UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-K

 

 

Commission File number 000-51734

 

Calumet Specialty Products Partners, L.P.

(Exact Name of Registrant as Specified in Its Charter)

 

 

2780 Waterfront Pkwy E. Drive

Suite 200

 

Indianapolis, Indiana 46214

(317) 328-5660

 

(Address, Including Zip Code, and Telephone Number,

Including Area Code, of Registrant’s Principal Executive Offices)

 

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

 

 

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  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):

 

(Do not check if a smaller reporting company)

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes o     No þ

 

The aggregate market value of the common units held by non-affiliates of the registrant (treating all executive officers and directors of the registrant and holders of 10% or more of the common units outstanding, for this purpose, as if they may be affiliates of the registrant) was approximately $100.3 million on June 30, 2008, based on $14.36 per unit, the closing price of the common units as reported on the NASDAQ Global Market on such date.

 

At February 26, 2009, there were 19,166,000 common units and 13,066,000 subordinated units outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE
NONE.

 

 

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
FORM 10-K — 2008 ANNUAL REPORT

Table of Contents

 

FORWARD-LOOKING STATEMENTS

 

This Annual Report on Form 10-K includes certain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Some of the information in this annual report may contain forward-looking statements. 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) the Shreveport refinery expansion project’s increases in production levels, (ii) expected settlements with the Louisiana Department of Environmental Quality (“LDEQ”) or other environmental and regulatory liabilities, (iii) the future benefits and risks of the Penreco acquisition, (iv) our anticipated levels of use of derivatives to mitigate our exposure to crude oil price changes and fuel products price changes and (v) future compliance with our debt covenants as well as other matters discussed in this Form 10-K that are not purely historical data, are forward-looking statements. These statements discuss future expectations or state other “forward-looking” information and involve risks and uncertainties. When considering these forward-looking statements, unitholders should keep in mind the risk factors and other cautionary statements included in this Annual Report on Form 10-K. The risk factors and other factors noted throughout this Annual Report on Form 10-K could cause our actual results to differ materially from those contained in any forward-looking statement. These factors include, but are not limited to:

 

 

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 on Form 10-K. 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 on Form 10-K to “Calumet Specialty Products Partners, L.P.,” “Calumet,” “the Partnership,” “the Company,” “we,” “our,” “us” or like terms, when used in a historical context prior to January 31, 2006, refer to the assets and liabilities of Calumet Lubricants Co., Limited Partnership and its subsidiaries of which substantially all such assets and liabilities were contributed to Calumet Specialty Products Partners, L.P. and its subsidiaries upon the completion of our initial public offering. When used in the present tense or prospectively, those terms refer to Calumet Specialty Products Partners, L.P. and its subsidiaries. References to “Predecessor” in this Form 10-K refer to Calumet Lubricants Co., Limited Partnership. The results of operations for the year ended December 31, 2006 for Calumet include the results of operations of the Predecessor for the period of January 1, 2006 through January 31, 2006. References in this Annual Report on Form 10-K to “our general partner” refer to Calumet GP, LLC.

 

 

Overview

 

We are a leading independent producer of high-quality, specialty hydrocarbon products in North America. 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, solvents 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 unleaded 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. For 2008, approximately 73.9% of our gross profit was generated from our specialty products segment and approximately 26.1% of our gross profit was generated from our fuel products segment. The acquisition of Penreco on January 3, 2008 expanded our specialty products offering and customer base. For additional discussion of this acquisition, please read Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Acquisition and Refinery Expansion.”

 

Our operating assets consist of our:

 

 

Business Strategies

 

Our management team is dedicated to improving our operations by executing the following strategies:

 

 

 

 

Competitive Strengths

 

We believe that we are well positioned to execute our business strategies successfully based on the following competitive strengths:

 

 

Our Operating Assets

 

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 as well as a terminal in Burnham, Illinois.

