e10vk
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 year ended
December 31,
2010
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OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
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Commission
File number
000-51734
Calumet Specialty Products
Partners, L.P.
(Exact Name of Registrant as
Specified in Its Charter)
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Delaware
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37-1516132
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(State or Other Jurisdiction
of
Incorporation or Organization)
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(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
(Do not check if a smaller reporting company)
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Smaller reporting company o
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Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the
Act). Yes 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
$283.2 million on June 30, 2010, based on $17.68 per
unit, the closing price of the common units as reported on the
NASDAQ Global Select Market on such date.
On February 18, 2011, there were 35,279,778 common units
outstanding.
DOCUMENTS
INCORPORATED BY REFERENCE
NONE.
CALUMET
SPECIALTY PRODUCTS PARTNERS, L.P.
FORM 10-K
2010 ANNUAL REPORT
Table of Contents
1
FORWARD-LOOKING
STATEMENTS
This Annual Report on
Form 10-K
(this Annual Report) 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) estimated capital
expenditures as a result of the required audits or required
operational changes included in our settlement 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, and (iii) future compliance with our debt
covenants, as well as other matters discussed in this Annual
Report 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 Annual Report. The
risk factors and other factors noted throughout this Annual
Report could cause our actual results to differ materially from
those contained in any forward-looking statement. These factors
include, but are not limited to:
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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, including guidance related to the Dodd-Frank Wall
Street Reform and Consumer Protection Act;
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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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2
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 Annual Report. Please read
Item 1A Risk Factors and Item 7A
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 Annual Report to Calumet Specialty
Products Partners, L.P., 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
Annual Report refer to Calumet Lubricants Co., Limited
Partnership. The results of operations for the year ended
December 31, 2006 for the Company include the results of
operations of the Predecessor for the period of January 1,
2006 through January 31, 2006. References in this Annual
Report to our general partner refer to Calumet GP,
LLC, the general partner of Calumet Specialty Products Partners,
L.P.
3
PART I
Items 1
and 2. Business and Properties
Overview
We are a Delaware limited partnership formed on
September 27, 2005 and are a leading independent producer
of high-quality, specialty hydrocarbon products in North
America. We own plants located in Princeton, Louisiana
(Princeton); Cotton Valley, Louisiana (Cotton
Valley); Shreveport, Louisiana (Shreveport);
Karns City, Pennsylvania (Karns City) and Dickinson,
Texas (Dickinson) and a terminal located in Burnham,
Illinois (Burnham). 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. We also
have contractual arrangements with LyondellBasell and other
third parties which provide us additional volumes of finished
products for our specialty products segment. 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. For the year ended December 31, 2010,
approximately 64.3% of our sales and 94.3% of our gross profit
were generated from our specialty products segment and
approximately 35.7% of our sales and 5.7% of our gross profit
were generated from our fuel products segment.
Our
Assets
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, automotive products and
drilling fluids. 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.
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Karns City Facility. Our Karns City facility,
located in western Pennsylvania and acquired in 2008, 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 2008, 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 (the
LyondellBasell Agreements) with Houston Refining LP,
a wholly-owned subsidiary of LyondellBasell (Houston
Refining), to form a long-term specialty products
affiliation. The initial term of the LyondellBasell Agreements
expires on October 31, 2014 after which it is automatically
extended for additional one-year terms until either party
terminates with 24 months notice. Under the terms of the
LyondellBasell Agreements, (i) we are required to purchase
at least a minimum volume of 3,100 bpd of naphthenic
lubricating oils produced at Houston Refinings Houston,
Texas refinery, and we have a right of first refusal to purchase
any additional naphthenic lubricating oils produced at the
refinery, and (ii) Houston Refining is required to process
a minimum of approximately 800 bpd of white mineral oil for
us at its Houston, Texas refinery, which supplements the white
mineral oil production at our
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Karns City and Dickinson facilities. LyondellBasell has also
granted us rights to use certain registered trademarks and
tradenames, including Tufflo, Duoprime, Duotreat, Crystex, Ideal
and Aquamarine.
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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 products in the Upper Midwest and East Coast
regions of the United States and in Canada. In addition, we
lease approximately 1,850 railcars used 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 64.3% of our sales and 94.3% of our
gross profit for 2010 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 35.7% of our sales and 5.7% of our gross
profit in 2010, we seek to mitigate our exposure to fuel
products margin volatility by maintaining a longer-term fuel
products hedging program. In 2010, we realized
$11.0 million of gains from this program. 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 their efforts to expand their product offerings as
well as marketing specialty product formulations to new
customers. By striving to maintain our long-term relationships
with our broad base of existing customers and by adding new
customers, we seek to limit our dependence on any one portion of
our customer base.
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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
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. In 2009 and 2010, we focused on
optimizing current operations through energy savings
initiatives, product quality enhancements, and product yield
improvements. We intend to continue this approach with our
existing assets in 2011.
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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
consider strategic acquisitions of assets or 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
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extent we perceive similar opportunities. For example, effective
November 4, 2009, we entered into sales and processing
agreements with Houston Refining related to naphthenic
lubricating and white mineral oils.
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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 in 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 active accounts and we are continually seeking new
customers. No single specialty products customer accounted for
more than 10% of our consolidated sales in each of the three
years ended December 31, 2010, 2009 and 2008.
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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 low sulfur fuel
regulations. For example, our Shreveport and Cotton Valley
refineries have the capability to make ultra low sulfur diesel
and all of the Shreveport refinerys gasoline production
meets federally mandated low sulfur standards and newly
implemented Mobile Source Air Toxic Rule II standards
(MSAT II standards) set by the
U.S. Environmental Protection Agency (EPA)
requiring the reduction of benzene levels in gasoline and
effective January 1, 2011. 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.
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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 approximately
25 years of industry experience. Our teams extensive
experience and contacts 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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Partnership
Structure and Management
Calumet Specialty Products Partners, L.P. is a Delaware limited
partnership formed on September 27, 2005. The general
partner of the Company is Calumet GP, LLC, a Delaware limited
liability company. As of February 18, 2011, the Company had
35,279,778 common units and 719,995 general partner units
outstanding. The general partner owns 2% of the Company. Our
general partner has sole responsibility for conducting our
business and managing our operations. For more information about
our general partners board of directors, executive
officers and other management, please read Item 10
Directors, Executive Officers of Our General Partner and
Corporate Governance.
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, and 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.
6
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
volumes under the LyondellBasell Agreements in 2008 and for the
majority of 2009, as such agreements were not deemed effective
until November 4, 2009.
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Year Ended December 31,
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2010
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2009
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2008
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(In bpd)
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Total sales volume (1)
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55,668
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57,086
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56,232
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Total feedstock runs (2)
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55,957
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60,081
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56,243
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Facility production:
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Specialty products:
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Lubricating oils
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13,697
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11,681
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12,462
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Solvents
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9,347
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7,749
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8,130
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Waxes
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1,220
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1,049
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1,736
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Fuels
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1,050
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853
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1,208
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Asphalt and other by-products
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6,907
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7,574
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6,623
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Total
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32,221
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28,906
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30,159
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Fuel products:
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Gasoline
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8,754
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9,892
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8,476
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Diesel
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10,800
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12,796
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10,407
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Jet fuel
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5,004
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6,709
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5,918
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By-products
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535
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489
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370
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Total
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25,093
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29,886
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25,171
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Total facility production (3)
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57,314
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58,792
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55,330
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(1) |
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Total sales volume includes sales from the production at our
facilities and certain third-party facilities pursuant to supply
and/or processing agreements, and sales of inventories. |
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Total feedstock runs represent the barrels per day of crude oil
and other feedstocks processed at our facilities and at certain
third-party facilities pursuant to supply and/or processing
agreements. The decrease in feedstock runs in 2010 compared to
2009 is due primarily to our decision to reduce crude oil run
rates at our Shreveport refinery during the entire first quarter
of 2010 because of the poor economics of running additional
barrels, the failure of an environmental operating unit during
the first quarter of 2010 and scheduled turnarounds completed in
the second and fourth quarters related to various operating
units at our Shreveport refinery. These decreases were partially
offset by higher year-long throughput rates at our Cotton Valley
refinery and the addition of volumes under the LyondellBasell
Agreements. |
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The increase in feedstock runs in 2009 compared to 2008 is due
primarily to the Shreveport refinery expansion project placed in
service in May 2008, resulting in a full year of increased
production in 2009 compared to 2008, and the addition of volumes
under the LyondellBasell Agreements in 2009. Partially
offsetting these increases were lower overall feedstock runs at
our other facilities in 2009 compared to 2008 due to general
economic conditions. |
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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 at certain
third-party facilities pursuant to supply and/or processing
agreements, including the LyondellBasell Agreements. The
difference between total facility 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. |
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The increase in the production of specialty products in 2010
compared to 2009 is primarily the result of the addition of
volumes under the LyondellBasell Agreements and higher
throughput rates at our Cotton Valley refinery. |
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The reduction in production of fuel products in 2010 compared to
2009 is due primarily to reduced feedstock runs at our
Shreveport refinery as discussed in footnote 2 of this table. |
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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.
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|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Sales of specialty products:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lubricating oils
|
|
$
|
759,701
|
|
|
$
|
500,938
|
|
|
$
|
841,225
|
|
Solvents
|
|
|
396,894
|
|
|
|
260,185
|
|
|
|
419,831
|
|
Waxes
|
|
|
124,964
|
|
|
|
97,658
|
|
|
|
142,525
|
|
Fuels
|
|
|
5,507
|
|
|
|
8,951
|
|
|
|
30,389
|
|
Asphalt and other by-products
|
|
|
121,806
|
|
|
|
103,488
|
|
|
|
144,065
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,408,872
|
|
|
|
971,220
|
|
|
|
1,578,035
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of fuel products:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline
|
|
|
304,544
|
|
|
|
317,435
|
|
|
|
332,669
|
|
Diesel
|
|
|
330,756
|
|
|
|
372,359
|
|
|
|
379,739
|
|
Jet fuel
|
|
|
135,796
|
|
|
|
167,638
|
|
|
|
186,675
|
|
By-products
|
|
|
10,784
|
|
|
|
17,948
|
|
|
|
11,876
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
781,880
|
|
|
|
875,380
|
|
|
|
910,959
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated sales
|
|
$
|
2,190,752
|
|
|
$
|
1,846,600
|
|
|
$
|
2,488,994
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, asphalt and
feedstock for the Shreveport refinery for further processing
into ultra low sulfur diesel. 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,
|
|
|
2010
|
|
2009
|
|
2008
|
|
|
(In bpd)
|
|
Crude oil throughput capacity
|
|
|
10,000
|
|
|
|
10,000
|
|
|
|
10,000
|
|
Total feedstock runs (1)
|
|
|
6,096
|
|
|
|
6,076
|
|
|
|
6,516
|
|
Total refinery production (1)
|
|
|
6,138
|
|
|
|
5,999
|
|
|
|
6,551
|
|
|
|
|
(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. |
8
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. 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, fuel feedstocks and residual fuel oil. The residual
fuel oil is an important feedstock for specialty 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 of
the Cotton Valley refinery 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,
|
|
|
2010
|
|
2009
|
|
2008
|
|
|
(In bpd)
|
|
Crude oil throughput capacity
|
|
|
13,500
|
|
|
|
13,500
|
|
|
|
13,500
|
|
Total feedstock runs (1) (2)
|
|
|
5,510
|
|
|
|
5,466
|
|
|
|
6,175
|
|
Total refinery production (2) (3)
|
|
|
7,229
|
|
|
|
6,455
|
|
|
|
6,757
|
|
|
|
|
(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). The Cotton Valley
refinerys feedstock is primarily low sulfur, paraffinic
crude oil originating from north Louisiana and is purchased from
various marketers and gatherers. In addition, the Cotton Valley
refinery receives interplant feedstocks for solvent production
from the Shreveport refinery. The Cotton Valley refinery ships
finished products by both truck and railcar service.
9
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 3.3 million barrels of storage capacity in
130 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 crude oil throughput
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,
|
|
|
2010
|
|
2009
|
|
2008
|
|
|
(In bpd)
|
|
Crude oil throughput capacity
|
|
|
60,000
|
|
|
|
60,000
|
|
|
|
60,000
|
|
Total feedstock runs (1) (2)
|
|
|
36,409
|
|
|
|
43,639
|
|
|
|
37,096
|
|
Total refinery production (2) (3)
|
|
|
36,395
|
|
|
|
43,467
|
|
|
|
35,566
|
|
|
|
|
(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 decrease in
feedstock runs in 2010 compared to 2009 is due primarily to our
decision to reduce crude oil run rates at our facilities during
the entire first quarter of 2010 because of the poor economics
of running additional barrels, the failure of an environmental
operating unit during the first quarter of 2010 and scheduled
turnarounds completed in the second and fourth quarters related
to various operating units at our Shreveport refinery. The
increase in feedstock runs in 2009 compared to 2008 is due
primarily to the Shreveport refinery expansion project placed in
service in May 2008, resulting in a full year of increased
production in 2009 compared to 2008. |
|
(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 feedstock
supplied to our Cotton Valley refinery and Karns City facility. |
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 completed in
2008.
The Shreveport refinery currently makes jet fuel and ultra low
sulfur diesel and all of its gasoline production currently meets
MSAT II standards.
The Shreveport refinery receives crude oil via tank truck,
railcar and common carrier pipeline systems that are operated by
subsidiaries of Plains and Exxon Mobil Corporation
(ExxonMobil) and are connected to the Shreveport
refinerys 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. Crude oil is also purchased
through Legacy Resources and various other counterparties,
including local producers who deliver crude oil to the
Shreveport refinery via tank truck.
10
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 Shreveport refinery
ships its finished products throughout the country by both truck
and railcar service.
The Shreveport refinery has direct pipeline access to the
Enterprise Products Partners L.P. pipeline (TEPPCO
pipeline), on 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, solvents, petrolatums, gelled
hydrocarbons, cable fillers, and natural petroleum sulfonates.
The Karns City facilitys processing capability includes
hydrotreating, fractionation, acid treating, filtering, blending
and packaging, approximately 817,000 barrels of storage
capacity in 250 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 facilitys processing capability
includes 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,
|
|
|
2010
|
|
2009
|
|
2008
|
|
|
(in bpd)
|
|
Feedstock throughput capacity (1)
|
|
|
6,800
|
|
|
|
6,800
|
|
|
|
6,800
|
|
Total feedstock runs (2)
|
|
|
5,051
|
|
|
|
4,595
|
|
|
|
6,456
|
|
Total production (3)
|
|
|
5,041
|
|
|
|
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. |
LyondellBasell
Agreements
Effective November 4, 2009, we entered into the
LyondellBasell Agreements with Houston Refining to form a
long-term specialty products affiliation. The initial term of
the LyondellBasell Agreements expires on October 31,
11
2014 after which it is automatically extended for additional
one-year terms until either party terminates with 24 months
notice. Under the terms of the LyondellBasell Agreements,
(i) we are required to purchase at least a minimum volume
of 3,100 bpd of naphthenic lubricating oils produced at
Houston Refinings Houston, Texas refinery, and we have a
right of first refusal to purchase any additional naphthenic
lubricating oils produced at the refinery, and (ii) Houston
Refining is required to process a minimum of approximately
800 bpd of white mineral oil for us at its Houston, Texas
refinery, which supplements the white mineral oil production at
our Karns City and Dickinson facilities. LyondellBasell has also
granted us rights to use certain registered trademarks and
tradenames, including Tufflo, Duoprime, Duotreat, Crystex, Ideal
and Aquamarine.
