than the
overall increase in the crude oil price per barrel due primarily
to the decline in gasoline demand throughout 2008. Fuel products
segment sales were also positively affected by a 14.5% increase
in sales volumes, from approximately 9.0 million barrels in
2007 to 10.3 million barrels in 2008, primarily driven by
diesel sales volume. The increase in diesel sales volume was due
primarily to the startup of the Shreveport refinery expansion
project in May 2008 and shifts in product mix to diesel during
various points throughout 2008, which lowered jet fuel
production. Our Shreveport refinery has the ability to switch
portions of its production between diesel and other fuel and
specialty products to allow it to take advantage of the most
advantageous markets. The increased sales volume and sales
prices were offset by a $263.7 million increase in
derivative losses on our fuel products cash flow hedges recorded
in sales. Please see Gross Profit below for the net
impact of our crude oil and fuel products derivative instruments
designated as hedges.
Gross Profit. Gross profit increased
$72.5 million, or 40.0%, to $253.9 million in 2008
from $181.4 million in 2007. Gross profit for our specialty
and fuel products segments was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2008
|
|
2007
|
|
% Change
|
|
|
(Dollars in millions)
|
|
Gross profit by segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
Specialty products
|
|
$
|
187.6
|
|
|
$
|
115.4
|
|
|
|
62.6
|
%
|
Percentage of sales
|
|
|
11.9
|
%
|
|
|
13.3
|
%
|
|
|
|
|
Fuel products
|
|
$
|
66.3
|
|
|
$
|
66.0
|
|
|
|
0.5
|
%
|
Percentage of sales
|
|
|
7.3
|
%
|
|
|
8.6
|
%
|
|
|
|
|
Total gross profit
|
|
$
|
253.9
|
|
|
$
|
181.4
|
|
|
|
40.0
|
%
|
Percentage of sales
|
|
|
10.2
|
%
|
|
|
11.1
|
%
|
|
|
|
|
The $72.5 million increase in total gross profit includes
an increase in gross profit of $72.2 million in the
specialty products segment and a $0.3 million increase in
gross profit in the fuel products segment.
The increase in specialty products segment gross profit was due
primarily to a 22.3% increase in sales volume principally due to
an additional 2.4 million barrels of sales volume from our
operations acquired in the Penreco acquisition. Negatively
impacting our gross profit was the effect of our specialty
products sales price increases not keeping pace with the rising
cost of crude oil late in 2007 and in the first half of 2008.
During the last six months of 2007, our specialty products sales
prices increased by 7.9% while our average cost of crude oil
increased by approximately 28.8%. This trend continued during
the first six months of 2008 as our specialty products sales
prices, excluding Penreco, increased by 18.3% and our average
cost of crude oil increased by 31.3%. As crude oil prices
started falling late in 2008, we benefited from price increases
during the last six months of 2008 resulting in our specialty
products sales prices increasing 25.5% while the average cost of
crude oil decreased by 13.8%. Further lowering our gross profit
was a reduction in the cost of sales benefit of
$5.5 million in 2008 as compared to 2007 from the
liquidation of lower cost inventory layers. These decreases were
offset by increased derivative gains of $19.8 million in
2008 as compared to 2007. Additionally, in 2008 we entered into
derivative contracts to economically hedge specialty crude
purchases which were not designated as hedges in accordance with
ASC 815-10,
Derivatives and Hedging (formerly SFAS 133,
Accounting for Derivative Instruments and Hedging
Activities). The impact of these hedges that settled in 2008
was a realized loss of $47.0 million which is recorded in
realized loss on derivative instruments in our statements of
operations as discussed below.
Fuel products segment gross profit was positively impacted by a
14.5% increase in fuel products sales volume as discussed above.
This increase was partially offset by the rising cost of crude
oil outpacing increases in the selling price per barrel of our
fuel products. The average cost of crude oil increased by
approximately 40.3% from 2007 to 2008 while the average selling
price per barrel of our fuel products increased by only 31.1%
primarily due to gasoline sales prices increasing at rates lower
than the overall increase in the crude oil price per barrel due
to the
58
decline in gasoline demand throughout 2008. Additionally,
lowering our gross profit was a reduction in the cost of sales
benefit of $8.9 million in 2008 as compared to 2007 from
the liquidation of lower cost inventory layers.
Selling, general and administrative. Selling,
general and administrative expenses increased
$14.7 million, or 74.7%, to $34.3 million in 2008 from
$19.6 million in 2007. This increase is primarily due to
additional selling, general and administrative expenses
associated with the Penreco acquisition. Selling, general and
administrative expenses also increased due to additional accrued
incentive compensation costs in 2008 as compared to 2007.
Transportation. Transportation expenses
increased $30.7 million, or 56.8%, to $84.7 million in
2008 from $54.0 million in 2007. This increase is primarily
related to additional transportation expenses associated with
the Penreco acquisition.
Interest expense. Interest expense increased
$29.2 million, or 619.5%, to $33.9 million in 2008
from $4.7 million in 2007. This increase was primarily due
to an increase in indebtedness as a result of a new senior
secured term loan facility, which closed on January 3, 2008
and includes a $385.0 million term loan partially used to
finance the acquisition of Penreco, as well as increased
borrowings on our revolving credit facility primarily due to
higher than expected capital expenditures to complete the
Shreveport refinery expansion project. This increase was
partially offset by an increase in capitalized interest as a
result of increased capital expenditures on the Shreveport
refinery expansion project.
Interest income. Interest income decreased
$1.6 million to $0.4 million in 2008 from
$1.9 million in 2007. This decrease was primarily due to a
larger average cash and cash equivalents balance during 2007 as
compared to 2008 due to the utilization of cash for capital
expenditures on the Shreveport refinery expansion project.
Debt extinguishment costs. Debt extinguishment
costs increased $0.5 million to $0.9 million in 2008
from $0.4 million in 2007. This increase was primarily due
to the repayment of our prior senior secured term loan facility
with a portion of the proceeds of our new senior secured term
loan facility. The increase was also the result of debt
extinguishment costs recognized in conjunction with the
repayment of a portion of our new senior secured term loan
facility using the proceeds of the sale of mineral rights on our
real property at our Shreveport and Princeton refineries.
Realized loss on derivative
instruments. Realized loss on derivative
instruments increased $46.3 million to $58.8 million
in 2008 from $12.5 million in 2007. This increased loss was
primarily the result of the unfavorable settlement of certain
derivative instruments not designated as cash flow hedges in
2008 as compared to 2007 as crude oil prices declined rapidly in
the third and fourth quarters of 2008. These derivative
instruments were primarily combinations of crude oil options
related to our specialty products segment crude oil purchases
and are utilized to economically offset our exposure to rising
crude oil prices.
Unrealized gain (loss) on derivative
instruments. Unrealized gain on derivative
instruments increased $4.8 million, to $3.5 million in
2008 from a loss of $1.3 million in 2007. This increased
gain was due primarily to the increase in gain ineffectiveness
related to derivative instruments in our fuel products segment
in 2008 as compared to 2007. This was offset by the unfavorable
mark-to-market
changes for certain derivative instruments in our specialty
products segment not designated as cash flow hedges, including
crude oil collars, natural gas swap contracts, and interest rate
swap contracts, being recorded to unrealized loss on derivative
instruments in 2008 as compared 2007.
Gain on sale of mineral rights. We recorded a
$5.8 million gain in 2008 resulting from the lease of
mineral rights on the real property at our Shreveport and
Princeton refineries to an unaffiliated third party, which was
accounted for as a sale. We have retained a royalty interest in
any future production associated with these mineral rights.
Liquidity
and Capital Resources
Our principal sources of cash have historically included cash
flow from operations, proceeds from public equity offerings and
bank borrowings. Principal uses of cash have included capital
expenditures, acquisitions, distributions and debt service. We
expect that our principal uses of cash in the future will be for
working capital as we continue to increase our throughput rate
at the Shreveport refinery and increased working capital
requirements
59
from the LyondellBasell Agreements, distributions to our limited
partners and general partner, debt service, and capital
expenditures related to internal growth projects and
acquisitions from third parties or affiliates. Future internal
growth projects or acquisitions may require expenditures in
excess of our then-current cash flow from operations and cause
us to issue debt or equity securities in public or private
offerings or incur additional borrowings under bank credit
facilities to meet those costs. Given the current credit
environment and our continued efforts to reduce leverage to
ensure continued covenant compliance under our credit
facilities, we do not anticipate completing any significant
acquisitions, internal growth projects or replacement and
environmental capital expenditures that would cause total
spending to exceed $30.0 million during 2010. We anticipate
future capital expenditures will be funded with current cash
flows from operations and borrowings under our existing
revolving credit facility.