The following table sets forth information about our combined operations. Production volume differs from sales volume due to changes in inventory. The following table does not include operations of our Karns City, Pennsylvania and Dickinson, Texas facilities for 2007 and 2006, as we did not acquire these facilities until January 3, 2008 with the acquisition of Penreco.

 

 

 

 

Set forth below is information regarding sales of our principal products by segment.

 

 

Princeton Refinery

 

The Princeton refinery, located on a 208-acre site in Princeton, Louisiana, has aggregate crude oil throughput capacity of 10,000 bpd and is currently processing naphthenic crude oil into lubricating oils, high sulfur diesel and asphalt. The high sulfur diesel may be blended to produce certain lubricating oils, transported to the Shreveport refinery for further processing into ultra low sulfur diesel or sold to third parties. The asphalt may be processed or blended for coating and roofing applications at the Princeton refinery or transported to the Shreveport refinery for processing into bright stock.

 

The Princeton refinery currently consists of seven major processing units, approximately 650,000 barrels of storage capacity in 200 storage tanks and related loading and unloading facilities and utilities. Since our acquisition of the Princeton refinery in 1990, we have debottlenecked the crude unit to increase production capacity to 10,000 bpd, increased the hydrotreater’s capacity to 7,000 bpd and upgraded the refinery’s 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.

 

 

 

 

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 refinery’s processing capabilities consist of atmospheric and vacuum distillation, hydrotreating, asphalt oxidation processing and clay/acid treating

facilities. In addition, we have the necessary tankage and technology to process our asphalt into higher value applications like coatings and road paving applications.

 

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, Related Party Transactions and Director Independence — Crude Oil Purchases” for additional information regarding our crude oil purchases from Legacy Resources. The Princeton refinery ships its finished products throughout the country by both truck and railcar service.

 

Cotton Valley Refinery

 

The Cotton Valley refinery, located on a 77-acre site in Cotton Valley, Louisiana, has aggregate crude oil throughput capacity of 13,500 bpd, hydrotreating capacity of 5,100 bpd and is currently processing crude oil into solvents, low sulfur diesel, fuel feedstocks and residual fuel oil. The residual fuel oil is an important feedstock for specialty refined products at our Shreveport refinery. We believe the Cotton Valley refinery produces the most complete, single-facility line of paraffinic solvents in the United States.

 

The Cotton Valley refinery currently consists of three major processing units that include a crude unit, a hydrotreater and a fractionation train, approximately 625,000 barrels of storage capacity in 74 storage tanks and related loading and unloading facilities and utilities. The Cotton Valley refinery also has a utility fractionator for batch processing of narrow distillation range specialty solvents. Since its acquisition in 1995, we have expanded the refinery’s capabilities by installing a hydrotreater that removes aromatics, increased the crude unit processing capability to 13,500 bpd and reconfigured the refinery’s 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.

 

 

 

 

The Cotton Valley configuration is flexible, which allows us to respond to market changes and customer demands by modifying its product mix. The reconfigured fractionation train also allows the refinery to satisfy demand fluctuations efficiently without large product inventory requirements.

 

The Cotton Valley refinery receives crude oil via truck and through a pipeline system operated by a subsidiary of Plains All American Pipeline, L.P. (“Plains”). Cotton Valley’s feedstock is primarily low sulfur, paraffinic crude oil originating from north Louisiana and is purchased from various marketers and gatherers. In addition, the refinery receives feedstocks for solvent production from the Shreveport refinery. The Cotton Valley refinery ships finished products throughout the country by both truck and railcar service.

 

Shreveport Refinery

 

The Shreveport refinery, located on a 240-acre site in Shreveport, Louisiana, currently has aggregate crude oil throughput capacity of 60,000 bpd subsequent to the completion of a major expansion project in May 2008 and is

currently processing paraffinic crude oil and associated feedstocks into fuel products, paraffinic lubricating oils, waxes, residuals, and by-products.