The following table sets forth the combined historical
information about production under the LyondellBasell Agreements.
|
|
|
|
|
|
|
|
|
|
|
Houston Refining
|
|
|
Year Ended
|
|
|
December 31,
|
|
|
2010
|
|
2009
|
|
|
(in bpd)
|
|
Feedstock throughput capacity (1)
|
|
|
4,500
|
|
|
|
4,500
|
|
Total production for the Company (2)
|
|
|
2,876
|
|
|
|
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. Total production in both 2010
and 2009 did not meet anticipated levels as Houston
Refinings Houston, Texas refinery experienced downtime due
to various turnarounds and operational issues. |
Burnham
Terminal and Other Logistics Assets
We own and operate a terminal, located on an
11-acre
site, in Burnham, Illinois. The Burnham terminal receives
specialty products from 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 1,850 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.
In 2010, we purchased 58.1% of our crude oil supply through
evergreen crude oil supply contracts, which are typically
terminable on 30 days notice by either party, and
0.4% of our crude oil supply on the spot market. Legacy
Resources supplied us with the remaining 41.5% of our crude oil
in 2010. Refer to Item 13 Certain Relationships and
Related Transactions and Director Independence Crude
Oil Purchases for further information on our
12
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 one to seven 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, as well as a variety of
fuel products. Our customers purchase these products primarily
as raw material components for basic industrial, consumer and
automotive goods. The following table depicts the diversity of
end-use applications for the products we produce:
Representative
Sample of End Use Applications by
Product1
|
|
|
|
|
|
|
|
|
Lubricating Oils
|
|
Solvents
|
|
Waxes
|
|
Asphalt & Other
|
|
Fuels & Fuel Related
|
24%
|
|
16%
|
|
2%
|
|
12%
|
|
46%
|
|
Hydraulic Oils
Passenger car motor oils
Railroad engine oils
Cutting oils
Compressor oils
Rubber process oils
Industrial lubricants
Gear oils
Grease
Automatic transmission fluid
Animal feed dedusting
Baby oils
Bakery pan oils
Catalyst carriers
Gelatin capsule lubricants
Sunscreen
|
|
Waterless hand cleaners
Alkyd resin diluents
Automotive products
Calibration fluids
Camping fuel
Charcoal lighter fluids
Chemical processing
Drilling fluids
Printing inks
|
|
Paraffin waxes
FDA compliant products
Candles
Adhesives
Crayons
Floor care
PVC
Paint strippers
Skin & hair care
Timber treatment
Waterproofing
Pharmaceuticals
Cosmetics
|
|
Roofing
Paving
|
|
Gasoline
Diesel
Jet fuel
Fluid catalytic cracking feedstock
Asphalt vacuum residuals
Mixed butanes
|
|
|
|
(1) |
|
Based on the percentage of actual total production for the year
ended December 31, 2010. We do not produce any of these
end-use products. |
13
We have an experienced marketing department with an average
industry tenure of approximately 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 metalworking fluids, belts, hoses,
sealing systems, batteries, hot melt adhesives, pressure
sensitive tapes, electrical transformers, refrigeration
compressors and drilling fluids;
|
|
|
|
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 2010, about 33.5% of our
specialty products were shipped in our fleet of approximately
1,850 leased railcars, about 63.0% of our specialty products
shipped in trucks owned and operated by several different
third-party carriers and the remaining 3.5% were shipped via
water transportation. For shipments outside of North America,
which accounted for less than 10% of our consolidated sales in
2010, we ship railcars and trucks to several ports where the
product is loaded on vessels for shipment to customers.
Fuel Products. We produce a variety of fuel
and fuel-related products at our Shreveport refinery.
Fuel products produced at the Shreveport refinery can be sold
locally or through the TEPPCO pipeline. Local sales are made
from the TEPPCO terminal in Bossier City, Louisiana, which is
located 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 2010, we sold gasoline, diesel and jet fuel 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 region.
The Shreveport refinery 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 occasionally
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 2011 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 refiners. 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.
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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, 2010, 2009 and 2008.
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 region
through the TEPPCO pipeline should the need arise. During the
year ended December 31, 2008, one of our customers, Murphy
Oil U.S.A., 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, 2010,
2009 and 2008.
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 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 primary competitors in
producing fuel 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.
15
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) initiated enforcement
actions in prior years 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. As further discussed
below, on December 23, 2010, the Company entered into a
settlement agreement with the LDEQ that consolidated the terms
of its settlement of the aforementioned alleged violations with
the Companys agreement to voluntarily participate in the
LDEQs Small Refinery and Single Site Refinery
Initiative.
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. 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
produced gasoline and produces diesel meeting the ultra low
sulfur standard.
16
Pursuant to the Energy Act of 2005 and 2007, the EPA has issued
Renewable Fuels Standards II (RFS II) that
implement mandates to blend renewable fuels into the petroleum
fuels produced at our refineries. Under the RFS II, the EPA
establishes a volume of renewable fuels that obligated
refineries must blend into their finished petroleum fuels. In
addition, we are required to meet the MSAT II regulations to
reduce the benzene content of motor gasoline produced at our
facilities. We have completed capital projects at our Shreveport
refinery to comply with these fuel quality requirements.
On December 23, 2010, we entered into a settlement
agreement with the LDEQ regarding the Companys voluntary
participation in the LDEQs 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. The agreement requires us to make a
$1.0 million payment to the LDEQ, resulting in an
additional $0.6 million expense recorded during the fourth
quarter of 2010, and complete beneficial environmental programs
and implement emissions reduction projects at our Shreveport,
Cotton Valley and Princeton refineries. We estimate
implementation of these requirements will result in
approximately $11.0 million to $15.0 million of
capital expenditures and expenditures related to additional
personnel and environmental studies. This agreement also fully
settles the aforementioned alleged environmental and permit
violations at our Shreveport, Cotton Valley and Princeton
refineries and stipulates that no further civil penalties over
alleged past violations will be pursued by the LDEQ. The
required investments are expected to include i) nitrogen
oxide and sulfur dioxide emission reductions from heaters and
boilers and New Source Performance Standards applicability of,
and compliance for, sulfur recovery plants and flaring devices,
iii) control of incidents related to acid gas flaring, tail
gas and hydrocarbon flaring, iv) electrical reliability
improvements to reduce flaring, v) flare refurbishment at
the Shreveport refinery, vi) enhance the Benzene Waste
National Emissions Standards for Hazardous Air Pollutants
programs and the Leak Detection and Repair programs at the
Companys three Louisiana refineries, and
vii) Title V audits and targeted audits of certain
regulatory compliance programs. During these negotiations with
the LDEQ, we voluntarily initiated projects for certain of these
requirements prior to our settlement with the LDEQ, and we
currently anticipate completion of these projects over the next
five years. These capital investment requirements will be
incorporated into our annual capital expenditures budget and we
do not expect any additional capital expenditures as a result of
the required audits or required operational changes included in
the settlement to have a material adverse effect on our
financial results or operations. We estimate that the total
additional expenditures above our already planned levels will be
approximately $1.0 million to $3.0 million. For
additional information regarding the impact on our capital
expenditures, please read Item 7 Managements
Discussion and Analysis of Financial Condition and Results of
Operations Liquidity and Capital
Resources Capital Expenditures. Before the
terms of this settlement agreement are deemed final, the terms
remain subject to public comment and the concurrence of the
Louisiana Attorney General until the end of the first quarter of
2011.
Climate
Change
In response to findings that emissions of carbon dioxide,
methane and other greenhouse gases (GHG)
present an endangerment to public health and the environment
because emissions of such gases are contributing to the warming
of the earths atmosphere and other climate changes, the
EPA has adopted regulations under existing provisions of the
federal Clean Air Act that require a reduction in emissions of
GHGs from motor vehicles and thereby triggered construction and
operating permit review for GHG emissions from certain
stationary sources. The EPA has published its final rule to
address the permitting of GHG emissions from stationary sources
under the Prevention of Significant Deterioration
(PSD) and Title V permitting programs, pursuant
to which these permitting programs have been
tailored to apply to certain stationary sources of
GHG emissions in a multi-step process, with the largest sources
first subject to permitting. Facilities required to obtain PSD
permits for their GHG emissions also will be required to meet
best available control technology standards, which
will be established by the states or, in some instances, by the
EPA on a
case-by-case
basis. Moreover, on December 23, 2010, EPA entered a
settlement agreement with environmental groups requiring the
agency to propose by December 15, 2011 GHG New Source
Performance Standards for refineries and to finalize these rules
by November 15, 2012. In addition, the EPA published a
final rule in October 2009 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. These EPA policies and
17
rulemakings could adversely affect our operations and restrict
or delay our ability to obtain air permits for new or modified
facilities.
In addition, from time to time Congress has actively considered
legislation to reduce emissions of GHGs, and almost one-half of
the states have already taken legal measures to reduce emissions
of GHGs, primarily through the planned development of GHG
emission inventories
and/or
regional GHG cap and trade programs. Most of these cap and trade
programs work by requiring either major sources of emissions or
major producers of fuels, such as petroleum refineries, to
acquire and surrender emission allowances, with the number of
allowances available for purchase reduced each year until the
overall GHG emission reduction goal is achieved. These
allowances would be expected to escalate significantly in cost
over time. The adoption of any legislation or regulations that
requires reporting of GHGs or otherwise limits 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 the refined petroleum
products that we produce. Finally, it should be noted that some
scientists have concluded that increasing concentrations of GHGs
in the Earths atmosphere may produce climate changes that
have significant physical effects, such as increased frequency
and severity of storms, floods and other climatic events; if any
such effects were to occur, they could have an adverse effect on
our operations.
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 laws. We believe that
we are in 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. In connection with the remediation of
groundwater impacts at our refinery sites, we incurred
approximately $0.5 million of capital expenditures at the
18
Cotton Valley refinery during 2010 and estimate that we will
incur another $0.8 million of capital expenditures in 2011
at this refinery in connection with ongoing remedial activities.
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 and
similar state laws.
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 mitigate 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 standards. On April 30,
2010, we received 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 event of a
serious injury or fatality, criminal charges.
During 2010, we completed studies 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 incur between $5.0 million and $8.0 million of
capital expenditures in total during 2011, 2012 and 2013 to
address OSHA process safety management compliance issues
identified in these studies. We expect these capital
expenditures will enhance equipment to maintain compliance with
applicable consensus codes and standards.
Beginning in February 2010, OSHA conducted an inspection of the
Shreveport refinerys process safety management program
under OSHAs National Emphasis Program which is targeting
all U.S. refineries for review. On August 19, 2010,
OSHA issued a Citation and Notification of Penalty (the
Citation) to us as a result of this inspection which
included a proposed civil penalty amount of $0.2 million.
We contested the Citation and associated penalty amount and
agreed to a final penalty amount of $0.1 million, which was
paid in January 2011.
19
The Cotton Valley refinerys process safety management
program is currently undergoing inspection under OSHAs
National Emphasis Program.
We 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 Item
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.
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.
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. 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
20
renew our lease of office space 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 18, 2011, our general partner employs
approximately 650 people who provide direct support to the
Companys operations. Of these employees, approximately 360
are covered by collective bargaining agreements. Employees at
the Princeton, Cotton Valley and Dickinson facilities are
covered by separate collective bargaining agreements with the
International Union of Operating Engineers. The Princeton
facilitys collective bargaining agreement expires on
October 31, 2011. The Cotton Valley and Dickinson
facilities collective bargaining agreements will both
expire on March 31, 2013. 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, 2013. The Karns City
facility employees are covered by a collective bargaining
agreement with United Steel Workers that will expire on
January 31, 2012. 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.
Information on our website is not incorporated into this Annual
Report or our other securities filings and is not a part of them.
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
21
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.
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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22
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.
Our senior secured term loan credit agreement and revolving
credit facility 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 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 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.
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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2009
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$
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8.68
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First quarter 2010
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$
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8.89
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Second quarter 2010
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$
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12.20
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Third quarter 2010
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$
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8.60
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Fourth quarter 2010
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$
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9.89
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Calendar year 2010
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$
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9.90
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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.
23
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 segment 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. 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 increased crude oil costs
to our customers. In addition, we are not 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.
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 could adversely
affect our liquidity, financial condition and our ability to
distribute cash to our unitholders.
The borrowing base under our revolving credit facility is
determined 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, 2010, we had $145.5 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 could have a material adverse effect
on our liquidity, financial condition and our ability to
distribute cash to our unitholders.
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
$3.29 and $6.01 per million British thermal unit, or MMBtu, in
2010 and between $2.51 and $6.07 per MMBtu in 2009. 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 21.6% and 20.7% of our total operating
expenses included in cost of sales for the years ended
24
December 31, 2010 and 2009, 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 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
2010 we entered into monthly crude oil collars and swaps to
hedge up to approximately 11,000 bpd of crude oil purchases
related to our specialty products segment, which had average
total daily production for 2010 of approximately
32,000 bpd. As of December 31, 2010, we had
significantly reduced the volume and duration of our crude oil
collars and swap positions and were hedging approximately
1,200 bpd of crude oil purchases through March 31,
2011. 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 obligations 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
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 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. Our forecasted internal
rates of return on such projects are
25
also based on our projections of future market fundamentals,
which are not within our control, including changes in general
economic conditions, available alternative supply and customer
demand. For example, the total cost of the Shreveport refinery
expansion project completed in 2008 was approximately
$375.0 million and was significantly over budget due
primarily to increased construction labor costs. Future
reconfiguration and enhancement projects may not be completed at
the budgeted cost, on schedule, or at all due to the risks
described above which could 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 $378.2 million of outstanding
indebtedness under our credit facilities as of December 31,
2010 and availability for borrowings of $145.5 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.
26
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 2010,
subsidiaries of Plains and Genesis Crude Oil, L.P. supplied us
with approximately 49.6% and 4.6%, respectively, of our total
crude oil supplies under term contracts and evergreen crude oil
supply contracts. In addition, 41.5% of our total crude oil
purchases in 2010 were 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 more 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. For example, our contracts
with Plains are currently
month-to-month
terminable upon 90 days notice. 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,
governmental moratoriums on drilling or production activities or
otherwise, could result in a decline in the volume of crude oil
we refine. Fluctuations in crude oil prices 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 Enterprise Products 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.
27
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 could 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, which may change 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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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, terminal and
related facility operations are subject to stringent and complex
federal, regional, state and local environmental, health and
safety laws and regulations governing worker health and safety
the discharge of materials into the environment and
environmental protection. These laws and regulations impose
numerous obligations that are applicable to our operations,
including the obligation to obtain 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, the expenditure of significant
monies in the application of specific health and safety criteria
addressing worker protection, 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
28
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. On occasion, we
receive notices of violation, enforcement proceedings and
regulatory inquiries from governmental agencies alleging
non-compliance with applicable environmental laws and other
regulations. Please read Items 1 and 2 Business and
Properties Environmental, Health and Safety
Matters for additional information regarding our
communications with the LDEQ and OSHA.
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,
recordkeeping requirements and monitoring of occupational
exposure to regulated substances could reduce our ability to
make distributions to our unitholders if we are subjected to
penalties or significant compliance costs.
Our
business subjects us to the inherent risk of incurring
significant environmental liabilities in the operation of our
refineries, terminal 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 because of air emissions and
water discharges related to our operations, and historical
operations and waste disposal practices of prior owners of our
facilities. We currently own or operate properties that for many
years have been used for industrial activities, including
refining or terminal storage operations, sometimes by third
parties over whom we had no control with respect to their
operations or waste disposal activities. Petroleum hydrocarbons
or wastes have been released on or under 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 legislation or regulations restricting emissions of
greenhouse gases could result in increased operating
costs and a decreased demand for our refining
services.