Cash
Flows
We believe that we have sufficient liquid assets, cash flow from
operations and borrowing capacity to meet our financial
commitments, debt service obligations, and anticipated capital
expenditures. However, we are subject to business and
operational risks that could materially adversely affect our
cash flows. A material decrease in our cash flow from
operations, including a significant, sudden change in crude oil
prices, would likely produce a corollary material adverse effect
on our borrowing capacity under our revolving credit facility
and potentially a material adverse impact on our ability to
comply with the covenants under our credit facilities.
The following table summarizes our primary sources and uses of
cash in each of the most recent three years:
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Year Ended December 31,
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2009
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2008
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|
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2007
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|
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(In millions)
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Net cash provided by operating activities
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$
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100.9
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$
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130.3
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|
|
$
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167.5
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Net cash used in investing activities
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$
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(22.7
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)
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$
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(480.5
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)
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$
|
(260.9
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)
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Net cash provided by (used in) financing activities
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$
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(78.1
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)
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$
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350.1
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|
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$
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12.4
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Operating Activities. Operating activities
provided $100.9 million in cash during 2009 compared to
$130.3 million during 2008. The decrease in cash provided
by operating activities during 2009 was primarily due to
increased working capital requirements as a result of the
LyondellBasell Agreements of $19.2 million as well as
rising crude oil prices increasing our working capital
requirements, partially offset by increased net income of
$17.3 million.
Operating activities provided $130.3 million in cash during
2008 compared to $167.5 million during 2007. The decrease
in cash provided by operating activities during 2008 was
primarily due to increased working capital of
$35.5 million, combined with a decrease of net income,
after adjusting for non-cash items, of $1.7 million. The
increase in working capital was due primarily to the decrease in
accounts payable resulting from significantly lower crude oil
and other feedstock prices at December 31, 2008 as compared
to December 31, 2007 and losses from our derivative
activities. The reduction in accounts payable was partially
offset by significant decreases in inventory and accounts
receivable as a result of our working capital reduction
initiatives and lower crude oil prices and fuel products selling
prices.
Investing Activities. Cash used in investing
activities decreased to $22.7 million during 2009 compared
to $480.5 million during 2008. This decrease was due
primarily to the acquisition of Penreco for $269.1 million
and spending on the Shreveport expansion project in 2008 of
$119.6 million, with no comparable activity in 2009. Also
decreasing the use of cash for investing activities in 2009 was
the early settlement of $49.7 million of derivative
instruments related to 2008 and 2009 utilized to economically
hedge the risk of rising crude oil prices in 2008 with no
comparable activity in 2009.
Cash used in investing activities increased to
$480.5 million during 2008 compared to $260.9 million
during 2007. This increase was primarily due to the acquisition
of Penreco for $269.1 million. Also increasing the use of
cash for investing activities was the settlement of
$49.7 million of derivative instruments utilized to
economically hedge the risk of rising crude oil prices. As crude
oil prices declined significantly during the last six months of
2008, the realized losses on these derivative instruments
increased. Offsetting this increased use of cash was a decrease
of
60
$93.3 million in capital expenditures in 2008 compared to
2007. The majority of the capital expenditures were incurred at
our Shreveport refinery, with $119.6 million related to the
Shreveport refinery expansion project incurred in 2008 as
compared to $188.9 million incurred in 2007. The remaining
decrease in capital expenditures of $24.0 million primarily
related to lower spending on various other capital projects at
our Shreveport refinery compared to the prior year. Further
offsetting the increased use of cash was the $6.1 million
of cash proceeds received as a result of selling certain mineral
rights on our real property at our Shreveport and Princeton
refineries to a third party during the second quarter of 2008.
Financing Activities. Cash used in financing
activities was $78.1 million during 2009 compared to cash
provided of $350.1 million during 2008. This change was
primarily due to proceeds from borrowings under the new senior
secured term loan credit facility of $385.0 million along
with associated debt issuance costs incurred during 2008 with no
comparable activity in 2009. The increased use of cash was also
due to net repayments on the revolving credit facility of
$62.6 million compared to net borrowings of
$95.6 million in 2008, primarily due to final spending on
the Shreveport refinery expansion project in 2008. Partially
offsetting the increased use of cash were the proceeds received
from our December 2009 public equity offering of approximately
$52.3 million, including $1.1 million of contributions
received from our general partner.
Financing activities provided cash of $350.1 million during
2008 as compared to $12.4 million during 2007. This change
was primarily due to borrowings under the new senior secured
term loan credit facility along with associated debt issuance
costs. A portion of the new term loan proceeds of
$385.0 million was used to finance the acquisition of
Penreco. The increase was also due to a $88.6 million
increase in borrowings on our revolving credit facility,
primarily due to spending on the Shreveport refinery expansion
project. These increases were offset by uses of cash to repay
our old term loan of $10.7 million, increased debt issuance
costs of $9.3 million and repayments under the new term
loan of $9.9 million. The repayments under the new term
loan are approximately $1.0 million per quarter. We sold
certain mineral rights and our term loan credit agreement
required that the proceeds of $6.1 million be used to repay
an equal portion of the term loan. Our distributions to partners
decreased $10.9 million as we reduced our distribution
early in 2008 to our minimum quarterly distribution of $0.45 per
unit.
On January 5, 2010, we declared a quarterly cash
distribution of $0.455 per unit on all outstanding units, or
$16.4 million, for the quarter ended December 31,
2009. The distribution was paid on February 12, 2010 to
unitholders of record as of the close of business on
February 2, 2010. This quarterly distribution of $0.455 per
unit equates to $1.82 per unit, or $65.6 million, on an
annualized basis.
Capital
Expenditures
Our capital expenditure requirements consist of capital
improvement expenditures, replacement capital expenditures and
environmental capital expenditures. Capital improvement
expenditures include expenditures to acquire assets to grow our
business and to expand existing facilities, such as projects
that increase operating capacity. Replacement capital
expenditures replace worn out or obsolete equipment or parts.
Environmental capital expenditures include asset additions to
meet or exceed environmental and operating regulations.
The following table sets forth our capital improvement
expenditures, replacement capital expenditures and environmental
capital expenditures in each of the periods shown.
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Year Ended December 31,
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2009
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2008
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2007
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(In millions)
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Capital improvement expenditures
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$
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8.0
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$
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161.6
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$
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248.8
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Replacement capital expenditures
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12.1
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|
|
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4.4
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10.9
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Environmental capital expenditures
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3.4
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1.7
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1.3
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|
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Total
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$
|
23.5
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|
|
$
|
167.7
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$
|
261.0
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|
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We anticipate that future capital expenditure requirements will
be provided primarily through cash provided by operations and
available borrowings under our revolving credit facility. In
2009, we limited our overall capital expenditures to required
environmental expenditures, necessary replacement capital
expenditures to maintain our facilities and minor capital
improvement projects to reduce energy costs, improve finished
product quality and
61
finished product yields. Management estimates its replacement
and environmental capital expenditures to be approximately
$4.0 million per quarter in 2010 with total capital
expenditures remaining generally consistent with 2009.
Over the past three years, we have invested significantly in
expanding and enhancing the operations at our facilities,
primarily at our Shreveport refinery. We invested a total of
approximately $8.0 million, $161.6 million, and
$248.8 million during 2009, 2008 and 2007, respectively. Of
these investments during these periods, $308.5 million was
related to our Shreveport refinery expansion project completed
and operational in May 2008. Approximately $123.2 million
was related to other projects to improve efficiency,
de-bottleneck certain operating units and for new product
development. These expenditures have enhanced and improved our
product mix and operating cost leverage, but did not
significantly increase the feedstock throughput capacity of our
Shreveport refinery or our other refineries.
The Shreveport expansion project has increased this
refinerys throughput capacity from 42,000 bpd to
60,000 bpd and enhanced the Shreveport refinerys
ability to process sour crude oil up to approximately
25,000 bpd. In 2008, the Shreveport refinery had total
feedstock runs of 37,096 bpd, representing an increase of
approximately 2,744 bpd from 2007, before completion of the
Shreveport expansion project. In 2008, the Shreveport refinery
did not achieve the expected significant increase in feedstock
runs compared to 2007 due primarily to unscheduled downtime due
to Hurricane Ike and scheduled downtime in the fourth quarter of
2008 to complete a three-week turnaround. In 2009, feedstock run
rates at our Shreveport refinery averaged approximately
43,639 bpd. We did not increase feedstock run rates further
due to the continued impacts of the economic downturn.
Debt
and Credit Facilities
On January 3, 2008, we repaid all of our indebtedness under
our previous senior secured first lien term loan credit
facility, entered into new senior secured first lien term loan
facility and amended our existing senior secured revolving
credit facility. As of December 31, 2009, our credit
facilities consist of:
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a $375.0 million senior secured revolving credit facility,
subject to borrowing base restrictions, with a standby letter of
credit sublimit of $300.0 million; and
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a $435.0 million senior secured first lien credit
facility consisting of a $385.0 million
term loan facility and a $50.0 million letter of credit
facility to support crack spread hedging. In connection with the
execution of the senior secured first lien credit facility, we
incurred total debt issuance costs of $23.4 million,
including $17.4 million of issuance discounts.