 

The Shreveport refinery currently consists of 16 major processing units, approximately 3.4 million barrels of storage capacity in 141 storage tanks and related loading and unloading facilities and utilities. Since our acquisition of the Shreveport refinery in 2001, we have expanded the refinery’s capabilities by adding additional processing and blending facilities, added a second reactor to the high pressure hydrotreater, resumed production of gasoline, diesel and other fuel products at the refinery, and added both 18,000 bpd of capacity and the capability to run up to 25,000 bpd of sour crude oil with the expansion project completed in May 2008. The following table sets forth historical information about production at our Shreveport refinery.

 

 

 

 

We completed an expansion project in May 2008 that increased our Shreveport refinery’s aggregate crude oil throughput capacity from approximately 42,000 bpd to approximately 60,000 bpd. For further discussion of this project, please read Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Capital Expenditures.”

 

The Shreveport refinery has a flexible operational configuration and operating personnel that facilitate development of new product opportunities. Product mix may fluctuate from one period to the next to capture market opportunities. The refinery has an idle residual fluid catalytic cracking unit, alkylation unit, vacuum tower and a number of idle towers that can be utilized for future project needs. Certain idle towers were utilized as a part of the Shreveport refinery expansion project discussed above.

 

The Shreveport refinery currently makes jet fuel, low sulfur diesel and ultra low sulfur diesel and all of its gasoline production currently meets low sulfur standards.

 

The Shreveport refinery receives crude oil from common carrier pipeline systems operated by subsidiaries of Plains and Exxon Mobil Corporation (“ExxonMobil”), each of which are connected to the Shreveport refinery’s facilities. The Plains pipeline system delivers local supplies of crude oil and condensates from north Louisiana and east Texas. The ExxonMobil pipeline system delivers domestic crude oil supplies from south Louisiana and foreign crude oil supplies from the Louisiana Offshore Oil Port (“LOOP”) or other crude oil terminals. In addition, trucks deliver crude oil gathered from local producers to the Shreveport refinery.

 

The Shreveport refinery has direct pipeline access to the TEPPCO Products Partners pipeline (“TEPPCO pipeline”), over which it can ship all grades of gasoline, diesel and jet fuel. The refinery also has direct access to the Red River Terminal facility, which provides the refinery with barge access, via the Red River, to major feedstock and petroleum products logistics networks on the Mississippi River and Gulf Coast inland waterway system. The Shreveport refinery also ships its finished products throughout the country through both truck and railcar service.

Karns City Facility

 

The Karns City facility, located on a 225-acre site in Karns City, Pennsylvania, currently has aggregate base oil throughput of 5,500 bpd and is currently processing white mineral oils, petrolatums, solvents, gelled hydrocarbons, cable fillers, and natural petroleum sulfonates. The Karns City facility consists of seven major processing units including hydrotreating, bender treating, fractionation, acid treating, filtering and blending, approximately 817,000 barrels of storage capacity in 309 tanks and related loading and unloading facilities and utilities. The facility receives its base oil feedstocks by rail 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 of 1,300 bpd and is currently processing white mineral oils, compressor lubricants, and natural petroleum sulfonates. The Dickinson facility consists of three major processing units including acid treating, filtering, and blending, approximately 183,000 barrels of storage capacity in 186 tanks and related loading and unloading facilities and utilities. The facility receives its base oil feedstocks by rail 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.

 

 

 

 

Burnham Terminal and Other Logistics Assets

 

We own and operate a terminal in Burnham, Illinois. The Burnham terminal receives specialty products from each of our refineries and distributes them by truck to our customers in the Upper Midwest and East Coast regions of the United States and in Canada.