In December 2009, the EPA published its findings that emissions
of carbon dioxide, methane, and other greenhouse gases, or
GHGs, present an endangerment to public health and
the environment because emissions of such gases are, according
to the EPA, contributing to the warming of the earths
atmosphere and other climate changes. 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. The EPA has adopted two sets of regulations under the
Clean Air Act. The first limits emissions of GHGs from motor
vehicles beginning with the 2012 model year. On June 3,
2010, the EPA published its final rule to address the permitting
of GHG emissions from stationary sources under the Prevention of
Significant Deterioration, or PSD, and Title V
permitting programs. This rule tailors these
permitting programs to apply to certain stationary sources of
GHG emissions in a multi-step process, with the
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largest sources first subject to permitting. It is widely
expected that facilities required to obtain PSD permits for
their GHG emissions also will be required to reduce those
emissions according to best available control
technology standards for GHG that have yet to be
developed. Also, in October 2009, the EPA published a final rule
requiring the reporting of GHG emissions from specified large
GHG emission sources in the United States, including refineries,
on an annual basis, beginning in 2011 for emissions occurring
after January 1, 2010. In addition, both houses of Congress
have actively considered legislation to reduce emissions of
GHGs, and almost one-half of the states have already taken legal
measures to reduce emissions of GHGs, primarily through the
planned development of GHG emission inventories
and/or
regional GHG cap and trade programs. Most of these cap and trade
programs work by requiring either major sources of emissions or
major producers of fuels to acquire and surrender emission
allowances, with the number of allowances available for purchase
reduced each year until the overall GHG emission reduction goal
is achieved. These allowances would be expected to escalate
significantly in cost over time. The adoption of any legislation
or regulations that requires reporting of GHGs or otherwise
limits emissions of GHGs from our equipment and operations could
require us to incur increased operating costs and could
adversely affect demand for the refined petroleum products we
produce.
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 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;
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customer or key employee losses at the acquired
businesses; and
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significant changes in our capitalization and results of
operations.
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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 certain operating hazards, and our
cash from operations could decline if any of our facilities
experiences a major accident, explosion or fire, is damaged by
severe weather or other natural disaster, or otherwise is forced
to curtail its operations or shut down. For example, on
February 5, 2010, our Shreveport refinery experienced an
explosion that caused us to shut down one of this
refinerys environmental operating units until August 2010
when it was replaced with a newly constructed unit, resulting in
modified operations during the
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period, including lower throughput rates at certain times during
this period. These operating 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 significant curtailment or suspension of our related
operations.
Although we maintain insurance policies, including personal and
property damage and 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
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 significant interruption of
operations. Our business interruption insurance will not apply
unless a business interruption exceeds 90 days.
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.
In addition, we are not fully insured against all risks incident
to our business because certain risks are not fully insurable,
coverage is unavailable, or premium costs, in our judgment, do
not justify such expenditures. For example, 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 our 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
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, 2010). Borrowings
under our term loan facility bear interest at a floating rate
(4.29% as of December 31, 2010). 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 primarily 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
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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, 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, Shreveport, Karns City and Dickinson facilities
are employed under collective bargaining agreements that expire
in October 2011, March 2013, April 2013, January 2012 and March
2013, respectively. 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.
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
recent adoption of financial reform legislation by the United
States Congress could have an adverse effect on our ability to
use derivative instruments to hedge risks associated with our
business.
The United States Congress recently adopted comprehensive
financial reform legislation that establishes federal oversight
and regulation of the
over-the-counter
derivatives market and entities, including businesses like ours,
that participate in that market. The new legislation, known as
the Dodd-Frank Wall Street Reform and Consumer Protection Act
(the Act), was signed into law by the President on
July 21, 2010, and requires the Commodities Futures Trading
Commission (the CFTC) and the SEC to promulgate
rules and regulations implementing the new legislation within
360 days from the date of enactment. In its rulemaking
under the Act, the CFTC has proposed regulations to set position
limits for certain futures and option contracts in the major
energy markets and for swaps that are their economic
equivalents. Although certain bona fide hedging transactions or
positions would be exempt from these position limits, it is not
possible at this time to predict what impact these regulations
will have on our hedging program or when the CFTC will finalize
these regulations. The Act may also require us to comply with
margin requirements and with certain clearing and
trade-execution requirements in connection with our derivatives
activities, although the application of those provisions to us
is uncertain at this time. The Act may also require the
counterparties to our derivative instruments to spin off some of
their derivatives activities to a separate entity, which may not
be as creditworthy as the current counterparty. The new
legislation and any new regulations could significantly increase
the cost of derivatives contracts (including through
requirements to post collateral which could adversely affect our
available liquidity), materially alter the terms of derivatives
contracts, reduce the availability of derivatives to protect
against risks we encounter, reduce our ability to monetize
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or restructure our existing derivatives contracts, and increase
our exposure to less creditworthy counterparties. If we reduce
our use of derivatives as a result of the legislation and
regulations, our results of operations may become more volatile
and our cash flows may be less predictable, which could
adversely affect our ability to plan for and fund capital
expenditures. Finally, the legislation was intended, in part, to
reduce the volatility of oil and natural gas prices, which some
legislators attributed to speculative trading in derivatives and
commodity instruments related to oil and natural gas. Our
revenues could therefore be adversely affected if a consequence
of the legislation and regulations is to lower commodity prices.
Any of these consequences could have a material adverse effect
on our business, our financial condition, and our results of
operations.
Risks
Inherent in an Investment in Us
The
families of our chairman, chief executive officer and vice
chairman, The Heritage Group and certain of their affiliates own
a 54.6% 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, chief executive officer and vice
chairman, the Heritage Group, and certain of their affiliates
own a 54.6% limited partner interest in us. In addition, The
Heritage Group and the families of our chairman and chief
executive officer and vice chairman 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;
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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 incentive distribution
rights; 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 incentive
distributions.
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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
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products in the continental United States 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.
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
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outstanding units voting together as a single class is required
to remove the general partner. At February 18, 2011, the
owners of our general partner and certain of their affiliates
own 54.6% of our common units.
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.
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. 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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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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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
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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 18, 2011,
our general partner and its affiliates own approximately 54.6%
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.
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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 Select
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 Global Select Market. 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 Annual Report.
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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 for U.S. federal income tax purposes 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 U.S. federal income tax purposes. A
publicly traded partnership such as us may be treated as a
corporation for U.S. federal income tax purposes unless it
satisfies a qualifying income exception. Based on
our current operations we believe that we are treated as a
partnership rather than a corporation for such purposes;
however, a change in our business could cause us to be treated
as a corporation for U.S. federal income tax purposes.
In addition, a change in current law may cause us to be treated
as a corporation for U.S. federal income tax purposes. For
example, members of Congress have recently considered
substantive changes to the existing U.S. federal income tax
laws that would affect the tax treatment of certain publicly
traded partnerships. Any change to the U.S. federal income
tax laws may or may not be applied retroactively. In addition,
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 or other forms
of taxation. If we were subject to federal income tax as a
corporation or any state was to impose a tax upon us, our cash
available to pay distributions would be reduced. Therefore, our
treatment as a corporation would result in a material reduction
in the anticipated cash flow and after-tax return to our
unitholders, likely causing a substantial reduction in the value
of our common units.
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, then the minimum quarterly distribution amount and
the target distribution amounts will be adjusted to reflect the
impact of that law on us.
37
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 U.S. 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 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, the costs of any contest with the IRS
will be borne indirectly by our unitholders 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 in us for
U.S. federal income tax purposes we will allocate a share
of our taxable income to our unitholders which could be
different in amount than the cash we distribute, and our
unitholders may be required to pay any U.S. federal income
taxes and, in some cases, state and local income taxes on their
share of our taxable income even if they do not receive any cash
distributions from us.
Tax
gain or loss on disposition of common units could be more or
less than expected.
If our 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 shares of our total
net taxable income result in a reduction in 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 our unitholders if they sell their
units at a price greater than their tax basis in those common
units, even if the price they receive is equal to 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 of depreciation deductions. 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-U.S.
persons face unique tax issues from owning our common units that
may result in adverse tax consequences to them.
Investments in our common units by tax-exempt entities,
including employee benefit plans and individual retirement
accounts (known as IRAs), and
non-U.S. persons
raise issues unique to them. For example, virtually all of our
income allocated to organizations 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 imposed at the highest
applicable tax rate, and
non-U.S. persons
will be required to file U.S. federal tax returns and pay
tax on their shares 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.
To maintain the uniformity of the economic and tax
characteristics of our common units, we have adopted certain
depreciation and amortization positions that may not conform to
all aspects of existing Treasury Regulations. These positions
may result in an understatement of deductions and an
overstatement of income to our unitholders. For example, we do
not amortize certain goodwill assets, the value of which has
been attributed to certain of our outstanding units. A
subsequent holder of those units may be entitled to an
amortization deduction attributable to that goodwill under
Internal Revenue Code Section 743(b). But, because we
cannot identify these units once they are traded by the initial
holder, we do not allocate any subsequent holder of a unit any
such amortization deduction. This approach may understate
deductions available to those unitholders who own those units
and may result in those unitholders reporting that they have a
higher tax basis in their units than would be the case if the
IRS strictly applied Treasury Regulations relating to these
depreciation or amortization adjustments.
38
This, in turn, may result in those unitholders reporting less
gain or more loss on a sale of their units than would be the
case if the IRS strictly applied those Treasury Regulations.
The IRS may challenge the manner in which we calculate our
unitholders basis adjustment under Section 743(b). If
so, because the specific unitholders to which this issue relates
cannot be identified, the IRS may assert adjustments to all
unitholders selling units within the period under audit. A
successful IRS challenge to this position or other positions we
may take could adversely affect the amount of taxable income or
loss allocated to our unitholders. It also could affect the gain
from a unitholders sale of common units or result in audit
adjustments to our unitholders tax returns without the
benefit of additional deductions. Consequently, a successful IRS
challenge could have a negative impact on the value of our
common units.
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 customers 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 obligated to pay
corporate income taxes, which reduce the corporations 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 were 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
existing unitholders and unitholders who purchase 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
existing unitholders and unitholders who purchase our units
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. Recently, the
U.S. Treasury Department issued proposed Treasury
Regulations that provide a safe harbor pursuant to which
publicly traded partnerships may use a similar monthly
simplifying convention to allocate tax items. Nonetheless, the
proposed regulations do not specifically authorize the use of
the proration method we have adopted. If the IRS were to
challenge our proration method or new Treasury Regulations were
issued, we may be required to change the allocation of items of
income, gain, loss and deduction among our unitholders.
A
unitholder whose units are loaned to a short seller
to cover a short sale of units may be considered as having
disposed of those units. If so, the unitholder would no longer
be treated for tax purposes as a partner with respect to those
units during the period of the loan and may recognize gain or
loss from the disposition.
If a unitholder loans units to a short seller to
cover a short sale of units, they may be considered as having
disposed of the loaned units, and may 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 such
disposition. During the period of the loan, any of our income,
gain, loss or deduction with respect to those units may not be
reportable by a unitholder and any cash distributions received
as to those units may be fully taxable as ordinary income. To
assure unitholder status as a partner and avoid the risk of gain
recognition from a loan to a short seller unitholders are urged
to modify any applicable brokerage account agreements to
prohibit brokers from borrowing their units.
We
have adopted certain valuation methodologies for U.S. federal
income tax purposes that may result in a shift of income, gain,
loss and deduction between our 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 will 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
39
case, there may be a shift of income, gain, loss and deduction
between certain unitholders and our general partner, which may
be unfavorable to such unitholders. Moreover, under our
valuation methods, subsequent purchasers of common units may
have a greater portion of their Internal Revenue Code
Section 743(b) adjustment allocated to our tangible assets
and a lesser portion allocated to our intangible assets. The IRS
may challenge our valuation methods, or our allocation of the
Section 743(b) adjustment attributable to our tangible and
intangible assets, and allocations of taxable income, gain, loss
and deduction between our general partner and certain of our
unitholders.
A successful IRS challenge to these methods or allocations could
adversely affect the amount of taxable income or loss being
allocated to our unitholders. It also could affect the amount of
taxable 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 constructively terminated as a
partnership for federal income tax purposes if there is a sale
or exchange within a twelve-month period of 50% or more of the
total interests in our capital and profits. 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 calendar 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 calendar year, 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 would not affect
our classification as a partnership for federal income tax
purposes, but instead, we would be treated as a new partnership
for federal income 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. The IRS has recently announced a relief procedure
whereby if a publicly traded partnership that has constructively
terminated requests and the IRS grants special relief, among
other things, the partnership may be permitted to provide only a
single
Schedule K-1
to unitholders for the tax years in which the termination occurs.
Unitholders
may be subject to state, local and
non-U.S.
taxes and return filing requirements.
In addition to federal income taxes, our unitholders will likely
be subject to other taxes, including state and local taxes,
non-U.S. 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 unitholders will
likely be required to file tax returns and pay taxes in some or
all of these jurisdictions. Further, unitholders may be subject
to penalties for failure to comply with those requirements. We
do business in 30 states. The states we operate in, with
the exception of Texas and Florida, currently impose 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 required U.S. federal, state, local
and
non-U.S. tax
returns.
The risks described in this Annual Report are not the only
risks facing the Company. Additional risks and uncertainties not
currently known to us or that we currently deem to be immaterial
also may materially adversely affect our business, financial
condition or future results.
|
|
Item 1B.
|
Unresolved
Staff Comments
|
None.
|
|
Item 3.
|
Legal
Proceedings
|
We are not a party to, and our property is not the subject of,
any pending legal proceedings other than ordinary routine
litigation incidental to our business. 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
40
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,
health and safety. Additionally, the information provided under
Note 6 Commitments and Contingencies in
Part I, Item 8 Financial Statements and
Supplementary Data Notes to Calumet Specialty
Products Partners, L.P. Consolidated Financial Statements
is incorporated herein by reference.
|
|
Item 4.
|
(Removed
and Reserved)
|
PART II
|
|
Item 5.
|
Market
for Registrants Common Equity, Related Unitholder Matters
and Issuer Purchases of Equity Securities
|
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, 2010 and 2009,
identical cash distributions per unit were paid among all
outstanding common and subordinated units.
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|
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|
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|
|
|
|
|
|
|
|
|
|
|
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|
|
Cash Distribution
|
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|
Low
|
|
High
|
|
per Unit (1)
|
|
Year ended December 31, 2009:
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|
|
|
|
|
|
|
|
|
|
|
|
First quarter
|
|
$
|
8.11
|
|
|
$
|
13.50
|
|
|
$
|
0.45
|
|
Second quarter
|
|
$
|
9.45
|
|
|
$
|
16.84
|
|
|
$
|
0.45
|
|
Third quarter
|
|
$
|
13.20
|
|
|
$
|
18.53
|
|
|
$
|
0.45
|
|
Fourth quarter
|
|
$
|
14.75
|
|
|
$
|
19.87
|
|
|
$
|
0.455
|
|
Year ended December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
First quarter
|
|
$
|
17.75
|
|
|
$
|
21.31
|
|
|
$
|
0.455
|
|
Second quarter
|
|
$
|
14.00
|
|
|
$
|
23.93
|
|
|
$
|
0.455
|
|
Third quarter
|
|
$
|
16.20
|
|
|
$
|
19.89
|
|
|
$
|
0.46
|
|
Fourth quarter
|
|
$
|
19.39
|
|
|
$
|
22.23
|
|
|
$
|
0.47
|
|
|
|
|
(1) |
|
We also paid cash distributions to our general partner with
respect to its 2% general partner interest. |
As of February 18, 2011, there were approximately
23 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 greater than
the number of holders of record. As of February 18, 2011,
there were 35,279,778 common units outstanding. The number of
common units outstanding on this date includes 13,066,000 common
units that converted from subordinated units on
February 16, 2011. The last reported sale price of our
common units by NASDAQ on February 18, 2011 was $23.83.