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Borrowings under the amended revolving credit facility are
limited by advance rates of percentages of eligible accounts
receivable and inventory (the borrowing base) as defined by the
revolving credit agreement. As such, the borrowing base can
fluctuate based on changes in selling prices of our products and
our current material costs, primarily the cost of crude oil. The
borrowing base cannot exceed the total commitments of the lender
group. The lender group under our revolving credit facility is
comprised of a syndicate of nine lenders with total commitments
of $375.0 million. The number of lenders in our facility
has been reduced from ten due to an acquisition. If further
acquisitions occur, we will increase the concentration of our
exposure to certain financial institutions. Currently, the
largest member of our bank group provides a commitment for
$87.5 million. The smallest commitment is $15 million
and the median commitment is $42.5 million. In the event of
a default by one of the lenders in the syndicate, the total
commitments under the revolving credit facility would be reduced
by the defaulting lenders commitment, unless another
lender or a combination of lenders increase their commitments to
replace the defaulting lender. In the alternative, the revolving
credit facility also permits us to replace a defaulting lender.
Although we do not expect any current lenders to default under
the revolving credit facility, we can provide no assurance that
lender defaults will not occur. Also, our borrowing base at
December 31, 2009 was $194.0 million; thus, we would
have to experience defaults in commitments totaling
$181.0 million from our lender group before such defaults
would impact our liquidity as of December 31, 2009.
Accordingly, at least three of our nine lenders would have to
default in order for our current liquidity position under the
revolving credit facility to be adversely impacted.
62
The revolving credit facility, which is our primary source of
liquidity for cash needs in excess of cash generated from
operations, currently bears interest at prime plus a basis
points margin or LIBOR plus a basis points margin, at our
option. This margin is currently at 50 basis points for
prime and 200 basis points for LIBOR; however, it
fluctuates based on measurement of our Consolidated Leverage
Ratio discussed below and is expected to be reduced during the
first quarter of 2010 to 25 basis points for prime and
175 basis points for LIBOR due to the reduction in our
Consolidated Leverage Ratio. The revolving credit facility has a
first priority lien on our cash, accounts receivable and
inventory and a second priority lien on our fixed assets which
matures in January 2013. On December 31, 2009, we had
availability on our revolving credit facility of
$107.3 million, based upon a $194.0 million borrowing
base, $46.9 million in outstanding standby letters of
credit, and outstanding borrowings of $39.9 million. The
improvement in our availability under our revolving credit
facility of approximately $56.0 million from
December 31, 2008 to December 31, 2009 is due
primarily to cash flow from operations and the
$52.3 million in proceeds from our December 2009 public
equity offering that were used to reduce borrowings under our
revolving credit facility offset by capital expenditures,
distributions to unitholders, and debt service costs.
Additionally, availability under the revolving credit facility
at December 31, 2009 was reduced by incremental working
capital requirements related to our obligations under the
LyondellBasell Agreements in November 2009. We believe that we
have sufficient cash flow from operations and borrowing capacity
to meet our financial commitments, debt service obligations,
contingencies and anticipated capital expenditures. However, we
are subject to business and operational risks that could
materially adversely affect our cash flows. A material decrease
in our cash flow from operations or a significant, sustained
decline in crude oil prices would likely produce a corollary
material adverse effect on our borrowing capacity under our
revolving credit facility and potentially have a material
adverse effect on our ability to comply with the covenants under
our credit facilities. Substantial declines in crude oil prices,
if sustained, may materially diminish our borrowing base which
is based, in part, on the value of our crude oil inventory and
could result in a material reduction in our borrowing capacity
under our revolving credit facility.
The term loan facility, fully drawn at $385.0 million on
January 3, 2008, bears interest at a rate of LIBOR plus
400 basis points or prime plus 300 basis points, at
our option. Management has historically kept the outstanding
balance on a LIBOR basis; however, that decision is evaluated
every three months to determine if a portion should be converted
back to the prime rate. Each lender under this facility has a
first priority lien on our fixed assets and a second priority
lien on our cash, accounts receivable and inventory. Our term
loan facility matures in January 2015. Under the terms of our
term loan facility, we applied a portion of the net proceeds
from the term loan facility to the acquisition of Penreco. We
are required to make mandatory repayments of approximately
$1.0 million at the end of each fiscal quarter, beginning
with the fiscal quarter ended March 31, 2008 and ending
with the fiscal quarter ending September 30, 2014, with the
remaining balance due at maturity on January 3, 2015. In
June 2008, we received lease bonuses of $6.1 million
associated with the sale of mineral rights on our real property
at our Shreveport and Princeton refineries to a non-affiliated
third party. As a result of these transactions, we recorded a
gain of $5.8 million in other income (expense) in the
consolidated statements of operations. Under the term loan
agreement, cash proceeds resulting from the disposition of our
property, plant and equipment generally must be used as a
mandatory prepayment of the term loan. As a result, in June 2008
we made a prepayment of $6.1 million on the term loan.
Our letter of credit facility to support crack spread hedging
bears interest at a rate of 4.0% and is secured by a first
priority lien on our fixed assets. We have issued a letter of
credit in the amount of $50.0 million, the full amount
available under this letter of credit facility, to one
counterparty. As long as this first priority lien is in effect
and the counterparty remains the beneficiary of the
$50.0 million letter of credit, we will have no obligation
to post additional cash, letters of credit or other collateral
with the counterparty to provide additional credit support for a
mutually-agreed maximum volume of executed crack spread hedges.
In the event the counterpartys exposure to us exceeds
$100.0 million, we would be required to post additional
credit support to enter into additional crack spread hedges up
to the aforementioned maximum volume. In addition, we have other
crack spread hedges in place with other approved counterparties
under the letter of credit facility whose credit exposure to us
is also secured by a first priority lien on our fixed assets,
subject to certain conditions.
Our credit facilities permit us to make distributions to our
unitholders as long as we are not in default and would not be in
default following the distribution. Under the credit facilities,
we were historically obligated to
63
comply with certain financial covenants requiring us to maintain
a Consolidated Leverage Ratio of no more than 4.0 to 1 and a
Consolidated Interest Coverage Ratio of no less than 2.50 to 1
(as of the end of each fiscal quarter and after giving effect to
a proposed distribution or other restricted payments as defined
in the credit agreements) and Availability (as such term is
defined in our credit agreements) of at least $35.0 million
(after giving effect to a proposed distribution or other
restricted payments as defined in the credit agreements). As of
the fiscal quarter ended June 30, 2009 and for all future
quarters, we are obligated to maintain a Consolidated Leverage
Ratio of no more than 3.75 to 1, a Consolidated Interest
Coverage Ratio of no less than 2.75 to 1 and Availability of at
least $35.0 million (after giving effect to a proposed
distribution or other restricted payments as defined in the
credit agreements. The Consolidated Leverage Ratio is defined
under our credit agreements to mean the ratio of our
Consolidated Debt (as defined in the credit agreements) as of
the last day of any fiscal quarter to our Adjusted EBITDA (as
defined below) for the last four fiscal quarter periods ending
on such date. The Consolidated Interest Coverage Ratio is
defined as the ratio of Consolidated EBITDA for the last four
fiscal quarters to Consolidated Interest Charges for the same
period. Adjusted EBITDA means Consolidated EBITDA as defined in
our credit facilities to mean, for any period: (1) net
income plus (2)(a) interest expense; (b) taxes;
(c) depreciation and amortization; (d) unrealized
losses from mark to market accounting for hedging activities;
(e) unrealized items decreasing net income (including the
non-cash impact of restructuring, decommissioning and asset
impairments in the periods presented); (f) other
non-recurring expenses reducing net income which do not
represent a cash item for such period; and (g) all
non-recurring restructuring charges associated with the Penreco
acquisition minus (3)(a) tax credits; (b) unrealized items
increasing net income (including the non-cash impact of
restructuring, decommissioning and asset impairments in the
periods presented); (c) unrealized gains from mark to
market accounting for hedging activities; and (d) other
non-recurring expenses and unrealized items that reduced net
income for a prior period, but represent a cash item in the
current period.
In addition, if at any time that our borrowing capacity under
our revolving credit facility falls below $35.0 million,
meaning we have Availability of less than $35.0 million, we
will be required to immediately measure and maintain a Fixed
Charge Coverage Ratio of at least 1 to 1 (as of the end of each
fiscal quarter). The Fixed Charge Coverage Ratio is defined
under our credit agreements to mean the ratio of
(a) Adjusted EBITDA minus Consolidated Capital Expenditures
minus Consolidated Cash Taxes, to (b) Fixed Charges (as
each such term is defined in our credit agreements).