 

The terminal includes a tank farm with 67 tanks with aggregate lubricating oil, solvent and specialty product storage capacity of approximately 150,000 barrels as well as blending equipment. The Burnham terminal is complementary to our refineries and plays a key role in moving our products to the end-user market by providing the following services:

 

 

We also lease a fleet of approximately 1,700 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 2008, we purchased 49.4% of our crude oil supply through evergreen crude oil supply contracts, which are typically terminable on 30 days’ notice by either party, approximately 38.3% of our crude oil supply from a subsidiary of Plains under a term contract that became evergreen in July 2008, and the remaining 4.6% of our crude oil supply on the spot market. Legacy Resources supplied us with 7.7% of our crude oil in 2008. In addition, we are purchasing additional crude oil from Legacy Resources in 2009 for our Shreveport refinery. Refer to Item 13, “Certain Relationships, Related Party Transactions and Director Independence — Crude Oil Purchases” for further information on our related party crude oil purchases. We also purchase foreign crude oil when its spot market price is attractive relative to the price of crude oil from domestic sources. We believe that adequate supplies of crude oil will continue to be available to us.

 

Our cost to acquire feedstocks and the price 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 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 2 to 9 years, for feedstocks that are key to the operations of our Karns City and Dickinson facilities. In addition, certain products of our refineries can be used as feedstocks by these facilities. We believe that adequate supplies of feedstocks are available for these facilities.

 

Markets and Customers

 

We produce a full line of specialty products, including lubricating oils, solvents and waxes. Our customers purchase these products primarily as raw material components for basic industrial, consumer and automotive goods. We also produce a variety of fuel products.

 

We have an experienced marketing department with an average industry tenure of 20 years. Our salespeople regularly visit customers and our marketing department works closely with both the laboratories at our refineries and our technical department to help create specialized blends that will work optimally for our customers.

 

Markets

 

Specialty Products.  The specialty products market represents a small portion of the overall petroleum refining industry in the United States. Of the nearly 150 refineries currently in operation in the United States, only a small number of the refineries are considered specialty products producers and only a few compete with us in terms of the number of products produced.

Our specialty products are utilized in applications across a broad range of industries, including in:

 

 

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 2008, about 45.5% of our specialty products were shipped in our fleet of approximately 1,700 leased railcars, about 51.2% of our specialty products shipped in trucks owned and operated by several different third-party carriers and the remaining 3.3% were shipped via water transportation. For shipments outside of North America, which accounted for less than 10% of our consolidated sales in 2008, we ship railcars to several ports where the product is loaded on ships for the customer.

 

Fuel Products.  We produce a variety of fuel and fuel-related products, primarily at our Shreveport refinery.

 

Fuel products produced at the Shreveport refinery can be sold locally or through the TEPPCO pipeline. Local sales are made in the TEPPCO terminal in Bossier City, Louisiana, which is approximately 15 miles from the Shreveport refinery, as well as from our own refinery terminal. Any excess volumes are sold to marketers further up the TEPPCO pipeline.

 

During 2008, we sold approximately 9,400 bpd of gasoline into the Louisiana, Texas and Arkansas markets, and any excess volumes to marketers further up the TEPPCO pipeline. Should the appropriate market conditions arise, we have the capability to redirect and sell additional volumes into the Louisiana, Texas and Arkansas markets rather than transport them to the Midwest. Similar market conditions exist for our diesel production. We sell the majority of our diesel locally but, similar to gasoline, we occasionally sell the excess volumes to marketers further up the TEPPCO pipeline during times of high diesel production or for competitive reasons.

 

The Shreveport refinery also has the capacity to produce about 9,000 bpd of commercial jet fuel that can be marketed to the Barksdale Air Force Base in Bossier City, Louisiana, sold as Jet-A locally or via the TEPPCO pipeline, or transferred to the Cotton Valley refinery to be used 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 1,500 bpd of jet fuel. This contract is effective until April 2009 and is bid annually.

 

Additionally, we produce a number of fuel-related products including fluid catalytic cracking (“FCC”) feedstock, asphalt vacuum residuals and mixed butanes.

 

Vacuum residuals are blended or processed further to make specialty asphalt products. Volumes of vacuum residuals which we cannot process are sold locally into the fuel oil market or sold via railcar to other producers. FCC feedstock is sold to other refiners as a feedstock for their FCC units to make fuel products. Butanes are primarily available in the summer months and are primarily sold to local marketers. If the butanes are not sold they are blended into our gasoline production.