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.
41
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.
|
Intent to Distribute the Minimum Quarterly
Distribution. We distribute to the holders of
common 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 14,
2011, we paid a quarterly cash distribution of $0.47 per unit on
all outstanding units totaling $16.9 million for the
quarter ended December 31, 2010 to all unitholders of
record as of the close of business on February 4, 2011.
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. Our general partner did not
earn incentive distribution rights during the years ended
December 31, 2009 and December 31, 2010.
Conversion of Subordinated Units. In February
2011, we satisfied the last of the earnings and distribution
tests contained in our partnership agreement for the automatic
conversion of all 13,066,000 outstanding subordinated units into
common units on a
one-for-one
basis. The last of these requirements was met upon payment of
the quarterly distribution paid on February 14, 2011. Two
days following this quarterly distribution to unitholders, or
February 16, 2011, all of the outstanding subordinated
units automatically converted to common units.
42
After the subordination period ended on February 16, 2011,
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
|
|
|
|
Total Quarterly
|
|
Interest in
|
|
|
|
Distribution
|
|
Distributions
|
|
|
|
Target Amount
|
|
Unitholders
|
|
|
General Partner
|
|
|
Minimum Quarterly Distribution
|
|
$0.45
|
|
|
98
|
%
|
|
|
2
|
%
|
First Target Distribution
|
|
up to $0.495
|
|
|
98
|
%
|
|
|
2
|
%
|
Second Target Distribution
|
|
above $0.495 up to $0.563
|
|
|
85
|
%
|
|
|
15
|
%
|
Third Target Distribution
|
|
above $0.563 up to $0.675
|
|
|
75
|
%
|
|
|
25
|
%
|
Thereafter
|
|
above $0.675
|
|
|
50
|
%
|
|
|
50
|
%
|
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 Annual Report.
Sales of
Unregistered Securities
None.
Issuer
Purchases of Equity Securities
None.
43
|
|
Item 6.
|
Selected
Financial Data
|
The following table shows selected historical consolidated
financial and operating data of Calumet Specialty Products
Partners, L.P. and its consolidated subsidiaries (the
Company) and includes Calumet Lubricants Co.,
Limited Partnership (Predecessor) for the period of
January 1, 2006 through January 31, 2006. The selected
historical financial data as of and after December 31, 2008
includes the operations acquired as part of the acquisition of
Penreco from their date of acquisition, January 3, 2008.
The following table includes the non-GAAP financial measures
EBITDA, Adjusted EBITDA and Distributable Cash Flow. For a
reconciliation of EBITDA, Adjusted EBITDA and Distributable Cash
Flow to net income and net cash provided by 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 the
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 Annual Report 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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|
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|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands, except unit, per unit and operations data)
|
|
|
Summary of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Sales
|
|
$
|
2,190,752
|
|
|
$
|
1,846,600
|
|
|
$
|
2,488,994
|
|
|
$
|
1,637,848
|
|
|
$
|
1,641,048
|
|
Cost of sales
|
|
|
1,992,003
|
|
|
|
1,673,498
|
|
|
|
2,235,111
|
|
|
|
1,456,492
|
|
|
|
1,436,108
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Gross profit
|
|
|
198,749
|
|
|
|
173,102
|
|
|
|
253,883
|
|
|
|
181,356
|
|
|
|
204,940
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Operating costs and expenses:
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|
|
|
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|
|
|
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|
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|
|
|
|
|
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Selling, general and administrative
|
|
|
35,224
|
|
|
|
32,570
|
|
|
|
34,267
|
|
|
|
19,614
|
|
|
|
20,430
|
|
Transportation
|
|
|
85,471
|
|
|
|
67,967
|
|
|
|
84,702
|
|
|
|
54,026
|
|
|
|
56,922
|
|
Taxes other than income taxes
|
|
|
4,601
|
|
|
|
3,839
|
|
|
|
4,598
|
|
|
|
3,662
|
|
|
|
3,592
|
|
Other
|
|
|
1,963
|
|
|
|
1,366
|
|
|
|
1,576
|
|
|
|
2,854
|
|
|
|
863
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
71,490
|
|
|
|
67,360
|
|
|
|
128,740
|
|
|
|
101,200
|
|
|
|
123,133
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(30,497
|
)
|
|
|
(33,573
|
)
|
|
|
(33,938
|
)
|
|
|
(4,717
|
)
|
|
|
(9,030
|
)
|
Interest income
|
|
|
70
|
|
|
|
170
|
|
|
|
388
|
|
|
|
1,944
|
|
|
|
2,951
|
|
Debt extinguishment costs
|
|
|
|
|
|
|
|
|
|
|
(898
|
)
|
|
|
(352
|
)
|
|
|
(2,967
|
)
|
Realized gain (loss) on derivative instruments
|
|
|
(7,704
|
)
|
|
|
8,342
|
|
|
|
(58,833
|
)
|
|
|
(12,484
|
)
|
|
|
(30,309
|
)
|
Unrealized gain (loss) on derivative instruments
|
|
|
(15,843
|
)
|
|
|
23,736
|
|
|
|
3,454
|
|
|
|
(1,297
|
)
|
|
|
12,264
|
|
Gain on sale of mineral rights
|
|
|
|
|
|
|
|
|
|
|
5,770
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
(217
|
)
|
|
|
(4,099
|
)
|
|
|
11
|
|
|
|
(919
|
)
|
|
|
(274
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expense
|
|
|
(54,191
|
)
|
|
|
(5,424
|
)
|
|
|
(84,046
|
)
|
|
|
(17,825
|
)
|
|
|
(27,365
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
17,299
|
|
|
|
61,936
|
|
|
|
44,694
|
|
|
|
83,375
|
|
|
|
95,768
|
|
Income tax expense
|
|
|
598
|
|
|
|
151
|
|
|
|
257
|
|
|
|
501
|
|
|
|
190
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
16,701
|
|
|
$
|
61,785
|
|
|
$
|
44,437
|
|
|
$
|
82,874
|
|
|
$
|
95,578
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average limited partner units outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
35,334,720
|
|
|
|
32,372,000
|
|
|
|
32,232,000
|
|
|
|
29,744,000
|
|
|
|
27,708,000
|
|
Diluted
|
|
|
35,351,020
|
|
|
|
32,372,000
|
|
|
|
32,232,000
|
|
|
|
29,746,000
|
|
|
|
27,708,000
|
|
Common and subordinated unitholders basic and diluted net
income per unit
|
|
$
|
0.46
|
|
|
$
|
1.87
|
|
|
$
|
1.35
|
|
|
$
|
2.61
|
|
|
$
|
3.19
|
|
Cash distributions declared per common and subordinated unit
|
|
$
|
1.84
|
|
|
$
|
1.81
|
|
|
$
|
1.98
|
|
|
$
|
2.43
|
|
|
$
|
1.30
|
|
44
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands, except unit, per unit and operations data)
|
|
|
Balance Sheet Data (at period end):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
$
|
612,433
|
|
|
$
|
629,275
|
|
|
$
|
659,684
|
|
|
$
|
442,882
|
|
|
$
|
191,732
|
|
Total assets
|
|
|
1,016,672
|
|
|
|
1,031,856
|
|
|
|
1,081,062
|
|
|
|
678,857
|
|
|
|
531,651
|
|
Accounts payable
|
|
|
174,715
|
|
|
|
109,976
|
|
|
|
93,855
|
|
|
|
167,977
|
|
|
|
78,752
|
|
Long-term debt
|
|
|
369,275
|
|
|
|
401,058
|
|
|
|
465,091
|
|
|
|
39,891
|
|
|
|
49,500
|
|
Total partners capital
|
|
|
398,279
|
|
|
|
485,347
|
|
|
|
473,212
|
|
|
|
399,644
|
|
|
|
385,267
|
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flow provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
134,143
|
|
|
$
|
100,854
|
|
|
$
|
130,341
|
|
|
$
|
167,546
|
|
|
$
|
166,768
|
|
Investing activities
|
|
|
(34,759
|
)
|
|
|
(22,714
|
)
|
|
|
(480,461
|
)
|
|
|
(260,875
|
)
|
|
|
(75,803
|
)
|
Financing activities
|
|
|
(99,396
|
)
|
|
|
(78,139
|
)
|
|
|
350,133
|
|
|
|
12,409
|
|
|
|
(22,183
|
)
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA
|
|
$
|
109,044
|
|
|
$
|
157,612
|
|
|
$
|
135,575
|
|
|
$
|
102,719
|
|
|
$
|
119,586
|
|
Adjusted EBITDA
|
|
|
130,369
|
|
|
|
146,017
|
|
|
|
128,075
|
|
|
|
104,272
|
|
|
|
104,458
|
|
Distributable Cash Flow
|
|
|
79,040
|
|
|
|
101,736
|
|
|
|
94,514
|
|
|
|
87,684
|
|
|
|
85,913
|
|
Operating Data (bpd):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total sales volume (1)
|
|
|
55,668
|
|
|
|
57,086
|
|
|
|
56,232
|
|
|
|
47,663
|
|
|
|
50,345
|
|
Total feedstock runs (2)
|
|
|
55,957
|
|
|
|
60,081
|
|
|
|
56,243
|
|
|
|
48,354
|
|
|
|
51,598
|
|
Total facility production (3)
|
|
|
57,314
|
|
|
|
58,792
|
|
|
|
55,330
|
|
|
|
47,736
|
|
|
|
50,213
|
|
|
|
|
(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 certain
third-party facilities pursuant to supply and/or processing
agreements. |
|
(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 certain
third-party facilities pursuant to supply and/or processing
agreements, including the LyondellBasell Agreements. The
difference between total facility 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. |
Non-GAAP Financial
Measures
We include in this Annual Report the non-GAAP financial measures
EBITDA, Adjusted EBITDA and Distributable Cash Flow, and provide
reconciliations of EBITDA, Adjusted EBITDA and Distributable
Cash Flow to net income and net cash provided by operating
activities, our most directly comparable financial performance
and liquidity measures calculated and presented in accordance
with GAAP.
EBITDA, Adjusted EBITDA and Distributable Cash Flow 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 and support our indebtedness;
|
|
|
|
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 and provide metrics to
analyze our ability to pay distributions. We
45
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
for additional details regarding our credit agreements.
We define Distributable Cash Flow as Adjusted EBITDA less
replacement capital expenditures, cash interest paid (excluding
capitalized interest) and income tax expense. Distributable Cash
Flow is used by us and our investors to analyze our ability to
pay distributions.
EBITDA, Adjusted EBITDA and Distributable Cash Flow should not
be considered alternatives to net income, operating income, net
cash provided by operating activities or any other measure of
financial performance presented in accordance with GAAP. In
evaluating our performance as measured by EBITDA, Adjusted
EBITDA and Distributable Cash Flow, management recognizes and
considers the limitations of these measurements. EBITDA,
Adjusted EBITDA and Distributable Cash Flow do not reflect our
obligations for the payment of income taxes, interest expense or
other obligations such as capital expenditures. Accordingly,
EBITDA, Adjusted EBITDA and Distributable Cash Flow are only
three of the measurements that management utilizes. Moreover,
our EBITDA, Adjusted EBITDA and Distributable Cash Flow may not
be comparable to similarly titled measures of another company
because all companies may not calculate EBITDA, Adjusted EBITDA
and Distributable Cash Flow in the same manner. The following
table presents a reconciliation of both net income to EBITDA,
Adjusted EBITDA and Distributable Cash Flow and Distributable
Cash Flow, Adjusted EBITDA and EBITDA to net cash provided by
46
operating activities, our most directly comparable GAAP
financial performance and liquidity measures, for each of the
periods indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Reconciliation of net income to EBITDA, Adjusted EBITDA and
Distributable Cash Flow:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
16,701
|
|
|
$
|
61,785
|
|
|
$
|
44,437
|
|
|
$
|
82,874
|
|
|
$
|
95,578
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense and debt extinguishment costs
|
|
|
30,497
|
|
|
|
33,573
|
|
|
|
34,836
|
|
|
|
5,069
|
|
|
|
11,997
|
|
Depreciation and amortization
|
|
|
61,248
|
|
|
|
62,103
|
|
|
|
56,045
|
|
|
|
14,275
|
|
|
|
11,821
|
|
Income tax expense
|
|
|
598
|
|
|
|
151
|
|
|
|
257
|
|
|
|
501
|
|
|
|
190
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA
|
|
$
|
109,044
|
|
|
$
|
157,612
|
|
|
$
|
135,575
|
|
|
$
|
102,719
|
|
|
$
|
119,586
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized loss (gain) from mark to market accounting for
hedging activities
|
|
$
|
18,833
|
|
|
$
|
(14,458
|
)
|
|
$
|
(11,509
|
)
|
|
$
|
3,487
|
|
|
$
|
(13,145
|
)
|
Prepaid non-recurring expenses and accrued non-recurring
expenses, net of cash outlays
|
|
|
2,492
|
|
|
|
2,863
|
|
|
|
4,009
|
|
|
|
(1,934
|
)
|
|
|
(1,983
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
130,369
|
|
|
$
|
146,017
|
|
|
$
|
128,075
|
|
|
$
|
104,272
|
|
|
$
|
104,458
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA attributable to Predecessor
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,494
|
)
|
Replacement capital expenditures (1)
|
|
|
(24,342
|
)
|
|
|
(13,787
|
)
|
|
|
(6,304
|
)
|
|
|
(12,007
|
)
|
|
|
(5,737
|
)
|
Cash interest expense (2)
|
|
|
(26,389
|
)
|
|
|
(30,343
|
)
|
|
|
(27,000
|
)
|
|
|
(4,080
|
)
|
|
|
(8,124
|
)
|
Income tax expense
|
|
|
(598
|
)
|
|
|
(151
|
)
|
|
|
(257
|
)
|
|
|
(501
|
)
|
|
|
(190
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable Cash Flow
|
|
$
|
79,040
|
|
|
$
|
101,736
|
|
|
$
|
94,514
|
|
|
$
|
87,684
|
|
|
$
|
85,913
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Replacement capital expenditures are defined as those capital
expenditures which do not increase operating capacity or reduce
operating costs. |
|
(2) |
|
Represents cash interest paid by the Company, excluding
capitalized interest. |
47
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Reconciliation of Distributable Cash Flow, Adjusted EBITDA
and EBITDA to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable Cash Flow
|
|
$
|
79,040
|
|
|
$
|
101,736
|
|
|
$
|
94,514
|
|
|
$
|
87,684
|
|
|
$
|
85,913
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA attributable to Predecessor
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,494
|
|
Replacement capital expenditures (1)
|
|
|
24,342
|
|
|
|
13,787
|
|
|
|
6,304
|
|
|
|
12,007
|
|
|
|
5,737
|
|
Cash interest expense (2)
|
|
|
26,389
|
|
|
|
30,343
|
|
|
|
27,000
|
|
|
|
4,080
|
|
|
|
8,124
|
|
Income tax expense
|
|
|
598
|
|
|
|
151
|
|
|
|
257
|
|
|
|
501
|
|
|
|
190
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
130,369
|
|
|
$
|
146,017
|
|
|
$
|
128,075
|
|
|
$
|
104,272
|
|
|
$
|
104,458
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized (gain) loss from mark to market accounting for
hedging activities
|
|
$
|
18,833
|
|
|
$
|
(14,458
|
)
|
|
$
|
(11,509
|
)
|
|
$
|
3,487
|
|
|
$
|
(13,145
|
)
|
Prepaid non-recurring expenses and accrued non-recurring
expenses, net of cash outlays
|
|
|
2,492
|
|
|
|
2,863
|
|
|
|
4,009
|
|
|
|
(1,934
|
)
|
|
|
(1,983
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA
|
|
$
|
109,044
|
|
|
$
|
157,612
|
|
|
$
|
135,575
|
|
|
$
|
102,719
|
|
|
$
|
119,586
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense and debt extinguishment costs, net of
amortization
|
|
|
(26,633
|
)
|
|
|
(29,902
|
)
|
|
|
(31,440
|
)
|
|
|
(4,638
|
)
|
|
|
(11,997
|
)
|
Unrealized (gain) loss on derivative instruments
|
|
|
15,843
|
|
|
|
(23,736
|
)
|
|
|
(3,454
|
)
|
|
|
1,297
|
|
|
|
(12,264
|
)
|
Income taxes
|
|
|
(598
|
)
|
|
|
(151
|
)
|
|
|
(257
|
)
|
|
|
(501
|
)
|
|
|
(190
|
)
|
Provision for doubtful accounts
|
|
|
74
|
|
|
|
(916
|
)
|
|
|
1,448
|
|
|
|
41
|
|
|
|
172
|
|
Non-cash debt extinguishment costs
|
|
|
|
|
|
|
|
|
|
|
898
|
|
|
|
352
|
|
|
|
2,967
|
|
Changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(35,267
|
)
|
|
|
(12,296
|
)
|
|
|
45,042
|
|
|
|
(15,038
|
)
|
|
|
16,031
|
|
Inventory
|
|
|
(9,860
|
)
|
|
|
(18,726
|
)
|
|
|
55,532
|
|
|
|
3,321
|
|
|
|
(2,554
|
)
|
Other current assets
|
|
|
4,669
|
|
|
|
(2,848
|
)
|
|
|
1,834
|
|
|
|
(4,121
|
)
|
|
|
16,183
|
|
Derivative activity
|
|
|
2,990
|
|
|
|
8,531
|
|
|
|
41,757
|
|
|
|
2,121
|
|
|
|
(879
|
)
|
Accounts payable
|
|
|
64,739
|
|
|
|
15,951
|
|
|
|
(103,136
|
)
|
|
|
89,225
|
|
|
|
33,993
|
|
Other liabilities
|
|
|
11,853
|
|
|
|
(905
|
)
|
|
|
(1,284
|
)
|
|
|
(4,150
|
)
|
|
|
657
|
|
Other, including changes in noncurrent assets and liabilities
|
|
|
(2,711
|
)
|
|
|
8,240
|
|
|
|
(12,174
|
)
|
|
|
(3,082
|
)
|
|
|
5,063
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
134,143
|
|
|
$
|
100,854
|
|
|
$
|
130,341
|
|
|
$
|
167,546
|
|
|
$
|
166,768
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Replacement capital expenditures are defined as those capital
expenditures which do not increase operating capacity or reduce
operating costs. |
|
(2) |
|
Represents cash interest paid by the Company, excluding
capitalized interest. |
48
|
|
Item 7.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
|
The historical consolidated financial statements included in
this Annual Report reflect all of the assets, liabilities and
results of operations of the Company. The following discussion
analyzes the financial condition and results of operations of
the Company for the years ended December 31, 2010, 2009,
and 2008. Unitholders should read the following discussion and
analysis of the financial condition and results of operations of
the Company in conjunction with the historical consolidated
financial statements and notes of the Company included elsewhere
in this Annual Report.