Compliance with the financial covenants pursuant to our credit
agreements is measured quarterly based upon performance over the
most recent four fiscal quarters, and as of December 31,
2009, we believe we were in compliance with all financial
covenants under our credit agreements and have adequate
liquidity to conduct our business. Even though our liquidity and
leverage improved during fiscal year 2009, we are continuing to
take steps to ensure that we continue to meet the requirements
of our credit agreements and currently believe that we will be
in compliance for all future measurement dates, although
assurances cannot be made regarding our future compliance with
these covenants.
Failure to achieve our anticipated results may result in a
breach of certain of the financial covenants contained in our
credit agreements. If this occurs, we will enter into
discussions with our lenders to either modify the terms of the
existing credit facilities or obtain waivers of non-compliance
with such covenants. There can be no assurances of the timing of
the receipt of any such modification or waiver, the term or
costs associated therewith or our ultimate ability to obtain the
relief sought. Our failure to obtain a waiver of non-compliance
with certain of the financial covenants or otherwise amend the
credit facilities would constitute an event of default under our
credit facilities and would permit the lenders to pursue
remedies. These remedies could include acceleration of maturity
under our credit facilities and limitations on, or the
elimination of, our ability to make distributions to our
unitholders. If our lenders accelerate maturity under our credit
facilities, a significant portion of our indebtedness may become
due and payable immediately. We might not have, or be able to
obtain, sufficient funds to make these accelerated payments. If
we are unable to make these accelerated payments, our lenders
could seek to foreclose on our assets.
In addition, our credit agreements contain various covenants
that limit our ability, among other things, to: incur
indebtedness; grant liens; make certain acquisitions and
investments; make capital expenditures above specified amounts;
redeem or prepay other debt or make other restricted payments
such as distributions to unitholders; enter into transactions
with affiliates; enter into a merger, consolidation or sale of
assets; and cease our refining margin hedging program (our
lenders have required us to obtain and maintain derivative
contracts for fuel products margins
64
in our fuel products segment for a rolling period of 1 to
12 months for at least 60% and no more than 90% of our
anticipated fuels production, and for a rolling
13-24 months
forward for at least 50% and no more than 90% of our anticipated
fuels production).
If an event of default exists under our credit agreements, the
lenders will be able to accelerate the maturity of the credit
facilities and exercise other rights and remedies. An event of
default is defined as nonpayment of principal interest, fees or
other amounts; failure of any representation or warranty to be
true and correct when made or confirmed; failure to perform or
observe covenants in the credit agreement or other loan
documents, subject to certain grace periods; payment defaults in
respect of other indebtedness; cross-defaults in other
indebtedness if the effect of such default is to cause the
acceleration of such indebtedness under any material agreement
if such default could have a material adverse effect on us;
bankruptcy or insolvency events; monetary judgment defaults;
asserted invalidity of the loan documentation; and a change of
control in us.
Contractual
Obligations and Commercial Commitments
A summary of our total contractual cash obligations as of
December 31, 2009 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
|
|
|
|
|
Less Than
|
|
|
1-3
|
|
|
3-5
|
|
|
More Than
|
|
|
|
Total
|
|
|
1 Year
|
|
|
Years
|
|
|
Years
|
|
|
5 Years
|
|
|
|
(In thousands)
|
|
|
Long-term debt obligations, excluding capital lease obligations
|
|
$
|
411,135
|
|
|
$
|
3,850
|
|
|
$
|
7,700
|
|
|
$
|
47,600
|
|
|
$
|
351,985
|
|
Interest on long-term debt at contractual rates
|
|
|
92,846
|
|
|
|
20,879
|
|
|
|
40,949
|
|
|
|
30,892
|
|
|
|
126
|
|
Capital lease obligations
|
|
|
2,938
|
|
|
|
1,159
|
|
|
|
1,544
|
|
|
|
235
|
|
|
|
|
|
Operating lease obligations (1)
|
|
|
35,088
|
|
|
|
11,137
|
|
|
|
15,170
|
|
|
|
7,731
|
|
|
|
1,050
|
|
Letters of credit (2)
|
|
|
96,859
|
|
|
|
46,859
|
|
|
|
50,000
|
|
|
|
|
|
|
|
|
|
Purchase commitments (3)
|
|
|
740,068
|
|
|
|
270,356
|
|
|
|
234,856
|
|
|
|
234,856
|
|
|
|
|
|
Pension obligations
|
|
|
8,878
|
|
|
|
1,078
|
|
|
|
5,200
|
|
|
|
|
|
|
|
2,600
|
|
Employment agreements (4)
|
|
|
1,038
|
|
|
|
667
|
|
|
|
371
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total obligations
|
|
$
|
1,388,850
|
|
|
$
|
355,985
|
|
|
$
|
355,790
|
|
|
$
|
321,314
|
|
|
$
|
355,761
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
We have various operating leases for the use of land, storage
tanks, pressure stations, railcars, equipment, precious metals
and office facilities that extend through August 2015. |
|
(2) |
|
Letters of credit supporting crude oil purchases, precious
metals leasing and hedging activities. |
|
(3) |
|
Purchase commitments consist of obligations to purchase fixed
volumes of crude oil from various suppliers based on current
market prices at the time of delivery. |
|
(4) |
|
Annual compensation under the employment agreement of F. William
Grube, chief executive officer and president and the
professional services and transition agreement with Allan A.
Moyes III, executive vice president. |
In connection with the closing of the Penreco acquisition on
January 3, 2008, we entered into a feedstock purchase
agreement with ConocoPhillips related to the LVT unit at its
Lake Charles, Louisiana refinery (the LVT Feedstock
Agreement). Pursuant to the LVT Feedstock Agreement,
ConocoPhillips is obligated to supply a minimum quantity (the
Base Volume) of feedstock for the LVT unit for a
term of ten years. Based upon this minimum supply quantity, we
expect to purchase $52.5 million of feedstock for the LVT
unit in each fiscal year of the term based on pricing estimates
as of December 31, 2009. If the Base Volume is not supplied
at any point during the first five years of the ten-year term, a
penalty for each gallon of shortfall must be paid to us as
liquidated damages.
65
Off-Balance
Sheet Arrangements
We have no material off-balance sheet arrangements.
Critical
Accounting Policies and Estimates
Our discussion and analysis of results of operations and
financial condition are based upon our consolidated financial
statements for the years ended December 31, 2009, 2008 and
2007. These consolidated financial statements have been prepared
in accordance with GAAP. The preparation of these financial
statements requires us to make estimates and judgments that
affect the amounts reported in those financial statements. On an
ongoing basis, we evaluate estimates and base our estimates on
historical experience and assumptions believed to be reasonable
under the circumstances. Those estimates form the basis for our
judgments that affect the amounts reported in the financial
statements. Actual results could differ from our estimates under
different assumptions or conditions. Our significant accounting
policies, which may be affected by our estimates and
assumptions, are more fully described in Note 2 to our
consolidated financial statements in Item 8 Financial
Statements and Supplementary Data of this
Form 10-K.
We believe that the following are the more critical judgment
areas in the application of our accounting policies that
currently affect our financial condition and results of
operations.
Revenue
Recognition
We recognize revenue on orders received from our customers when
there is persuasive evidence of an arrangement with the customer
that is supportive of revenue recognition, the customer has made
a fixed commitment to purchase the product for a fixed or
determinable sales price, collection is reasonably assured under
our normal billing and credit terms, and ownership and all risks
of loss have been transferred to the buyer, which is primarily
upon shipment to the customer or, in certain cases, upon receipt
by the customer in accordance with contractual terms.
Inventories
The cost of inventories is determined using the
last-in,
first-out (LIFO) method and valued at the lower of cost or
market. Costs include crude oil and other feedstocks, labor and
refining overhead costs. We review our inventory balances
quarterly for excess inventory levels or obsolete products and
write down, if necessary, the inventory to net realizable value.
The replacement cost of our inventory, based on current market
values, would have been $30.4 million and
$27.5 million higher at December 31, 2009 and 2008,
respectively.
Fair
Value of Financial Instruments
In accordance with Financial Accounting Standards Board
(FASB) Accounting Standards Codification Statement
(ASC)
815-10,
Derivatives and Hedging (formerly Statement of
Financial Accounting Standards (SFAS) No. 161,
Derivative Instruments and Hedging Activities), we
recognize all derivative transactions as either assets or
liabilities at fair value on the consolidated balance sheets. We
utilize third party valuations and published market data to
determine the fair value of these derivatives and thus does not
directly rely on market indices. We perform an independent
verification of the third party valuation statements to validate
inputs for reasonableness and completes a comparison of implied
crack spread
mark-to-market
valuations among our counterparties.