 

Customers

 

Specialty Products.  We have a diverse customer base for our specialty products, with approximately 2,400 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 accounts for more that 10% of our consolidated sales.

 

Fuel Products.  We have a diverse customer base for our fuel products, with approximately 60 active accounts. We are able to sell the majority of the fuel products we produce to the local markets of Louisiana, east Texas and Arkansas. We also have the ability to ship our fuel products to the Midwest through the TEPPCO pipeline should the need arise. During the year ended December 31, 2008, the fuel products segment had one customer,

Murphy Oil U.S.A., which represented approximately 10.5% of consolidated sales due to rising gasoline and diesel prices and increased fuel products sales to this customer. No other fuel products segment customer represented 10% or greater of consolidated sales in each of the three years ended December 31, 2008, 2007 and 2006.

 

Safety and Maintenance

 

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 our assets as required by law or regulation.

 

We are subject to the requirements of Federal Occupational Safety and Health Act (“OSHA”) and comparable state occupational safety statutes. We believe that we have operated in substantial compliance with OSHA requirements, including general industry standards, recordkeeping and reporting, hazard communication and process safety management. We have implemented a quality system that meets the requirements of the QS 9000/ISO-9002 Standard. The integrity of our certification is maintained through surveillance audits by our registrar at regular intervals designed to ensure adherence to the standards. The nature of our business may result in industrial accidents from time to time. It is possible that changes in safety and health regulations or a finding of non-compliance with current regulations could result in additional capital expenditures or operating expenses, as well as fines and penalties.

 

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, Sunoco Lubricants & Special Products 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, Ashland Inc. and ConocoPhillips.

 

Fuel Products.  Our competitors in producing fuels products in the local markets in which we operate include Delek Refining, Ltd. and Lion Oil Company.

 

Our ability to compete effectively depends on our responsiveness to customer needs and our ability to maintain competitive prices and product offerings. We believe that our flexibility and customer responsiveness differentiate us from many of our larger competitors. However, it is possible that new or existing competitors could enter the markets in which we operate, which could negatively affect our financial performance.

 

During 2008, two of our competitors, Citgo Petroleum Corporation and Ashland Inc. announced and have completed plans to cease production of certain specialty product lines, including paraffinic lubricating oils, waxes and solvents at certain of their facilities, thereby reducing overall supply capacity in the specialty products market.

Environmental Matters

 

We operate crude oil and specialty hydrocarbon refining and terminal operations, which are subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations can impair our operations that affect the environment in many ways, such as requiring the acquisition of permits to conduct regulated activities; restricting the manner in which the Company can release materials into the environment; requiring remedial activities or capital expenditures to mitigate pollution from former or current operations; and imposing substantial liabilities on us for pollution resulting from our operations. Certain environmental laws impose joint and several, strict liability for costs required to remediate and restore sites where petroleum hydrocarbons, wastes, or other materials have been released or disposed.

 

Failure to comply with environmental laws and regulations may result in the triggering of administrative, civil and criminal measures, including the assessment of monetary penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or prohibiting some or all of our operations. On occasion, we receive notices of violation, enforcement and other complaints from regulatory agencies alleging non-compliance with applicable environmental laws and regulations. In particular, the Louisiana Department of Environmental Quality (“LDEQ”) has proposed penalties totaling approximately $0.4 million and supplemental projects for the following alleged violations: (i) a May 2001 notification received by the Cotton Valley refinery from the LDEQ regarding several alleged violations of various air emission regulations, as identified in the course of our Leak Detection and Repair program, and also for failure to submit various reports related to the facility’s 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 LDEQ’s file review of the Cotton Valley refinery; (iii) a December 2004 notification received by the Cotton Valley refinery from the LDEQ regarding alleged violations for the construction of a multi-tower pad and associated pump pads without a permit issued by the agency; and (iv) an August 2005 notification received by the Princeton refinery from the LDEQ regarding alleged violations of air emissions regulations, as identified by LDEQ following performance of a compliance review, due to excess emissions and failures to continuously monitor and record air emission levels. We anticipate that any penalties that may be assessed due to the alleged violations at our Princeton refinery as well as the aforementioned penalties related to the Cotton Valley refinery will be consolidated in a settlement agreement that we anticipate executing with the LDEQ in connection with the agency’s “Small Refinery and Single Site Refinery Initiative” described below.