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. In 2010, approximately 94.3%
of our gross profit was generated from our specialty products
segment and approximately 5.7% of our gross profit was generated
from our fuel products segment.
2010
Update
For the years ended December 31, 2010 and 2009, 53.0% and
45.0%, respectively, of our sales volume and 94.3% and 81.8%,
respectively, of our gross profit was generated from our
specialty products segment while, for the same periods, 47.0%
and 55.0%, respectively, of our sales volume and approximately
5.7% and 18.2%, respectively, of our gross profit was generated
from our fuel products segment.
Despite uncertainty surrounding the pace of recovery in the
overall economy, we noted continued improvements in demand for
our specialty products, with particular strength in the second
half of the year. Specialty products segment sales volume during
the last six months of 2010 combined were 21.7% higher than the
same six-month period in 2009, with an increase of 14.9% for the
full year of 2010 compared to 2009. Specialty segment gross
profit also improved in 2010 compared to 2009 supported by
relatively stable crude oil prices and increased demand for our
specialty products. Our specialty products segment generated a
gross profit margin of 15.2% for the last six months of 2010
compared to a gross profit margin of 11.5% for the same period
in 2009.
While our total production in 2010 was relatively flat compared
to 2009, our production levels trended higher over the course of
the year. During the first quarter of 2010 we opted to run at
reduced crude oil rates, primarily at our Shreveport refinery,
due to the poor economics of running additional barrels in both
the specialty products and fuel products segments. We also
experienced the failure of an environmental operating unit
during the first quarter of 2010 and completed scheduled
turnarounds at our Shreveport refinery during the second and
fourth quarters of 2010 which impacted overall production levels
for the year. Subsequent to the completion of the extended
turnaround at the Shreveport refinery in April 2010, we
increased this refinerys throughput rates in order to meet
increasing specialty products demand and historically higher
demand for fuel products during the second and third quarters or
2010. Other factors increasing production levels year over year
were higher production volumes at our Cotton Valley and
Princeton refineries as well as increased specialty products
volumes under the LyondellBasell Agreements, which were
effective in November 2009. We intend to continue to run at
these higher production levels in 2011 based on current demand
for both specialty products and fuel products.
We improved our cash flow from operations by generating
$134.1 million during 2010 with $91.6 million
generated in the last six months of 2010. We paid distributions
of $65.7 million to our unitholders during 2010, an
increase of $6.5 million compared to 2009. We continue to
focus our efforts on generating positive cash flow from
operations which we expect will be used to i) maintain
compliance with the financial covenants of our credit
49
agreements, ii) improve our liquidity position,
iii) pay our quarterly distributions to our unitholders and
iv) provide funding for general operational purposes.
LyondellBasell
Agreements
Effective November 4, 2009, we entered into the
LyondellBasell Agreements with Houston Refining to form a
long-term specialty products affiliation. The initial term of
the LyondellBasell Agreements expires on October 31, 2014
after which it is automatically extended for additional one-year
terms until either party terminates with 24 months notice.
Under the terms of the LyondellBasell Agreements, (i) we
are required to purchase at least a minimum volume of
3,100 bpd of naphthenic lubricating oils produced at
Houston Refinings Houston, Texas refinery, and we have a
right of first refusal to purchase any additional naphthenic
lubricating oils produced at the refinery, and (ii) Houston
Refining is required to process a minimum of approximately
800 bpd of white mineral oil for us at its Houston, Texas
refinery, which supplements the white mineral oil production at
our Karns City and Dickinson facilities. Our annual purchase
commitment under these agreements is approximately
$158.0 million. LyondellBasell has also granted us rights
to use certain registered trademarks and tradenames, including
Tufflo, Duoprime, Duotreat, Crystex, Ideal and Aquamarine.
While no fixed assets were purchased under the LyondellBasell
Agreements, these agreements have increased our working capital
as of December 31, 2010 by approximately $24.6 million
from December 31, 2009 and our sales by $139.6 million
for the year ended December 31, 2010 as compared to the
prior year.
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 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, 2010, we have hedged
approximately 11.4 million barrels of fuel products through
December 2012 at an average refining margin of $12.62 per barrel
with average refining margins ranging from a low of $11.87 in
2011 to a high of $13.07 in 2012. As of December 31, 2010,
we have approximately 71,000 barrels of crude oil swaps
through March 2011 to hedge our purchases of crude oil for
specialty products production. The strike prices and types of
these crude oil swaps vary. Please refer to Item 7A
Quantitative and Qualitative Disclosures About Market
Risk Existing Commodity Derivative Instruments
and Existing Interest Rate Derivative
Instruments for detailed information regarding our
derivative instruments and our commodity price and interest rate
risks.
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 fuel 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
50
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 includes 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.
Our fuel products segment gross profit may differ from a
standard U.S. Gulf Coast
2/1/1 or
3/2/1 market
crack spread due to many factors, including our fuel products
mix as shown in our production table being different than the
ratios used to calculate such market crack spreads, the
allocation of by-product (primarily asphalt) losses at the
Shreveport refinery to the fuel products segment, operating
costs including fixed costs, derivative activity to hedge our
fuel products segment revenues and cost of crude oil reflected
in gross profit and our local market pricing differential in
Shreveport, Louisiana as compared to U.S. Gulf Coast
postings.
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.
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 volumes under
the LyondellBasell Agreements in 2008 and the majority of 2009,
as such agreements were not effective until November 4,
2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2010
|
|
2009
|
|
2008
|
|
|
(In bpd)
|
|
Total sales volume (1)
|
|
|
55,668
|
|
|
|
57,086
|
|
|
|
56,232
|
|
Total feedstock runs (2)
|
|
|
55,957
|
|
|
|
60,081
|
|
|
|
56,243
|
|
Facility production: (3)
|
|
|
|
|
|
|
|
|
|
|
|
|
Specialty products:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lubricating oils
|
|
|
13,697
|
|
|
|
11,681
|
|
|
|
12,462
|
|
Solvents
|
|
|
9,347
|
|
|
|
7,749
|
|
|
|
8,130
|
|
Waxes
|
|
|
1,220
|
|
|
|
1,049
|
|
|
|
1,736
|
|
Fuels
|
|
|
1,050
|
|
|
|
853
|
|
|
|
1,208
|
|
Asphalt and other by-products
|
|
|
6,907
|
|
|
|
7,574
|
|
|
|
6,623
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
32,221
|
|
|
|
28,906
|
|
|
|
30,159
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel products:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline
|
|
|
8,754
|
|
|
|
9,892
|
|
|
|
8,476
|
|
Diesel
|
|
|
10,800
|
|
|
|
12,796
|
|
|
|
10,407
|
|
Jet fuel
|
|
|
5,004
|
|
|
|
6,709
|
|
|
|
5,918
|
|
By-products
|
|
|
535
|
|
|
|
489
|
|
|
|
370
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
25,093
|
|
|
|
29,886
|
|
|
|
25,171
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total facility production (3)
|
|
|
57,314
|
|
|
|
58,792
|
|
|
|
55,330
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
51
|
|
|
(1) |
|
Total sales volume includes sales from the production at our
facilities and, certain third-party facilities pursuant to
supply and/or processing agreements, and sales of inventories. |
|
(2) |
|
Total feedstock runs represent the barrels per day of crude oil
and other feedstocks processed at our facilities and at certain
third-party facilities pursuant to supply and/or processing
agreements. The decrease in feedstock runs in 2010 compared to
2009 is due primarily to our decision to reduce crude oil run
rates at our Shreveport refinery during the entire first quarter
of 2010 because of the poor economics of running additional
barrels, the failure of an environmental operating unit during
the first quarter of 2010 and scheduled turnarounds completed in
the second and fourth quarters related to various operating
units at our Shreveport refinery. These decreases were partially
offset by higher year-long throughput rates at our Cotton Valley
refinery and the addition of volumes under the LyondellBasell
Agreements. |
|
|
|
The increase in feedstock runs in 2009 compared to 2008 is due
primarily to the Shreveport refinery expansion project placed in
service in May 2008, resulting in a full year of increased
production in 2009 compared to 2008, and the addition of volumes
under the LyondellBasell Agreements in 2009. Partially
offsetting these increases were lower overall feedstock runs at
our other facilities in 2009 compared to 2008 due to general
economic conditions. |
|
(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 at certain
third-party facilities pursuant to supply and/or processing
agreements, including the LyondellBasell Agreements. The
difference between total facility 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 increase in the production of specialty products in 2010
compared to 2009 is primarily the result of the addition of
volumes under the LyondellBasell Agreements and higher
throughput rates at our Cotton Valley refinery. The reduction in
production of fuel products in 2010 compared to 2009 is due
primarily to reduced feedstock runs at our Shreveport refinery
as discussed in footnote 2 of this table. |
|
|
|
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. |
52
The following table reflects our consolidated results of
operations and includes the non-GAAP financial measures EBITDA,
Adjusted EBITDA and Distributable Cash Flow. For a
reconciliation of EBITDA, Adjusted EBITDA and Distributable Cash
Flow to net income and net cash provided by operating
activities, our most directly comparable financial performance
and liquidity measures calculated in accordance with GAAP,
please read Non-GAAP Financial
Measures.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Sales
|
|
$
|
2,190,752
|
|
|
$
|
1,846,600
|
|
|
$
|
2,488,994
|
|
Cost of sales
|
|
|
1,992,003
|
|
|
|
1,673,498
|
|
|
|
2,235,111
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
198,749
|
|
|
|
173,102
|
|
|
|
253,883
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Selling, general and administrative
|
|
|
35,224
|
|
|
|
32,570
|
|
|
|
34,267
|
|
Transportation
|
|
|
85,471
|
|
|
|
67,967
|
|
|
|
84,702
|
|
Taxes other than income taxes
|
|
|
4,601
|
|
|
|
3,839
|
|
|
|
4,598
|
|
Other
|
|
|
1,963
|
|
|
|
1,366
|
|
|
|
1,576
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
71,490
|
|
|
|
67,360
|
|
|
|
128,740
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(30,497
|
)
|
|
|
(33,573
|
)
|
|
|
(33,938
|
)
|
Debt extinguishment costs
|
|
|
|
|
|
|
|
|
|
|
(898
|
)
|
Realized gain (loss) on derivative instruments
|
|
|
(7,704
|
)
|
|
|
8,342
|
|
|
|
(58,833
|
)
|
Unrealized gain (loss) on derivative instruments
|
|
|
(15,843
|
)
|
|
|
23,736
|
|
|
|
3,454
|
|
Gain on sale of mineral rights
|
|
|
|
|
|
|
|
|
|
|
5,770
|
|
Other
|
|
|
(147
|
)
|
|
|
(3,929
|
)
|
|
|
399
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expense
|
|
|
(54,191
|
)
|
|
|
(5,424
|
)
|
|
|
(84,046
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
17,299
|
|
|
|
61,936
|
|
|
|
44,694
|
|
Income tax expense
|
|
|
598
|
|
|
|
151
|
|
|
|
257
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
16,701
|
|
|
$
|
61,785
|
|
|
$
|
44,437
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA
|
|
$
|
109,044
|
|
|
$
|
157,612
|
|
|
$
|
135,575
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
130,369
|
|
|
$
|
146,017
|
|
|
$
|
128,075
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable Cash Flow
|
|
$
|
79,040
|
|
|
$
|
101,736
|
|
|
$
|
94,514
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
53
Year
Ended December 31, 2010 Compared to Year Ended
December 31, 2009
Sales. Sales increased $344.2 million, or
18.6%, to $2,190.8 million in 2010 from
$1,846.6 million in 2009. Sales for each of our principal
product categories in these periods were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
% Change
|
|
|
|
(Dollars in thousands)
|
|
|
Sales by segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
Specialty products:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lubricating oils
|
|
$
|
759,701
|
|
|
$
|
500,938
|
|
|
|
51.7
|
%
|
Solvents
|
|
|
396,894
|
|
|
|
260,185
|
|
|
|
52.5
|
%
|
Waxes
|
|
|
124,964
|
|
|
|
97,658
|
|
|
|
28.0
|
%
|
Fuels (1)
|
|
|
5,507
|
|
|
|
8,951
|
|
|
|
(38.5
|
)%
|
Asphalt and by-products (2)
|
|
|
121,806
|
|
|
|
103,488
|
|
|
|
17.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total specialty products
|
|
$
|
1,408,872
|
|
|
$
|
971,220
|
|
|
|
45.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total specialty products sales volume (in barrels)
|
|
|
10,766,000
|
|
|
|
9,370,000
|
|
|
|
14.9
|
%
|
Average specialty products sales price per barrel
|
|
$
|
130.86
|
|
|
$
|
103.65
|
|
|
|
26.3
|
%
|
Fuel products:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline
|
|
$
|
304,544
|
|
|
$
|
317,435
|
|
|
|
(4.1
|
)%
|
Diesel
|
|
|
330,756
|
|
|
|
372,359
|
|
|
|
(11.2
|
)%
|
Jet fuel
|
|
|
135,796
|
|
|
|
167,638
|
|
|
|
(19.0
|
)%
|
By-products (3)
|
|
|
10,784
|
|
|
|
17,948
|
|
|
|
(39.9
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total fuel products
|
|
$
|
781,880
|
|
|
$
|
875,380
|
|
|
|
(10.7
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total fuel products sales volume (in barrels)
|
|
|
9,553,000
|
|
|
|
11,466,000
|
|
|
|
(16.7
|
)%
|
Average fuel products sales price per barrel
|
|
$
|
88.93
|
|
|
$
|
69.84
|
|
|
|
27.3
|
%
|
Total sales
|
|
$
|
2,190,752
|
|
|
$
|
1,846,600
|
|
|
|
18.6
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total sales volume (in barrels)
|
|
|
20,319,000
|
|
|
|
20,836,000
|
|
|
|
(2.5
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents fuels produced in connection with the production of
specialty products at the Princeton and Cotton Valley facilities. |
|
(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. |
Specialty products segment sales in 2010 increased
$437.7 million, or 45.1%, due primarily to an increase in
the average selling price per barrel of $27.21, or 26.3%, and a
14.9% increase in sales volume, from approximately
9.4 million barrels in 2009 to 10.8 million barrels in
2010. Specialty products average selling prices per barrel
increased in all product categories driven by improving overall
demand and in response to an increase of 31.8% in the average
cost of crude oil per barrel in 2010 compared to 2009. The
increased sales volume is due primarily to improving overall
specialty products demand as a result of improved economic
conditions and the addition of sales volume under the
LyondellBasell Agreements in 2010, partially offset by decreased
production due primarily to our decision to reduce crude oil run
rates at our Shreveport refinery during the entire first quarter
of 2010 because of the poor economics of running additional
barrels, the failure of an environmental operating unit during
the first quarter of 2010 and scheduled turnarounds completed in
the second quarter related to various operating units at our
Shreveport refinery.