Our derivative instruments, consisting of derivative assets and
derivative liabilities of $30.9 million and
$4.8 million, respectively, as of December 31, 2009,
are valued at Level 1, Level 2, and Level 3 fair
value measurement under ASC
820-10,
Fair Value Measurements and Disclosures (formerly
SFAS No. 157, Fair Value
Measurements), depending upon the degree
by which inputs are observable. We recorded realized and
unrealized gains on derivative instruments of $8.3 million
and $23.7 million, respectively, on our derivative
instruments in 2009. The decrease in the fair market value of
our outstanding derivative instruments from a net asset of
$55.4 million as of December 31, 2008 to a net asset
of $26.1 million as of December 31, 2009 was primarily
due to $22.6 million in settlements of crack spread hedges
outstanding as of December 31, 2008, with only
$1.3 million offsetting this amount for new derivative
instruments. We believe that the fair values of our derivative
66
instruments may diverge materially from the amounts currently
recorded to fair value at settlement due to the volatility of
commodity prices.
Holding all other variables constant, we expect a $1 increase in
the applicable commodity prices would change our recorded
mark-to-market
valuation by the following amounts based upon the volume hedged
as of December 31, 2009:
|
|
|
|
|
|
|
In millions
|
|
Crude oil swaps
|
|
$
|
12.9
|
|
Diesel swaps
|
|
$
|
(7.1
|
)
|
Jet fuel swaps
|
|
$
|
(2.5
|
)
|
Gasoline swaps
|
|
$
|
(3.3
|
)
|
Crude oil collars
|
|
$
|
0.2
|
|
Jet fuel collars
|
|
$
|
|
|
We enter into crude oil, gasoline, and diesel hedges to hedge an
implied crack spread. Therefore, any increase in crude oil swap
mark-to-market
valuation due to changes in commodity prices will generally be
accompanied by a decrease in gasoline and diesel swap
mark-to-market
valuation.
In addition, we measure our investments associated with the
Companys non-contributory defined benefit plan
(Pension Plan) on a recurring basis. The
Companys investments associated with its Pension Plan
consist of mutual funds that are publicly traded and for which
market prices are readily available, thus these investments are
categorized as Level 1.
Recent
Accounting Pronouncements
In December 2007, the FASB issued ASC
805-10,
Business Combinations (formerly
SFAS No. 141(R)).
ASC 805-10
applies to the financial accounting and reporting of business
combinations. ASC
805-10 is
effective for business combination transactions for which the
acquisition date is on or after the beginning of the first
annual reporting period beginning on or after December 15,
2008. The Company will apply the provisions of ASC
805-10 for
all future acquisitions.
In March 2008, the FASB issued ASC
815-10,
Derivatives and Hedging (formerly
SFAS No. 161, Derivative Instruments and Hedging
Activities). ASC
815-10
requires entities that utilize derivative instruments to provide
qualitative disclosures about their objectives and strategies
for using such instruments, as well as any details of
credit-risk-related contingent features contained within
derivatives. ASC
815-10 also
requires entities to disclose additional information about the
amounts and location of derivatives located within the financial
statements, how the provisions of ASC
815-10 have
been applied, and the impact that hedges have on an
entitys financial position, results of operations, and
cash flows. ASC
815-10 is
effective for fiscal years and interim periods beginning after
November 15, 2008. The Company adopted ASC
815-10 as of
January 1, 2009. Because ASC
815-10
applies only to financial statement disclosures, it did not have
any impact on the Companys financial position, results of
operations, or cash flows.
In March 2008, FASB issued requirements under ASC
260-10,
Earnings per Share (formerly EITF Issue
No. 07-4,
Application of the Two-Class Method under FASB Statement
No. 128 to Master Limited Partnerships), requiring
master limited partnerships to treat incentive distribution
rights (IDRs) as participating securities for the
purposes of computing earnings per unit in the period that the
general partner becomes contractually obligated to pay IDRs. ASC
260-10
requires that undistributed earnings be allocated to the
partnership interests based on the allocation of earnings to
capital accounts as specified in the respective partnership
agreement. When distributions exceed earnings, ASC
260-10
requires that net income be reduced by the actual distributions
with the resulting net loss being allocated to capital accounts
as specified in the respective partnership agreement. ASC
260-10 is
effective for fiscal years and interim periods beginning after
December 15, 2008. The Company adopted these requirements
under ASC
260-10 as of
January 1, 2009 and applied it retrospectively.
In June 2008, the FASB issued pronouncements under ASC
260-10,
Earnings per Share (formerly
EITF 03-6-1,
Determining Whether Instruments Granted in Share-Based
Payment Transactions Are Participating
67
Securities). ASC
260-10
clarifies that unvested share-based payment awards with a right
to receive nonforfeitable dividends are participating securities
for the purposes of applying the two-class method of calculating
EPS (earnings per share). ASC
260-10 also
provides guidance on how to allocate earnings to participating
securities and compute basic EPS using the two-class method.
These additional requirements under ASC
260-10 are
effective for financial statements issued for fiscal years
beginning after December 15, 2008. The Company has adopted
these pronouncements as of January 1, 2009 and applied them
retrospectively. The adoption of ASC
260-10 did
not have a material impact on the Companys financial
position, results of operations, or cash flows.
In April 2008, the FASB issued pronouncements under ASC
350-30,
General Intangibles Other Than
Goodwill (formerly FSP
No. 142-3,
Determination of the Useful Life of Intangible Assets).
ASC 350-30
amends the factors considered in developing renewal or extension
assumptions used to determine the useful life of a recognized
intangible asset under ASC 350 (formerly SFAS No. 142,
Goodwill and Other Intangible Assets).
ASC 350-30
requires a consistent approach between the useful life of a
recognized intangible asset under ASC 350 and the period of
expected cash flows used to measure the fair value of an asset
under ASC
805-10. ASC
350-30 also
requires enhanced disclosures when an intangible assets
expected future cash flows are affected by an entitys
intent
and/or
ability to renew or extend the arrangement. ASC
350-30 is
effective for financial statements issued for fiscal years
beginning after December 15, 2008 and is applied
prospectively. The Company has adopted
ASC 350-30
and applied its various provisions as required as of
January 1, 2009. The adoption of ASC
350-30 did
not have a material impact on the Companys financial
position, results of operations, or cash flows.
In December 2008, the FASB issued pronouncements under ASC
715-20,
Compensation-Retirement Benefits-Defined Benefit Plans
(formerly FSP
FAS 132R-1,
Employers Disclosures about Postretirement Benefit Plan
Assets). ASC
715-20
replaces the requirement to disclose the percentage of the fair
value of total plan assets with a requirement to disclose the
fair value of each major asset category. ASC
715-20 also
requires additional disclosure regarding the level of the plan
assets within the fair value hierarchy according to ASC
820-10,
Fair Value Measurements and
Disclosures (formerly SFAS No. 157,
Fair Value Measurements), and a reconciliation of
activity for any plan assets being measured using unobservable
inputs as defined in ASC
715-20. ASC
715-20 is
effective for fiscal years ending after December 15, 2009.
The adoption of ASC
715-20 did
not have a material impact on the Companys financial
position, results of operations, or cash flows.
In May 2009, the FASB issued pronouncements under ASC
855-10,
Subsequent Events (formerly
SFAS No. 165, Subsequent Events). ASC
855-10
provides authoritative accounting literature for a topic that
was previously addressed only in the auditing literature. ASC
855-10
distinguishes events requiring recognition in the financial
statements and those that may require disclosure in the
financial statements. Furthermore, ASC
855-10
requires disclosure of the date through which subsequent events
were evaluated. ASC
855-10 is
effective on a prospective basis for interim or annual financial
periods ending after June 15, 2009. The Company adopted
ASC 855-10
in June 30, 2009, and has evaluated subsequent events
through the date of this filing.
In June 2009, the FASB issued pronouncements under ASC
105-10,
Generally Accepted Accounting
Principles (formerly SFAS No. 168,
The FASB Accounting Standards Codification and the Hierarchy
of Generally Accepted Accounting Principles). ASC
105-10
established the FASB Accounting Standards Codification
(Codification), which supersedes all existing
accounting standards documents and is the single source of
authoritative non-governmental U.S. GAAP. All other
accounting literature not included in the Codification is
considered non-authoritative. The Codification was implemented
on July 1, 2009 and is effective for interim and annual
periods ending after September 15, 2009. The Company
adopted ASC
105-10
beginning with the quarter ended September 30, 2009. The
adoption of ASC
105-10 did
not have any effect on the Companys financial position,
results of operations, or cash flows.
In April 2009, the FASB issued pronouncements under ASC
825-10,
Financial Instruments (formerly
FSP No. FAS 107-1
and APB
28-1,
Interim Disclosures about Fair Value of Financial
Instruments). ASC
825-10
requires disclosures about fair value of financial instruments
for interim reporting periods of publicly traded companies as
well as in annual financial statements. This action also
requires those disclosures in summarized financial information
at interim periods. ASC
825-10 is
effective for reporting periods ending after June 15, 2009
and was adopted by the Company beginning with the quarter ended
June 30, 2009. The adoption of these pronouncements did not
have a material impact on the Companys financial
statements.
68
In January 2010, the FASB issued Accounting Standards Update
No. 2010-06
(ASU
2010-06)
under ASC 820, Fair Value Measurements and
Disclosures (formerly SFAS No. 157,
Fair Value Measurements).
ASU 2010-06
requires reporting entities to make new disclosures about
recurring or nonrecurring fair-value measurements including
significant transfers into and out of Level 1 and
Level 2 fair-value measurements and information on
purchases, sales, issuances, and settlements on a gross basis in
the reconciliation of Level 3 fair-value measurements. ASU
2010-06 also
clarifies existing fair-value measurement disclosure guidance
about the level of disaggregation, inputs, and valuation
techniques. ASU
2010-06 is
effective for reporting periods beginning after
December 15, 2009 and will be adopted by the Company
beginning with the quarter ended March 31, 2010. The
Company expects that the adoption of ASU
2010-06 will
not have a material impact on the Companys financial
position, results of operations, or cash flows.
|
|
Item 7A.
|
Quantitative
and Qualitative Disclosures About Market Risk
|
Commodity
Price Risk
Consistent with prior years, both our profitability and our cash
flows are affected by volatility in prevailing crude oil,
gasoline, diesel, jet fuel, and natural gas prices. The primary
purpose of our commodity risk management activities is to hedge
our exposure to price risks associated with the cost of crude
oil and natural gas and sales prices of our fuel products.
Crude
Oil Price Volatility
We are exposed to significant fluctuations in the price of crude
oil, our principal raw material. Given the historical volatility
of crude oil prices, this exposure can significantly impact
product costs and gross profit. Holding all other variables
constant, and excluding the impact of our current hedges, we
expect a $1.00 change in the per barrel price of crude oil would
change our specialty product segment cost of sales by
$9.4 million and our fuel product segment cost of sales by
$11.5 million based on our sales volumes for 2009.
Crude
Oil Hedging Policy
Because we typically do not set prices for our specialty
products in advance of our crude oil purchases, we can generally
take into account the cost of crude oil in setting specialty
products prices. However, during the prior two years when crude
oil prices ranged from a low of approximately $34 per barrel to
a high of approximately $145 per barrel, we are not always able
to adjust our sales prices as quickly as increases in the price
of crude oil. Due to this lack of correlation between our
specialty products sales prices and crude oil in periods of high
volatility, we further manage our exposure to fluctuations in
crude oil prices in our specialty products segment through the
use of derivative instruments, which can include both swaps and
options, generally executed in the
over-the-counter
(OTC) market. Our policy is generally to enter into crude oil
derivative contracts that match our expected future cash
outflows for up to 70% of our anticipated crude oil purchases
related to our specialty products production. These positions
generally will be short term in nature and expire within three
to nine months from execution; however, we may execute
derivative contracts for up to two years forward if our expected
future cash flows support lengthening our position. Our fuel
products sales are based on market prices at the time of sale.
Accordingly, in conjunction with our fuel products hedging
policy discussed below, we enter into crude oil derivative
contracts related to our fuel products segment for up to five
years and no more than 75% of our fuel products sales on average
for each fiscal year.
Natural
Gas Price Volatility
Since natural gas purchases comprise a significant component of
our cost of sales, changes in the price of natural gas also
significantly affect our profitability and our cash flows.
Holding all other cost and revenue variables constant, and
excluding the impact of our current hedges, we expect a $0.50
change per MMBtu (one million British Thermal Units) in the
price of natural gas would change our cost of sales by
$3.9 million based on our results for the year ended
December 31, 2009.
69
Natural
Gas Hedging Policy
We enter into derivative contracts to manage our exposure to
natural gas prices. Our policy is generally to enter into
natural gas swap contracts during the summer months for up to
approximately 50% of our anticipated natural gas requirements
for the upcoming fall and winter months with time to expiration
not to exceed three years.
Fuel
Products Selling Price Volatility
We are exposed to significant fluctuations in the prices of
gasoline, diesel, and jet fuel. Given the historical volatility
of gasoline, diesel, and jet fuel prices, this exposure can
significantly impact sales and gross profit. Holding all other
variables constant, and excluding the impact of our current
hedges, we expect that a $1 change in the per barrel selling
price of gasoline, diesel, and jet fuel would change our fuel
products segment sales by $11.5 million based on our
results for the year ended December 31, 2009.
Fuel
Products Hedging Policy
In order to manage our exposure to changes in gasoline, diesel,
and jet fuel selling prices, our policy is generally to enter
into derivative contracts to hedge our fuel products sales for a
period no greater than five years forward and for no more than
75% of anticipated fuels sales on average for each fiscal year,
which is consistent with our crude oil purchase hedging policy
for our fuel products segment discussed above. We believe this
policy lessens the volatility of our cash flows. In addition, in
connection with our credit facilities, our lenders require us to
obtain and maintain derivative contracts to hedge our fuel
products margins for a rolling period of 1 to 12 months
forward for at least 60% and no more than 90% of our anticipated
fuels production, and for a rolling 13 to 24 months forward
for at least 50% and no more than 90% of our anticipated fuels
production. As of December 31, 2009, we were over 60%
hedged for both the forward 12 and 24 month periods. We are
currently hedging in calendar year 2012, with no positions
currently in 2013 or 2014.
The unrealized gain or loss on derivatives at a given point in
time is not necessarily indicative of the results realized when
such contracts mature. The decrease in the fair market value of
our outstanding derivative instruments from a net asset of
$55.4 million as of December 31, 2008 to a net asset
of $26.1 million as of December 31, 2009 was primarily
due to increases in the forward market values of fuel products
margins, or cracks spreads, relative to our hedged fuel products
margins and settlement of derivatives in 2009 that resulted in
realized gain. Please read Note 2 Summary of
Significant Accounting Policies Derivatives in the
notes to our consolidated financial statements for a discussion
of the accounting treatment for the various types of derivative
transactions, and a further discussion of our hedging policies.
Interest
Rate Risk
Our profitability and cash flows are affected by changes in
interest rates, specifically LIBOR and prime rates, which is
consistent with prior years. The primary purpose of our interest
rate risk management activities is to hedge our exposure to
changes in interest rates.
We are exposed to market risk from fluctuations in interest
rates. As of December 31, 2009, we had approximately
$411.1 million of variable rate debt. Holding other
variables constant (such as debt levels), a one hundred basis
point change in interest rates on our variable rate debt as of
December 31, 2009 would be expected to have an impact on
net income and cash flows for 2009 of approximately
$4.1 million.
We have a $375.0 million revolving credit facility as of
December 31, 2009, bearing interest at the prime rate or
LIBOR, at our option, plus the applicable margin. We had
borrowings of $39.9 million outstanding under this facility
as of December 31, 2009, bearing interest at the prime rate
or LIBOR, at our option, plus the applicable margin.
Existing
Interest Rate Derivative Instruments
In 2008, the Company entered into a forward swap contract to
manage interest rate risk related to its current variable rate
senior secured first lien term loan which closed January 3,
2008. The Company has hedged the future interest payments
related to $150.0 million and $50.0 million of the
total outstanding term loan indebtedness in
70
2009 and 2010, respectively, pursuant to this forward swap
contract. This swap contract is designated as a cash flow hedge
of the future payment of interest with three-month LIBOR fixed
at 3.09%, and 3.66% per annum in 2009 and 2010, respectively.
In 2009, the Company entered into a forward swap contract to
manage interest rate risk related to its current variable rate
senior secured first lien term loan which closed January 3,
2008. The Company has hedged the future interest payments
related to $200.0 million of the total outstanding term
loan indebtedness from February 15, 2010 to
February 15, 2011. This swap contract is designated as a
cash flow hedge of the future payment of interest with
three-month LIBOR fixed at an average annual rate of 0.94%.
Existing
Commodity Derivative Instruments
Fuel
Products Segment
As a result of our fuel products hedging activity, we recorded a
gain of $74.6 million and a loss of $56.0 million, to
sales and cost of sales, respectively, in the consolidated
statements of operations for 2009.