Fuel products segment sales in 2010 decreased
$93.5 million, or 10.7%, due primarily to a 16.7% decrease
in sales volumes, from approximately 11.5 million barrels
in 2009 to 9.6 million barrels in 2010, due primarily to
our decision to reduce crude oil run rates at our facilities
during the entire first quarter of 2010 because of the poor
54
economics of running additional barrels, the failure of an
environmental operating unit during the first quarter of 2010
and scheduled turnarounds completed in the second and fourth
quarters related to various operating units at our Shreveport
refinery. Partially offsetting this decrease in sales volume was
an increase in the average selling price per barrel of $19.09,
or 27.3%, as compared to a 32.3% increase in the average cost of
crude oil per barrel. Increases in sales prices lagged crude oil
cost increases due to local market conditions. Also contributing
to the overall decrease in sales was a $142.2 million
decrease in derivative gains on our fuel products cash flow
hedges 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 increased
$25.6 million, or 14.8%, to $198.7 million in 2010
from $173.1 million in 2009. Gross profit for our specialty
and fuel products segments was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2010
|
|
2009
|
|
% Change
|
|
|
(Dollars in thousands)
|
|
Gross profit by segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
Specialty products
|
|
$
|
187,416
|
|
|
$
|
141,577
|
|
|
|
32.4
|
%
|
Percentage of sales
|
|
|
13.3
|
%
|
|
|
14.6
|
%
|
|
|
|
|
Specialty products gross profit per barrel
|
|
$
|
17.41
|
|
|
$
|
15.11
|
|
|
|
15.2
|
%
|
Fuel products
|
|
$
|
11,333
|
|
|
$
|
31,525
|
|
|
|
(64.1
|
)%
|
Percentage of sales
|
|
|
1.4
|
%
|
|
|
3.6
|
%
|
|
|
|
|
Fuel products gross profit per barrel
|
|
$
|
1.19
|
|
|
$
|
2.75
|
|
|
|
(56.7
|
)%
|
Total gross profit
|
|
$
|
198,749
|
|
|
$
|
173,102
|
|
|
|
14.8
|
%
|
Percentage of sales
|
|
|
9.1
|
%
|
|
|
9.4
|
%
|
|
|
|
|
The increase in specialty products segment gross profit is due
primarily to the 14.9% increase in sales volume. Also improving
our gross profit was an increase of $10.9 million in 2010
compared to 2009 from the liquidation of lower cost inventory
layers. Further, the increase in the average selling price per
barrel of $27.21 exceeded the increase in the average cost of
crude oil per barrel. Partially offsetting these increases were
higher operating costs per barrel sold at our Shreveport
refinery due to lower production levels in 2010 compared to 2009.
The decrease in fuel products segment gross profit is due
primarily to reduced sales volume of 16.7%, increased crude oil
costs per barrel of 32.3% compared to the 27.3% increase in the
average sales price per barrel, a $15.6 million reduction
in gains from the liquidation of lower cost inventory layers,
higher operating costs per barrel at our Shreveport refinery due
to lower production levels and decreased derivative gains of
$4.6 million from our crack spread cash flow hedges.
Selling, general and administrative. Selling,
general and administrative expenses increased $2.7 million,
or 8.1%, to $35.2 million in 2010 from $32.6 million
in 2009. This increase is due primarily to lower bad debt
expense in 2009 resulting from the recovery of $0.9 million
account receivable and the write off of the remaining costs
related to the proposed offering for sale of senior unsecured
notes in July 2010 which we opted not to complete.
Transportation. Transportation expenses
increased $17.5 million, or 25.8%, to $85.5 million in
2010 from $68.0 million in 2009. This increase is due
primarily to increased sales volumes of lubricating oils,
solvents and waxes.
Interest expense. Interest expense decreased
$3.1 million, or 9.2%, to $30.5 million in 2010 from
$33.6 million in 2009. This decrease is due primarily to
lower interest rates and lower balances being carried on the
Companys revolver and term loan during the 2010 as
compared to 2009. Revolver borrowings were reduced due to
reductions in working capital as we improved payment terms with
certain suppliers.
Realized gain (loss) on derivative
instruments. Realized gain (loss) on derivative
instruments decreased $16.0 million to a loss of
$7.7 million in 2010 from an $8.3 million gain in
2009. This decrease is due primarily to reduced derivative gains
of $13.6 million in 2010 on settlements of our crack spread
derivatives used to economically lock in gains on a portion of
our fuel products segment derivative hedging activity. Also
contributing to this decrease was higher loss ineffectiveness on
settled fuel products derivatives designated as cash flow hedges
55
of $9.2 million. Partially offsetting these items were
decreased realized losses in 2010 on crude oil derivatives in
our specialty products segment due to the significant decline in
crude oil prices late in 2008 (which resulted in larger realized
losses early in 2009), whereas crude oil prices were relatively
stable in 2010 as well as significantly less volume of these
derivative contracts settled in 2010.
Unrealized gain (loss) on derivative
instruments. Unrealized gain (loss) on derivative
instruments decreased $39.6 million, to a $15.8 million
loss in 2010 from a $23.7 million gain in 2009. This
increased loss is due primarily to decreased gains of
$11.4 million on the derivatives used to economically hedge
our specialty products crude oil purchases and increased losses
of $7.8 million on our crack spread derivatives used to
economically lock in gains on a portion of our fuel products
segment derivative hedging activity with minimal related
activity in 2010. This decrease was also due to lower gain
ineffectiveness in 2010 as compared to 2009.
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 thousands)
|
|
|
Sales by segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
Specialty products:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lubricating oils
|
|
$
|
500,938
|
|
|
$
|
841,225
|
|
|
|
(40.5
|
)%
|
Solvents
|
|
|
260,185
|
|
|
|
419,831
|
|
|
|
(38.0
|
)%
|
Waxes
|
|
|
97,658
|
|
|
|
142,525
|
|
|
|
(31.5
|
)%
|
Fuels (1)
|
|
|
8,951
|
|
|
|
30,389
|
|
|
|
(70.5
|
)%
|
Asphalt and by-products (2)
|
|
|
103,488
|
|
|
|
144,065
|
|
|
|
(28.2
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total specialty products
|
|
$
|
971,220
|
|
|
$
|
1,578,035
|
|
|
|
(38.5
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total specialty products sales volume (in barrels)
|
|
|
9,370,000
|
|
|
|
10,289,000
|
|
|
|
(8.9
|
)%
|
Average specialty products sales price per barrel
|
|
$
|
103.65
|
|
|
$
|
153.37
|
|
|
|
(32.4
|
)%
|
Fuel products:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline
|
|
$
|
317,435
|
|
|
$
|
332,669
|
|
|
|
(4.6
|
)%
|
Diesel
|
|
|
372,359
|
|
|
|
379,739
|
|
|
|
(1.9
|
)%
|
Jet fuel
|
|
|
167,638
|
|
|
|
186,675
|
|
|
|
(10.2
|
)%
|
By-products (3)
|
|
|
17,948
|
|
|
|
11,876
|
|
|
|
51.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total fuel products
|
|
$
|
875,380
|
|
|
$
|
910,959
|
|
|
|
(3.9
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total fuel products sales volume (in barrels)
|
|
|
11,466,000
|
|
|
|
10,292,000
|
|
|
|
11.4
|
%
|
Average fuel products sales price per barrel
|
|
$
|
69.84
|
|
|
$
|
117.40
|
|
|
|
(40.5
|
)%
|
Total sales
|
|
$
|
1,846,600
|
|
|
$
|
2,488,994
|
|
|
|
(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. |
Specialty products segment sales in 2009 decreased 38.5% due
primarily 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
56
decreased by 8.9% from approximately 10.3 million barrels
in 2008 to 9.4 million barrels in 2009. This decrease is
due primarily 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
volume. 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, due primarily 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 derivative gains on
our fuel products cash flow hedges 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 thousands)
|
|
Gross profit by segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
Specialty products
|
|
$
|
141,577
|
|
|
$
|
187,561
|
|
|
|
(24.5
|
)%
|
Percentage of sales
|
|
|
14.6
|
%
|
|
|
11.9
|
%
|
|
|
|
|
Specialty products gross profit per barrel
|
|
$
|
15.11
|
|
|
$
|
18.23
|
|
|
|
(17.1
|
)%
|
Fuel products
|
|
$
|
31,525
|
|
|
$
|
66,322
|
|
|
|
(52.5
|
)%
|
Percentage of sales
|
|
|
3.6
|
%
|
|
|
7.3
|
%
|
|
|
|
|
Fuel products gross profit per barrel
|
|
$
|
2.75
|
|
|
$
|
6.44
|
|
|
|
(57.3
|
)%
|
Total gross profit
|
|
$
|
173,102
|
|
|
$
|
253,883
|
|
|
|
(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 is due
primarily to an 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 from the liquidation of lower cost inventory layers and
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 from 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 is 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 due
primarily to reduced sales volumes of lubricating oils, solvents
and waxes as well as cost reductions achieved in 2009 from
improvements in railcar leasing, lower fuel surcharges and
variable rail rates being reduced on certain routes.
57
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 is 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
due primarily 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
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.
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 to our limited
partners and general partner and debt service. We expect that
our principal uses of cash in the future will be for
distributions to our limited partners and general partner, debt
service, replacement and environmental capital expenditures and
capital expenditures related to internal growth projects and
acquisitions from third parties or affiliates. We expect to fund
future capital expenditures with current cash flow from
operations and borrowings under our existing revolving credit
facility. Future internal growth projects or acquisitions may
require expenditures in excess of our then-current cash flow
from operations and borrowings under our existing revolving
credit facility and may require us to issue debt or equity
securities in public or private offerings or incur additional
borrowings under bank credit facilities to meet those costs.
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 decrease in crude oil prices
would likely produce a corollary material adverse effect on our
borrowing capacity under our revolving credit facility and
potentially our ability to comply with the covenants under our
credit facilities. A significant, sudden increase in crude oil
prices, if sustained, would likely result in increased working
capital requirements which would be funded by borrowings under
our revolving credit facility.
The following table summarizes our primary sources and uses of
cash in each of the most recent three years:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2010
|
|
2009
|
|
2008
|
|
|
(In thousands)
|
|
Net cash provided by operating activities
|
|
$
|
134,143
|
|
|
$
|
100,854
|
|
|
$
|
130,341
|
|
Net cash used in investing activities
|
|
$
|
(34,759
|
)
|
|
$
|
(22,714
|
)
|
|
$
|
(480,461
|
)
|
Net cash provided by (used in) financing activities
|
|
$
|
(99,396
|
)
|
|
$
|
(78,139
|
)
|
|
$
|
350,133
|
|
Operating Activities. Operating activities
provided $134.1 million in cash during 2010 compared to
$100.9 million during 2009. The increase in cash provided
by operating activities is due primarily to reduced working
capital needs in 2010 providing $26.0 million in cash
compared to 2009 working capital changes using
$14.8 million. This improvement is due primarily to
improved payment terms with suppliers, offset by increases in
both accounts receivable and inventories from higher crude oil
prices.
58
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 is due
primarily to increased working capital requirements of
$19.2 million resulting from the LyondellBasell Agreements
as well as rising crude oil prices increasing our working
capital requirements, partially offset by increased net income
of $17.3 million.
Investing Activities. Cash used in investing
activities increased to $34.8 million in 2010 compared to
$22.7 million in 2009 due primarily to increased capital
expenditures in 2010 compared to 2009.
Cash used in investing activities decreased to
$22.7 million during 2009 compared to $480.5 million
during 2008. This decrease is 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
in 2008 of $49.7 million of derivative instruments related
to 2008 and 2009 utilized to economically hedge the risk of
rising crude oil prices with no comparable activity in 2009.
Financing Activities. Cash used in financing
activities was $99.4 million during 2010 compared to
$78.1 million during 2009. This increased use of cash is
due primarily to 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, with only $0.8 million of proceeds received in
early 2010 from the exercise of the underwriters
overallotment option on our December 2009 public equity offering
in addition to increased distributions of $6.5 million in
2010 as compared to 2009 due to higher amounts of outstanding
units and an increase in our distribution per unit. Partially
offsetting these increases is decreased net repayments of
revolver borrowings of $33.6 million in 2010 as compared to
2009.
Cash used in financing activities was $78.1 million during
2009 compared to cash provided of $350.1 million during
2008. This change is due primarily 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, due primarily 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.
On January 14, 2011, the Company declared a quarterly cash
distribution of $0.47 per unit on all outstanding units, or
$16.9 million, for the quarter ended December 31,
2010. The distribution was paid on February 14, 2011 to
unitholders of record as of the close of business on
February 4, 2011. This quarterly distribution of $0.47 per
unit equates to $1.88 per unit, or $67.7 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, to expand existing facilities, such as projects that
increase operating capacity, or to reduce operating costs.