The following tables provide information about our derivative
instruments related to our fuel products segment as of
December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barrels
|
|
|
|
|
|
|
|
Crude Oil Swap Contracts by Expiration Dates
|
|
Purchased
|
|
|
BPD
|
|
|
($/Bbl)
|
|
|
First Quarter 2010
|
|
|
1,800,000
|
|
|
|
20,000
|
|
|
$
|
67.29
|
|
Second Quarter 2010
|
|
|
1,820,000
|
|
|
|
20,000
|
|
|
|
67.29
|
|
Third Quarter 2010
|
|
|
1,840,000
|
|
|
|
20,000
|
|
|
|
67.29
|
|
Fourth Quarter 2010
|
|
|
1,840,000
|
|
|
|
20,000
|
|
|
|
67.29
|
|
Calendar Year 2011
|
|
|
5,614,000
|
|
|
|
15,381
|
|
|
|
76.54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
|
12,914,000
|
|
|
|
|
|
|
|
|
|
Average price
|
|
|
|
|
|
|
|
|
|
$
|
71.31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diesel Swap Contracts by Expiration Dates
|
|
Barrels Sold
|
|
|
BPD
|
|
|
($/Bbl)
|
|
|
First Quarter 2010
|
|
|
1,170,000
|
|
|
|
13,000
|
|
|
$
|
80.41
|
|
Second Quarter 2010
|
|
|
1,183,000
|
|
|
|
13,000
|
|
|
|
80.41
|
|
Third Quarter 2010
|
|
|
1,196,000
|
|
|
|
13,000
|
|
|
|
80.41
|
|
Fourth Quarter 2010
|
|
|
1,196,000
|
|
|
|
13,000
|
|
|
|
80.41
|
|
Calendar Year 2011
|
|
|
2,371,000
|
|
|
|
6,496
|
|
|
|
90.58
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
|
7,116,000
|
|
|
|
|
|
|
|
|
|
Average price
|
|
|
|
|
|
|
|
|
|
$
|
83.80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jet Fuel Swap Contracts by Expiration Dates
|
|
Barrels Sold
|
|
|
BPD
|
|
|
($/Bbl)
|
|
|
Calendar Year 2011
|
|
|
2,514,000
|
|
|
|
6,888
|
|
|
$
|
88.51
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
|
2,514,000
|
|
|
|
|
|
|
|
|
|
Average price
|
|
|
|
|
|
|
|
|
|
$
|
88.51
|
|
71
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline Swap Contracts by Expiration Dates
|
|
Barrels Sold
|
|
|
BPD
|
|
|
($/Bbl)
|
|
|
First Quarter 2010
|
|
|
630,000
|
|
|
|
7,000
|
|
|
$
|
75.28
|
|
Second Quarter 2010
|
|
|
637,000
|
|
|
|
7,000
|
|
|
|
75.28
|
|
Third Quarter 2010
|
|
|
644,000
|
|
|
|
7,000
|
|
|
|
75.28
|
|
Fourth Quarter 2010
|
|
|
644,000
|
|
|
|
7,000
|
|
|
|
75.28
|
|
Calendar Year 2011
|
|
|
729,000
|
|
|
|
1,997
|
|
|
|
83.53
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
|
3,284,000
|
|
|
|
|
|
|
|
|
|
Average price
|
|
|
|
|
|
|
|
|
|
$
|
77.11
|
|
The following table provides a summary of these derivatives and
implied crack spreads for the crude oil, diesel and gasoline
swaps disclosed above, all of which are designated as hedges.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barrels
|
|
|
|
|
|
Implied Crack
|
|
Swap Contracts by Expiration Dates
|
|
Purchased
|
|
|
BPD
|
|
|
Spread ($/Bbl)
|
|
|
First Quarter 2010
|
|
|
1,800,000
|
|
|
|
20,000
|
|
|
$
|
11.32
|
|
Second Quarter 2010
|
|
|
1,820,000
|
|
|
|
20,000
|
|
|
|
11.32
|
|
Third Quarter 2010
|
|
|
1,840,000
|
|
|
|
20,000
|
|
|
|
11.32
|
|
Fourth Quarter 2010
|
|
|
1,840,000
|
|
|
|
20,000
|
|
|
|
11.32
|
|
Calendar Year 2011
|
|
|
5,614,000
|
|
|
|
15,381
|
|
|
|
12.16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
|
12,914,000
|
|
|
|
|
|
|
|
|
|
Average price
|
|
|
|
|
|
|
|
|
|
$
|
11.68
|
|
At December 31, 2009, the Company had the following
derivatives related to crude oil sales in its fuel products
segment, none of which are designated as hedges. As a result of
these derivatives not being designated as hedges, the Company
recognized $13.1 million of gains in unrealized gain (loss)
on derivative instruments in the consolidated statements of
operations in 2009. Refer to the gasoline swap contracts table
below with corresponding barrel per day amounts for the related
transactions.
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Swap Contracts by Expiration Dates
|
|
Barrels Sold
|
|
|
BPD
|
|
|
($/Bbl)
|
|
|
First Quarter 2010
|
|
|
135,000
|
|
|
|
1,500
|
|
|
$
|
58.25
|
|
Second Quarter 2010
|
|
|
136,500
|
|
|
|
1,500
|
|
|
|
58.25
|
|
Third Quarter 2010
|
|
|
138,000
|
|
|
|
1,500
|
|
|
|
58.25
|
|
Fourth Quarter 2010
|
|
|
138,000
|
|
|
|
1,500
|
|
|
|
58.25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
|
547,500
|
|
|
|
|
|
|
|
|
|
Average price
|
|
|
|
|
|
|
|
|
|
$
|
58.25
|
|
At December 31, 2009, the Company had the following
derivatives related to gasoline purchases in its fuel products
segment, none of which are designated as hedges. As a result of
these derivatives not being designated as hedges, the Company
recognized $16.2 million of losses in unrealized gain
(loss) on derivative instruments in the consolidated statements
of operations in 2009. Refer to the crude oil swap contracts
table above with corresponding barrel per day amounts for the
related transactions.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barrels
|
|
|
|
|
|
|
|
Gasoline Swap Contracts by Expiration Dates
|
|
Purchased
|
|
|
BPD
|
|
|
($/Bbl)
|
|
|
First Quarter 2010
|
|
|
135,000
|
|
|
|
1,500
|
|
|
$
|
58.42
|
|
Second Quarter 2010
|
|
|
136,500
|
|
|
|
1,500
|
|
|
|
58.42
|
|
Third Quarter 2010
|
|
|
138,000
|
|
|
|
1,500
|
|
|
|
58.42
|
|
Fourth Quarter 2010
|
|
|
138,000
|
|
|
|
1,500
|
|
|
|
58.42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
|
547,500
|
|
|
|
|
|
|
|
|
|
Average price
|
|
|
|
|
|
|
|
|
|
$
|
58.42
|
|
72
To summarize at December 31, 2009, the Company had the
following crude oil and gasoline derivative instruments not
designated as hedges in its fuel products segment. These trades
were used to economically freeze a portion of the
mark-to-market
valuation gain for the above crack spread trades.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barrels
|
|
|
|
|
|
Implied Crack
|
|
Swap Contracts by Expiration Dates
|
|
Purchased
|
|
|
BPD
|
|
|
Spread ($/Bbl)
|
|
|
First Quarter 2010
|
|
|
135,000
|
|
|
|
1,500
|
|
|
$
|
0.17
|
|
Second Quarter 2010
|
|
|
136,500
|
|
|
|
1,500
|
|
|
|
0.17
|
|
Third Quarter 2010
|
|
|
138,000
|
|
|
|
1,500
|
|
|
|
0.17
|
|
Fourth Quarter 2010
|
|
|
138,000
|
|
|
|
1,500
|
|
|
|
0.17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
|
547,500
|
|
|
|
|
|
|
|
|
|
Average price
|
|
|
|
|
|
|
|
|
|
$
|
0.17
|
|
The above derivative instruments to purchase the crack spread
have effectively locked in a gain of $6.52 per barrel on
approximately 0.5 million barrels, or $3.6 million, to
be recognized in 2010.
Jet
Fuel Put Spread Contracts
At December 31, 2009, the Company had the following jet
fuel put options related to jet fuel crack spreads in its fuel
products segment, none of which are designated as hedges.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Average
|
|
|
|
|
|
|
|
|
|
Sold Put
|
|
|
Bought Put
|
|
Jet Fuel Put Option Crack Spread Contracts by Expiration
Dates
|
|
Barrels
|
|
|
BPD
|
|
|
($/Bbl)
|
|
|
($/Bbl)
|
|
|
Calendar Year 2011
|
|
|
814,000
|
|
|
|
2,230
|
|
|
$
|
4.17
|
|
|
$
|
6.23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
|
814,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average price
|
|
|
|
|
|
|
|
|
|
$
|
4.17
|
|
|
$
|
6.23
|
|
Specialty
Products Segment
As a result of our specialty products crude oil hedging
activity, we recorded a loss of $9.1 million, to realized
loss on derivative instruments in the consolidated statements of
operations for 2009. As of December 31, 2009 and
February 23, 2010, we had not provided any cash margin in
credit support to any of our hedging counterparties. At
December 31, 2009, the Company had the following three-way
crude oil collar derivatives related to crude oil purchases in
its specialty products segment, none of which are designated as
hedges. As a result of these derivatives not being designated as
hedges, the Company recognized $12.2 million of gain in
unrealized gain (loss) on derivative instruments in the
consolidated statements of operations in 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Average
|
|
|
Average
|
|
|
|
|
|
|
|
|
|
Bought Put
|
|
|
Swap
|
|
|
Sold Call
|
|
Crude Oil Put/Swap/Call Contracts by Expiration Dates
|
|
Barrels
|
|
|
BPD
|
|
|
($/Bbl)
|
|
|
($/Bbl)
|
|
|
($/Bbl)
|
|
|
January 2010
|
|
|
186,000
|
|
|
|
6,000
|
|
|
$
|
68.32
|
|
|
$
|
80.43
|
|
|
$
|
90.43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
|
186,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average price
|
|
|
|
|
|
|
|
|
|
$
|
68.32
|
|
|
$
|
80.43
|
|
|
$
|
90.43
|
|
73
|
|
Item 8.
|
Financial
Statements and Supplementary Data
|
Report of
Independent Registered Public Accounting Firm
The Board of Directors of Calumet GP, LLC
General Partner of Calumet Specialty Products Partners, L.P.
We have audited the accompanying consolidated balance sheets of
Calumet Specialty Products Partners, L.P. as of
December 31, 2009 and 2008, and the related consolidated
statements of operations, partners capital, and cash flows
for each of the three years in the period ended
December 31, 2009. These financial statements are the
responsibility of the Companys management. Our
responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the consolidated
financial position of Calumet Specialty Products Partners, L.P.
at December 31, 2009 and 2008, and the consolidated results
of its operations and its cash flows for each of the three years
in the period ended December 31, 2009, in conformity with
U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States),
Calumet Specialty Products Partners L.P.s internal control
over financial reporting as of December 31, 2009, based on
criteria established in Internal Control-Integrated Framework
issued by the Committee of Sponsoring Organizations of the
Treadway Commission and our report dated February 25, 2010
expressed an unqualified opinion thereon.
Indianapolis, Indiana
February 25, 2010
74
CALUMET
SPECIALTY PRODUCTS PARTNERS, L.P.
CONSOLIDATED
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
49
|
|
|
$
|
48
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Trade, less allowance for doubtful accounts of $801 and $2,121,
respectively
|
|
|
116,914
|
|
|
|
103,962
|
|
Other
|
|
|
5,854
|
|
|
|
5,594
|
|
|
|
|
|
|
|
|
|
|
|
|
|
122,768
|
|
|
|
109,556
|
|
|
|
|
|
|
|
|
|
|
Inventories
|
|
|
137,250
|
|
|
|
118,524
|
|
Derivative assets
|
|
|
30,904
|
|
|
|
71,199
|
|
Prepaid expenses and other current assets
|
|
|
1,811
|
|
|
|
1,803
|
|
Deposits
|
|
|
6,861
|
|
|
|
4,021
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
299,643
|
|
|
|
305,151
|
|
Property, plant and equipment, net
|
|
|
629,275
|
|
|
|
659,684
|
|
Goodwill
|
|
|
48,335
|
|
|
|
48,335
|
|
Other intangible assets, net
|
|
|
38,093
|
|
|
|
49,502
|
|
Other noncurrent assets, net
|
|
|
16,510
|
|
|
|
18,390
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,031,856
|
|
|
$
|
1,081,062
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS CAPITAL
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
92,110
|
|
|
$
|
87,460
|
|
Accounts payable related party
|
|
|
17,866
|
|
|
|
6,395
|
|
Accrued salaries, wages and benefits
|
|
|
6,500
|
|
|
|
6,865
|
|
Taxes payable
|
|
|
7,551
|
|
|
|
6,833
|
|
Other current liabilities
|
|
|
6,114
|
|
|
|
9,662
|
|
Current portion of long-term debt
|
|
|
5,009
|
|
|
|
4,811
|
|
Derivative liabilities
|
|
|
4,766
|
|
|
|
15,827
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
139,916
|
|
|
|
137,853
|
|
Pension and postretirement benefit obligations
|
|
|
9,433
|
|
|
|
9,717
|
|
Other long-term liabilities
|
|
|
1,111
|
|
|
|
|
|
Long-term debt, less current portion
|
|
|
396,049
|
|
|
|
460,280
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
546,509
|
|
|
|
607,850
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
Partners capital:
|
|
|
|
|
|
|
|
|
Common unitholders (22,166,000 units and
19,166,000 units, issued and outstanding at
December 31, 2009 and 2008, respectively)
|
|
|
418,902
|
|
|
|
363,935
|
|
Subordinated unitholders (13,066,000 units, issued and
outstanding)
|
|
|
34,714
|
|
|
|
35,778
|
|
General partners interest
|
|
|
19,087
|
|
|
|
17,933
|
|
Accumulated other comprehensive income
|
|
|
12,644
|
|
|
|
55,566
|
|
|
|
|
|
|
|
|
|
|
Total partners capital
|
|
|
485,347
|
|
|
|
473,212
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners capital
|
|
$
|
1,031,856
|
|
|
$
|
1,081,062
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
75
CALUMET
SPECIALTY PRODUCTS PARTNERS, L.P.
CONSOLIDATED
STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands, except per unit data)
|
|
|
Sales
|
|
$
|
1,846,600
|
|
|
$
|
2,488,994
|
|
|
$
|
1,637,848
|
|
Cost of sales
|
|
|
1,673,498
|
|
|
|
2,235,111
|
|
|
|
1,456,492
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
173,102
|
|
|
|
253,883
|
|
|
|
181,356
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Selling, general and administrative
|
|
|
32,570
|
|
|
|
34,267
|
|
|
|
19,614
|
|
Transportation
|
|
|
67,967
|
|
|
|
84,702
|
|
|
|
54,026
|
|
Taxes other than income taxes
|
|
|
3,839
|
|
|
|
4,598
|
|
|
|
3,662
|
|
Other
|
|
|
1,366
|
|
|
|
1,576
|
|
|
|
2,854
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
67,360
|
|
|
|
128,740
|
|
|
|
101,200
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(33,573
|
)
|
|
|
(33,938
|
)
|
|
|
(4,717
|
)
|
Interest income
|
|
|
170
|
|
|
|
388
|
|
|
|
1,944
|
|
Debt extinguishment costs
|
|
|
|
|
|
|
(898
|
)
|
|
|
(352
|
)
|
Realized gain (loss) on derivative instruments
|
|
|
8,342
|
|
|
|
(58,833
|
)
|
|
|
(12,484
|
)
|
Unrealized gain (loss) on derivative instruments
|
|
|
23,736
|
|
|
|
3,454
|
|
|
|
(1,297
|
)
|
Gain on sale of mineral rights
|
|
|
|
|
|
|
5,770
|
|
|
|
|
|
Other
|
|
|
(4,099
|
)
|
|
|
11
|
|
|
|
(919
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expense
|
|
|
(5,424
|
)
|
|
|
(84,046
|
)
|
|
|
(17,825
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income before income taxes
|
|
|
61,936
|
|
|
|
44,694
|
|
|
|
83,375
|
|
Income tax expense
|
|
|
151
|
|
|
|
257
|
|
|
|
501
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
61,785
|
|
|
$
|
44,437
|
|
|
$
|
82,874
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocation of net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
61,785
|
|
|
$
|
44,437
|
|
|
$
|
82,874
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
General partners interest in net income
|
|
|
1,236
|
|
|
|
889
|
|
|
|
1,657
|
|
Holders of incentive distribution rights
|
|
|
|
|
|
|
|
|
|
|
3,460
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to limited partners
|
|
|
60,549
|
|
|
|
43,548
|
|
|
|
77,757
|
|
Weighted average limited partner units outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
32,372
|
|
|
|
32,232
|
|
|
|
29,744
|
|
Diluted
|
|
|
32,372
|
|
|
|
32,232
|
|
|
|
29,746
|
|
Common and subordinated unitholders basic and diluted net
income per unit
|
|
$
|
1.87
|
|
|
$
|
1.35
|
|
|
$
|
2.61
|
|
Cash distributions declared per common and subordinated unit
|
|
$
|
1.81
|
|
|
$
|
1.98
|
|
|
$
|
2.43
|
|
See accompanying notes to consolidated financial statements.
76
CALUMET
SPECIALTY PRODUCTS PARTNERS, L.P.
CONSOLIDATED
STATEMENTS OF PARTNERS CAPITAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated Other
|
|
|
Partners Capital
|
|
|
|
|
|
|
Comprehensive
|
|
|
General
|
|
|
Limited Partners
|
|
|
|
|
|
|
Income (Loss)
|
|
|
Partner
|
|
|
Common
|
|
|
Subordinated
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
Balance at January 1, 2007
|
|
$
|
52,251
|
|
|
$
|
15,950
|
|
|
$
|
274,719
|
|
|
$
|
42,347
|
|
|
$
|
385,267
|
|
Comprehensive loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
5,944
|
|
|
|
43,139
|
|
|
|
33,791
|
|
|
|
82,874
|
|
Cash flow hedge gain reclassified to net income
|
|
|
(13,880
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(13,880
|
)
|
Change in fair value of cash flow hedges
|
|
|
(78,012
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(78,012
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|