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Capital improvement expenditures
|
|
$
|
10,656
|
|
|
$
|
8,013
|
|
|
$
|
161,398
|
|
Replacement capital expenditures
|
|
|
14,700
|
|
|
|
12,149
|
|
|
|
4,555
|
|
Environmental capital expenditures
|
|
|
9,645
|
|
|
|
3,359
|
|
|
|
1,749
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
35,001
|
|
|
$
|
23,521
|
|
|
$
|
167,702
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
59
We anticipate that future capital expenditure requirements will
be provided primarily through cash from operations and available
borrowings under our revolving credit facility. In 2009 and
2010, 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 improve finished product yields. We estimate
our replacement and environmental capital expenditures will
average approximately $5.0 million per quarter in 2011 with
total capital expenditures below 2010 levels. These estimated
amounts for 2011 include a portion of the $11.0 million to
$15.0 million in environmental projects required by our
settlement with the LDEQ under the Small Refinery and
Single Site Refining Initiative. Please read Items 1
and 2 Business and Properties Environmental,
Health and Safety Matters Air for additional
information.
Debt
and Credit Facilities
As of December 31, 2010, our credit facilities consist of:
|
|
|
|
|
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
|
|
|
|
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 above
senior secured first lien credit facility, we incurred total
debt issuance costs of $23.4 million, including
$17.4 million of issuance discounts.
|
Borrowings under the amended revolving credit facility are
limited to a borrowing base that is determined based on advance
rates of percentages of eligible accounts receivable and
inventory (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. Our borrowing base at
December 31, 2010 was $247.0 million. 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. 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, 2010
was $247.0 million; thus, we would have to experience
defaults in commitments totaling $128.0 million from our
lender group before such defaults would impact our liquidity as
of December 31, 2010. Accordingly, at least three of our
nine lenders would have to default in order for our liquidity
position as of December 31, 2010 under the revolving credit
facility to be adversely impacted.
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. The revolving credit facility, which
matures in January 2013, has a first priority lien on our cash,
accounts receivable and inventory and a second priority lien on
our fixed assets. On December 31, 2010, we had availability
on our revolving credit facility of $145.5 million, based
upon a $247.0 million borrowing base, $90.7 million in
outstanding standby letters of credit, and outstanding
borrowings of $10.8 million. The improvement in our
availability under our revolving credit facility of
approximately $38.2 million from December 31, 2009 to
December 31, 2010 is due primarily to increased cash flow
from operations.
Amounts outstanding on our revolving credit facility do
materially fluctuate during each quarter due to normal changes
in working capital, payments of quarterly distributions to
unitholders and debt service costs. Specifically, the amount
borrowed under our revolving credit facility is typically at its
highest level after we pay for the majority of our crude oil
supplies on the 20th day of every month per standard
industry terms. The maximum revolving credit
60
facility borrowings during the fourth quarter of 2010 was
$107.2 million. Nonetheless, our availability on our
revolving credit facility during the peak borrowing days of a
quarter has been ample to support our operations and service
upcoming requirements. During the quarter ended
December 31, 2010, availability for additional borrowings
under our revolving credit facility was approximately
$78.6 million at its lowest point. We believe that we will
continue to have sufficient cash flow from operations and
borrowing availability under our revolving credit facility to
meet our financial commitments, minimum quarterly distributions
to our unitholders, debt service obligations, credit agreement
covenants, 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 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 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.
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 with the counterparty 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.
The credit facilities require us to satisfy certain financial
and other covenants, including:
|
|
|
|
|
|
|
|
|
|
|
Requirement
|
|
Actual Level at December 31, 2010
|
|
Consolidated Leverage Ratio
|
|
|
< 3.75 to 1
|
|
|
|
2.90 to 1
|
|
Consolidated Interest Coverage Ratio
|
|
|
> 2.75 to 1
|
|
|
|
4.22 to 1
|
|
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 are obligated to comply with certain financial covenants
requiring us to maintain a Consolidated Leverage Ratio of no
more than 3.75 to 1 and a Consolidated Interest Coverage Ratio
of no less than 2.75 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). 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,
61
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
acquisition of Penreco on January 3, 2008 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,
2010, 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 2010, 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 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.
On July 12, 2010, we announced that we and Calumet Finance
Corp., our wholly owned subsidiary, intended to offer for sale
in a private placement under Rule 144A to eligible
purchasers $450 million in aggregate principal amount of
senior unsecured notes. We viewed the offering as an
opportunity, but not a necessity, to refinance our existing term
loan facility with longer-term unsecured notes. However, on
July 22, 2010, we announced that, due to
62
market conditions, we opted to not move forward with the
contemplated senior notes offering at that time. We intend to
continue monitoring the capital markets for the opportunity to
complete a debt refinancing transaction under appropriate market
conditions.
Contractual
Obligations and Commercial Commitments
A summary of our total contractual cash obligations as of
December 31, 2010 is as follows:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
|
|
|
|
|
Less Than
|
|
|
1-3
|
|
|
3-5
|
|
|
More Than
|
|
|
|
Total
|
|
|
1 Year
|
|
|
Years
|
|
|
Years
|
|
|
5 Years
|
|
|
|
(In thousands)
|
|
|
Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest on long-term debt at contractual rates
|
|
$
|
70,458
|
|
|
$
|
20,026
|
|
|
$
|
34,908
|
|
|
$
|
15,524
|
|
|
$
|
|
|
Operating lease obligations (1)
|
|
|
36,339
|
|
|
|
12,572
|
|
|
|
16,355
|
|
|
|
6,644
|
|
|
|
768
|
|
Letters of credit (2)
|
|
|
140,725
|
|
|
|
90,725
|
|
|
|
50,000
|
|
|
|
|
|
|
|
|
|
Purchase commitments (3)
|
|
|
1,006,114
|
|
|
|
560,015
|
|
|
|
315,264
|
|
|
|
130,835
|
|
|
|
|
|
Pension obligations
|
|
|
10,063
|
|
|
|
1,763
|
|
|
|
4,300
|
|
|
|
3,500
|
|
|
|
500
|
|
Employment agreements (4)
|
|
|
742
|
|
|
|
371
|
|
|
|
371
|
|
|
|
|
|
|
|
|
|
Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital lease obligations
|
|
|
1,781
|
|
|
|
994
|
|
|
|
787
|
|
|
|
|
|
|
|
|
|
Long-term debt obligations, excluding capital lease obligations
|
|
|
378,217
|
|
|
|
3,850
|
|
|
|
18,532
|
|
|
|
355,835
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total obligations
|
|
$
|
1,644,439
|
|
|
$
|
690,316
|
|
|
$
|
440,517
|
|
|
$
|
512,338
|
|
|
$
|
1,268
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 and other feedstocks and finished products
for resale 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 vice chairman of the board of
our general partner. |
In connection with the closing of the acquisition of Penreco 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 $64.9 million of feedstock for the LVT
unit in each fiscal year of the term based on pricing estimates
as of December 31, 2010. This amount is not included in the
table above. 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.
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, 2010, 2009 and
2008. These consolidated financial statements have been prepared
in accordance with GAAP. The preparation of these financial
statements requires
63
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 Annual Report. 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 $55.9 million and
$30.4 million higher at December 31, 2010 and 2009,
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 complete a comparison of implied
crack spread
mark-to-market
valuations among our counterparties.
Our derivative instruments, consisting of derivative liabilities
of $32.8 million as of December 31, 2010, 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 losses on derivative
instruments of $7.7 million and $15.8 million,
respectively, on our derivative instruments in 2010. The
decrease in the fair market value of our outstanding derivative
instruments from a net asset of $26.1 million as of
December 31, 2009 to a liability of $32.8 million as
of December 31, 2010 was due primarily to
$28.9 million in settlements of fuel products derivative
instruments outstanding as of December 31, 2009, in
addition to $18.5 million in liabilities related to new
derivative instruments. We believe that the fair values of our
derivative instruments may diverge materially from the amounts
currently recorded to fair value at settlement due to the
volatility of commodity prices.
64
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 volumes hedged
as of December 31, 2010:
|
|
|
|
|
|
|
In millions
|
|
Crude oil swaps
|
|
$
|
11.5
|
|
Diesel swaps
|
|
$
|
(3.9
|
)
|
Jet fuel swaps
|
|
$
|
(6.6
|
)
|
Gasoline swaps
|
|
$
|
(0.9
|
)
|
We enter into crude oil, gasoline, and diesel hedges to hedge an
implied crack spread in our fuel products segment. 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 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 January 2010, the FASB issued ASU
No. 2010-06,
Disclosures About Fair Value Measurements (ASU
2010-06),
which amends ASC No. 820, Fair Value Measurements and
Disclosures to add new requirements for disclosures about
transfers into and out of Levels 1 and 2 and separate
disclosures about purchases, sales, issuances, and settlements
relating to Level 3 measurements. ASU
2010-06 also
clarifies existing fair value disclosures about the level of
disaggregation and about inputs and valuation techniques used to
measure fair value. ASU
2010-06 is
effective for the first reporting period (including interim
periods) beginning after December 15, 2009. The Company
adopted ASU
2010-06
effective January 1, 2010; however, the Companys
adoption of the ASU did not have a material effect on the
Companys financial position, results of operations or cash
flows.
In December 2010, the FASB issued ASU
No. 2010-28,
When to Perform Step 2 of the Goodwill Impairment Test for
Reporting Units with Zero or Negative Carrying Amounts
(ASU
2010-28),
which amends ASC No. 830, Intangibles
Goodwill and Other to modify Step 1 of the evaluation of
goodwill impairment for reporting units with zero or negative
carrying amounts to require that Step 2 of the impairment test
be performed to measure the amount of any impairment loss when
it is more likely than not that a goodwill impairment exits. ASU
2010-28 is
effective for fiscal years, and interim periods within those
years, beginning after December 15, 2010, with early
adoption not permitted. The Company does not expect the adoption
of ASU
2010-28 to
have a material impact on the Companys financial position,
results of operations, or cash flows.
In December 2010, the FASB issued ASU
No. 2010-29,
Disclosures of Supplementary Pro Forma Information for
Business Combinations (ASU
2010-29),
which amends ASC No. 805, Business Combinations, to
expand the requirements for supplemental pro forma disclosures
to include a description of the nature and amount of material,
nonrecurring pro forma adjustments directly attributable to the
business combination included in the reported pro forma revenue
and earnings. ASU
2010-29 is
effective for business combinations for which the acquisition
date is on or after the beginning of the first annual reporting
period beginning on or after December 15, 2010, and should
be
65
applied prospectively. The Company will apply the provisions of
ASU 2010-29
for all future business combinations.
|
|
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
$10.8 million and our fuel product segment cost of sales by
$9.6 million based on our sales volumes for 2010.
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, as evidenced during the prior three
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 selling prices as quickly as
increases in the price of crude oil. Due to this lack of
correlation between our specialty products selling 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. While our policy
generally requires that these positions be short term in nature
and expire within three to nine months from execution, we may
execute derivative instruments for up to two years forward, if a
change in crude oil price risks supports 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
$4.0 million based on our results for the year ended
December 31, 2010.
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.
66
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 $9.6 million
based on our results for the year ended December 31, 2010.
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
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, 2010,
we were over 60% hedged for the forward 12 month period and
over 50% hedged for the forward 24 month period. We are
currently hedging in calendar year 2013, with no positions
currently in 2014 or 2015.
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
$26.1 million as of December 31, 2009 to a liability
of $32.8 million as of December 31, 2010 was due
primarily 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 2010 that
resulted in realized gain. Please read Note 2
Summary of Significant Accounting Policies
Derivatives in the notes to our consolidated financial
statements under Item 8 Financial Statements and
Supplementary Data 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. Our policy is generally to enter into
interest rate swap agreements to hedge up to 75% of its interest
rate risk under our term loan agreement.
We are exposed to market risk from fluctuations in interest
rates. As of December 31, 2010, we had approximately
$378.2 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, 2010 would be expected to have an impact on
net income and cash flows for 2010 of approximately
$3.8 million.
We have a $375.0 million revolving credit facility as of
December 31, 2010, bearing interest at the prime rate or
LIBOR, at our option, plus the applicable margin. We had
borrowings of $10.8 million outstanding under this facility
as of December 31, 2010, 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 a portion of its current
variable rate senior secured first lien term loan which closed
January 3, 2008. The Company hedged the future interest
payments related to $150.0 million and $50.0 million
of the total outstanding term loan indebtedness in 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 hedged the future interest payments related
to $200.0 million of the total outstanding term loan
indebtedness for the period 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 rate during the hedge
period of 0.94%.
67
During 2010, the Company entered into forward swap contracts to
manage interest rate risk related to a portion of its current
variable rate senior secured first lien term loan. The Company
hedged the future interest payments related to
$100.0 million of the total outstanding term loan
indebtedness for the period from February 15, 2011 to
February 15, 2012 pursuant to these forward swap contracts.
These swap contracts are designated as cash flow hedges of the
future payments of interest with three-month LIBOR fixed at an
average rate during the hedge period of 2.03%.
Existing
Commodity Derivative Instruments
Fuel
Products Segment
As a result of our fuel products hedging activity, we recorded a
loss of $67.7 million and a gain of $81.6 million, to
sales and cost of sales, respectively, in the consolidated
statements of operations for 2010. As of December 31, 2010
we had not provided any cash margin in credit support to our
hedging counterparties. As of February 18, 2011, we had
provided $23.2 million in credit support to our hedging
counterparties due to the decrease in the fair market value of
our derivative instruments since December 31, 2010.
The following tables provide information about our derivative
instruments related to our fuel products segment as of
December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
Barrels
|
|
|
|
|
|
Swap
|
|
Crude Oil Swap Contracts by Expiration Dates
|
|
Purchased
|
|
|
BPD
|
|
|
($/Bbl)
|
|
|
First Quarter 2011
|
|
|
1,215,000
|
|
|
|
13,500
|
|
|
$
|
75.32
|
|
Second Quarter 2011
|
|
|
1,729,000
|
|
|
|
19,000
|
|
|
|
76.62
|
|
Third Quarter 2011
|
|
|
1,610,000
|
|
|
|
17,500
|
|
|
|
77.38
|
|
Fourth Quarter 2011
|
|
|
1,334,000
|
|
|
|
14,500
|
|
|
|
77.71
|
|
Calendar Year 2012
|
|
|
5,535,000
|
|
|
|
15,123
|
|
|
|
86.30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
|
11,423,000
|
|
|
|
|
|
|
|
|
|
Average price
|
|
|
|
|
|
|
|
|
|
$
|
81.41
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
|
|
|
Swap
|
|
Diesel Swap Contracts by Expiration Dates
|
|
Barrels Sold
|
|
|
BPD
|
|
|
($/Bbl)
|
|
|
First Quarter 2011
|
|
|
630,000
|
|
|
|
7,000
|
|
|
$
|
89.57
|
|
Second Quarter 2011
|
|
|
637,000
|
|
|
|
7,000
|
|
|
|
89.57
|
|
Third Quarter 2011
|
|
|
552,000
|
|
|
|
6,000
|
|
|
|
91.74
|
|
Fourth Quarter 2011
|
|
|
552,000
|
|
|
|
6,000
|
|
|
|
91.74
|
|
Calendar Year 2012
|
|
|
1,560,000
|
|
|
|
4,262
|
|
|
|
99.27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
|
3,931,000
|
|
|
|
|
|
|
|
|
|
Average price
|
|
|
|
|
|
|
|
|
|
$
|
94.03
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
|
|
|
Swap
|
|
Jet Fuel Swap Contracts by Expiration Dates
|
|
Barrels Sold
|
|
|
BPD
|
|
|
($/Bbl)
|
|
|
First Quarter 2011
|
|
|
405,000
|
|
|
|
4,500
|
|
|
$
|
86.12
|
|
Second Quarter 2011
|
|
|
819,000
|
|
|
|
9,000
|
|
|
|
89.58
|
|
Third Quarter 2011
|
|
|
920,000
|
|
|
|
10,000
|
|
|
|
89.86
|
|
Fourth Quarter 2011
|
|
|
644,000
|
|
|
|
7,000
|
|
|
|
89.21
|
|
Calendar Year 2012
|
|
|
3,838,500
|
|
|
|
10,480
|
|
|
|
99.78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
|
6,626,500
|
|
|
|
|
|
|
|
|
|
Average price
|
|
|
|
|
|
|
|
|
|
$
|
95.28
|
|
68
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
|
|
|
Swap
|
|
Gasoline Swap Contracts by Expiration Dates
|
|
Barrels Sold
|
|
|
BPD
|
|
|
($/Bbl)
|
|
|
First Quarter 2011
|
|
|
180,000
|
|
|
|
2,000
|
|
|
$
|
81.84
|
|
Second Quarter 2011
|
|
|
273,000
|
|
|
|
3,000
|
|
|
|
82.66
|
|
Third Quarter 2011
|
|
|
138,000
|
|
|
|
1,500
|
|
|
|
85.50
|
|
Fourth Quarter 2011
|
|
|
138,000
|
|
|
|
1,500
|
|
|
|
85.50
|
|
Calendar Year 2012
|
|
|
136,500
|
|
|
|
373
|
|
|
|
89.04
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
|
865,500
|
|
|
|
|
|
|
|
|
|
Average price
|
|
|
|
|
|
|
|
|
|
$
|
84.40
|
|
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Implied
|
|
|
|
|
|
|
|
|
|
Crack Spread
|
|
Swap Contracts by Expiration Dates
|
|
Barrels Sold
|
|
|
BPD
|
|
|
($/Bbl)
|
|
|
First Quarter 2011
|
|
|
1,215,000
|
|
|
|
13,500
|
|
|
$
|
11.96
|
|
Second Quarter 2011
|
|
|
1,729,000
|
|
|
|
19,000
|
|
|
|
11.87
|
|
Third Quarter 2011
|
|
|
1,610,000
|
|
|
|
17,500
|
|
|
|
12.75
|
|
Fourth Quarter 2011
|
|
|
1,334,000
|
|
|
|
14,500
|
|
|
|
12.16
|
|
Calendar Year 2012
|
|
|
5,535,000
|
|
|
|
15,123
|
|
|
|
13.07
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
|
11,423,000
|
|
|
|
|
|
|
|
|
|
Average price
|
|
|
|
|
|
|
|
|
|
$
|
12.62
|
|
Jet
Fuel Put Spread Contracts
At December 31, 2010, 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)
|
|
|
First Quarter 2011
|
|
|
630,000
|
|
|
|
7,000
|
|
|
$
|
4.00
|
|
|
$
|
6.00
|
|
Fourth Quarter 2011
|
|
|
184,000
|
|
|
|
2,000
|
|
|
|
4.75
|
|
|
|
7.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 $5.3 million, to realized
loss on derivative instruments in the consolidated statements of
operations for 2010. As of December 31, 2010 and
February 18, 2011, we had not provided any cash margin in
credit support to any of our hedging counterparties. At
December 31, 2010, the Company had the following crude oil
swap 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 $0.7 million of gain in unrealized gain
(loss) on derivative instruments in the consolidated statements
of operations in 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
Barrels
|
|
|
|
|
|
Swap
|
|
Crude Oil Swap Contracts by Expiration Dates
|
|
Purchased
|
|
|
BPD
|
|
|
($/Bbl)
|
|
|
February 2011
|
|
|
33,600
|
|
|
|
1,200
|
|
|
$
|
83.10
|
|
March 2011
|
|
|
37,200
|
|
|
|
1,200
|
|
|
|
83.55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
|
70,800
|
|
|
|
|
|
|
|
|
|
Average price
|
|
|
|
|
|
|
|
|
|
$
|
83.34
|
|
69
|
|
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, 2010 and 2009, and the related consolidated
statements of operations, partners capital, and cash flows
for each of the three years in the period ended
December 31, 2010. 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, 2010 and 2009, and the consolidated results
of its operations and its cash flows for each of the three years
in the period ended December 31, 2010, 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, 2010, 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 18, 2011
expressed an unqualified opinion thereon.
Indianapolis, Indiana
February 18, 2011
70
CALUMET
SPECIALTY PRODUCTS PARTNERS, L.P.
CONSOLIDATED
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands, except
|
|
|
|
unit data)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
37
|
|
|
$
|
49
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Trade, less allowance for doubtful accounts of $633 and $801,
respectively
|
|
|
157,185
|
|
|
|
116,914
|
|
Other
|
|
|
776
|
|
|
|
5,854
|
|
|
|
|
|
|
|
|
|
|
|
|
|
157,961
|
|
|
|
122,768
|
|
|
|
|
|
|
|
|
|
|
Inventories
|
|
|
147,110
|
|
|
|
137,250
|
|
Derivative assets
|
|
|
|
|
|
|
30,904
|
|
Prepaid expenses and other current assets
|
|
|
1,909
|
|
|
|
1,811
|
|
Deposits
|
|
|
2,094
|
|
|
|
6,861
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
309,111
|
|
|
|
299,643
|
|
Property, plant and equipment, net
|
|
|
612,433
|
|
|
|
629,275
|
|
Goodwill
|
|
|
48,335
|
|
|
|
48,335
|
|
Other intangible assets, net
|
|
|
29,666
|
|
|
|
38,093
|
|
Other noncurrent assets, net
|
|
|
17,127
|
|
|
|
16,510
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,016,672
|
|
|
$
|
1,031,856
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS CAPITAL
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
146,730
|
|
|
$
|
92,110
|
|
Accounts payable related party
|
|
|
27,985
|
|
|
|
17,866
|
|
Accrued salaries, wages and benefits
|
|
|
7,559
|
|
|
|
6,500
|
|
Taxes payable
|
|
|
7,174
|
|
|
|
7,551
|
|
Other current liabilities
|
|
|
16,605
|
|
|
|
6,114
|
|
Current portion of long-term debt
|
|
|
4,844
|
|
|
|
5,009
|
|
Derivative liabilities
|
|
|
32,814
|
|
|
|
4,766
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
243,711
|
|
|
|
139,916
|
|
Pension and postretirement benefit obligations
|
|
|
9,168
|
|
|
|
9,433
|
|
Other long-term liabilities
|
|
|
1,083
|
|
|
|
1,111
|
|
Long-term debt, less current portion
|
|
|
364,431
|
|
|
|
396,049
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
618,393
|
|
|
|
546,509
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
Partners capital:
|
|
|
|
|
|
|
|
|
Common unitholders (22,213,778 units and
22,166,000 units, issued and outstanding at
December 31, 2010 and 2009, respectively)
|
|
|
390,843
|
|
|
|
418,902
|
|
Subordinated unitholders (13,066,000 units, issued and
outstanding at December 31, 2010 and 2009)
|
|
|
16,930
|
|
|
|
34,714
|
|
General partners interest
|
|
|
18,125
|
|
|
|
19,087
|
|
Accumulated other comprehensive income (loss)
|
|
|
(27,619
|
)
|
|
|
12,644
|
|
|
|
|
|
|
|
|
|
|
Total partners capital
|
|
|
398,279
|
|
|
|
485,347
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners capital
|
|
$
|
1,016,672
|
|
|
$
|
1,031,856
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
71
CALUMET
SPECIALTY PRODUCTS PARTNERS, L.P.
CONSOLIDATED
STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands, except per unit data)
|
|
|
Sales
|
|
$
|
2,190,752
|
|
|
$
|
1,846,600
|
|
|
$
|
2,488,994
|
|
Cost of sales
|
|
|
1,992,003
|
|
|
|
1,673,498
|
|
|
|
2,235,111
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
198,749
|
|
|
|
173,102
|
|
|
|
253,883
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Selling, general and administrative
|
|
|
35,224
|
|
|
|
32,570
|
|
|
|
34,267
|
|
Transportation
|
|
|
85,471
|
|
|
|
67,967
|
|
|
|
84,702
|
|
Taxes other than income taxes
|
|
|
4,601
|
|
|
|
3,839
|
|
|
|
4,598
|
|
Other
|
|
|
1,963
|
|
|
|
1,366
|
|
|
|
1,576
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
71,490
|
|
|
|
67,360
|
|
|
|
128,740
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(30,497
|
)
|
|
|
(33,573
|
)
|
|
|
(33,938
|
)
|
Debt extinguishment costs
|
|
|
|
|
|
|
|
|
|
|
(898
|
)
|
Realized gain (loss) on derivative instruments
|
|
|
(7,704
|
)
|
|
|
8,342
|
|
|
|
(58,833
|
)
|
Unrealized gain (loss) on derivative instruments
|
|
|
(15,843
|
)
|
|
|
23,736
|
|
|
|
3,454
|
|
Gain on sale of mineral rights
|
|
|
|
|
|
|
|
|
|
|
5,770
|
|
Other
|
|
|
(147
|
)
|
|
|
(3,929
|
)
|
|
|
399
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expense
|
|
|
(54,191
|
)
|
|
|
(5,424
|
)
|
|
|
(84,046
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
17,299
|
|
|
|
61,936
|
|
|
|
44,694
|
|
Income tax expense
|
|
|
598
|
|
|
|
151
|
|
|
|
257
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
16,701
|
|
|
$
|
61,785
|
|
|
$
|
44,437
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocation of net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
16,701
|
|
|
$
|
61,785
|
|
|
$
|
44,437
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
General partners interest in net income
|
|
|
334
|
|
|
|
1,236
|
|
|
|
889
|
|
Holders of incentive distribution rights
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to limited partners
|
|
|
16,367
|
|
|
|
60,549
|
|
|
|
43,548
|
|
Weighted average limited partner units outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
35,335
|
|
|
|
32,372
|
|
|
|
32,232
|
|
Diluted
|
|
|
35,351
|
|
|
|
32,372
|
|
|
|
32,232
|
|
Common and subordinated unitholders basic and diluted net
income per unit
|
|
$
|
0.46
|
|
|
$
|
1.87
|
|
|
$
|
1.35
|
|
Cash distributions declared per common and subordinated unit
|
|
$
|
1.84
|
|
|
$
|
1.81
|
|
|
$
|
1.98
|
|
See accompanying notes to consolidated financial statements.
72
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, 2008
|
|
$
|
(39,641
|
)
|
|
$
|
19,364
|
|
|
$
|
375,925
|
|
|
$
|
43,996
|
|
|
$
|
399,644
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
889
|
|
|
|
25,895
|
|
|
|
17,653
|
|
|
|
44,437
|
|
Cash flow hedge loss reclassified to net income
|
|
|
(8,208
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8,208
|
)
|
Change in fair value of cash flow hedges
|
|
|
109,639
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
109,639
|
|
Defined benefit pension and retiree health benefit plans
|
|
|
(6,224
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,224
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
139,644
|
|
Units repurchased for phantom unit grants
|
|
|
|
|
|
|
|
|
|
|
(115
|
)
|
|
|
|
|
|
|
(115
|
)
|
Amortization of vested phantom units
|
|
|
|
|
|
|
|
|
|
|
179
|
|
|
|
|
|
|
|
179
|
|
Distributions to partners
|
|
|
|
|
|
|
(2,320
|
)
|
|
|
(37,949
|
)
|
|
|
(25,871
|
)
|
|
|
(66,140
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008
|
|
$
|
55,566
|
|
|
$
|
17,933
|
|
|
$
|
363,935
|
|
|
$
|
35,778
|
|
|
$
|
473,212
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
1,236
|
|
|
|
38,094
|
|
|
|
22,455
|
|
|
|
61,785
|
|
Cash flow hedge gain reclassified to net income
|
|
|
(15,068
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(15,068
|
)
|
Change in fair value of cash flow hedges
|
|
|
(29,371
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(29,371
|
)
|
Defined benefit pension and retiree health benefit plans
|
|
|
1,517
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,517
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18,863
|
|
Proceeds from public equity offering, net
|
|
|
|
|
|
|
|
|
|
|
51,225
|
|
|
|
|
|
|
|
51,225
|
|
Contribution from Calumet GP, LLC
|
|
|
|
|
|
|
1,102
|
|
|
|
|
|
|
|
|
|
|
|
1,102
|
|
Units repurchased for phantom unit grants
|
|
|
|
|
|
|
|
|
|
|
(164
|
)
|
|
|
|
|
|
|
(164
|
)
|
Amortization of vested phantom units
|
|
|
|
|
|
|
|
|
|
|
367
|
|
|
|
|
|
|
|
367
|
|
Distributions to partners
|
|
|
|
|
|
|
(1,184
|
)
|
|
|
(34,555
|
)
|
|
|
(23,519
|
)
|
|
|
(59,258
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009
|
|
$
|
12,644
|
|
|
$
|
19,087
|
|
|
$
|
418,902
|
|
|
$
|
34,714
|
|
|
$
|
485,347
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
334
|
|
|
|
10,305
|
|
|
|
6,062
|
|
|
|
16,701
|
|
Cash flow hedge gain reclassified to net income
|
|
|
(11,104
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(11,104
|
)
|
Change in fair value of cash flow hedges
|
|
|
(29,015
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(29,015
|
)
|
Defined benefit pension and retiree health benefit plans
|
|
|
(144
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(144
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(23,562
|
)
|
Proceeds from public equity offering, net
|
|
|
|
|
|
|
|
|
|
|
793
|
|
|
|
|
|
|
|
793
|
|
Contribution from Calumet GP, LLC
|
|
|
|
|
|
|
18
|
|
|
|
|
|
|
|
|
|
|
|
18
|
|
Units repurchased for phantom unit grants
|
|
|
|
|
|
|
|
|
|
|
(248
|
)
|
|
|
|
|
|
|
(248
|
)
|
Amortization of vested phantom units
|
|
|
|
|
|
|
|
|
|
|
1,670
|
|
|
|
|
|
|
|
1,670
|
|
Distributions to partners
|
|
|
|
|
|
|
(1,314
|
)
|
|
|
(40,579
|
)
|
|
|
(23,846
|
)
|
|
|
(65,739
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2010
|
|
$
|
(27,619
|
)
|
|
$
|
18,125
|
|
|
$
|
390,843
|
|
|
$
|
16,930
|
|
|
$
|
398,279
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
73
CALUMET
SPECIALTY PRODUCTS PARTNERS, L.P.
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
16,701
|
|
|
$
|
61,785
|
|
|
$
|
44,437
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
64,151
|
|
|
|
65,407
|
|
|
|
59,261
|
|
Amortization of turnaround costs
|
|
|
10,006
|
|
|
|
7,256
|
|
|
|
2,468
|
|
Provision for doubtful accounts
|
|
|
74
|
|
|
|
(916
|
)
|
|
|
1,448
|
|
Non-cash debt extinguishment costs
|
|
|
|
|
|
|
|
|
|
|
898
|
|
Unrealized (gain) loss on derivative instruments
|
|
|
15,843
|
|
|
|
(23,736
|
)
|
|
|
(3,454
|
)
|
Gain on sale of mineral rights
|
|
|
|
|
|
|
|
|
|
|
(5,770
|
)
|
Loss on disposal of fixed assets
|
|
|
239
|
|
|
|
4,455
|
|
&nbs |