 

The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations and financial position. Moreover, in connection with accidental spills or releases associated with our operations, we cannot assure our unitholders that we will not incur substantial costs and liabilities as a result of such spills or releases, including those relating to claims for damage to property and persons. In the event of future increases in costs, we may be unable to pass on those increases to our customers. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with these requirements will not have a material adverse effect on us, there can be no assurance that our environmental compliance expenditures will not become material in the future.

 

Air

 

Our operations are subject to the federal Clean Air Act, as amended, and comparable state and local laws. The Clean Air Act Amendments of 1990 require most industrial operations in the U.S. to incur capital expenditures to meet the air emission control standards that are developed and implemented by the EPA and state environmental agencies. Under the Clean Air Act, facilities that emit volatile organic compounds or nitrogen oxides face increasingly stringent regulations, including requirements to install various levels of control technology on sources of pollutants. In addition, the petroleum refining sector has come under stringent new EPA regulations, imposing maximum achievable control technology (“MACT”) on refinery equipment emitting certain listed hazardous air pollutants. Some of our facilities have been included within the categories of sources regulated by MACT rules. In addition, air permits are required for our refining and terminal operations that result in the emission of regulated air contaminants. These permits incorporate stringent control technology requirements and are subject to extensive

review and periodic renewal. Excluding consideration of the alleged air violations discussed in this Environmental Matters section for which we are currently discussing settlement with the LDEQ, we believe that we are in substantial compliance with the Clean Air Act and similar state and local laws.

 

The Clean Air Act authorizes the EPA to require modifications in the formulation of the refined transportation fuel products we manufacture in order to limit the emissions associated with the fuel product’s final use. For example, in December 1999, the EPA promulgated regulations limiting the sulfur content allowed in gasoline. These regulations required the phase-in of gasoline sulfur standards beginning in 2004, with special provisions for small refiners and for refiners serving those Western states exhibiting lesser air quality problems. Similarly, the EPA promulgated regulations that limit the sulfur content of highway diesel beginning in 2006 from its former level of 500 parts per million (“ppm”) to 15 ppm (the “ultra low sulfur standard”). The Shreveport refinery has implemented the sulfur standard with respect to gasoline in its production and produces diesel meeting the ultra low sulfur standard.

 

We are party to ongoing discussions on a voluntary basis with the LDEQ regarding the Company’s participation in that agency’s “Small Refinery and Single Site Refinery Initiative.” This state initiative is patterned after the EPA’s “National Petroleum Refinery Initiative,” which is a coordinated, integrated compliance and enforcement strategy to address federal Clean Air Act compliance issues at the nation’s largest petroleum refineries. We expect that the LDEQ’s primary focus under the state initiative will be on four compliance and enforcement concerns: (i) Prevention of Significant Deterioration/New Source Review; (ii) New Source Performance Standards for fuel gas combustion devices, including flares, heaters and boilers; (iii) Leak Detection and Repair requirements; and (iv) Benzene Waste Operations National Emission Standards for Hazardous Air Pollutants. We are in discussions with the LDEQ regarding our participation in this regulatory initiative and anticipate that we will be entering into a settlement agreement with the LDEQ pursuant to which we will be required to make emissions reductions requiring capital investments between approximately $1.0 million and $3.0 million in total over a three to five year period at our three Louisiana refineries. Because the settlement agreement is also expected to resolve the alleged air emissions issues at our Cotton Valley and Princeton refineries and consolidate any penalties associated with such issues, we further anticipate that a penalty of approximately $0.4 million will be assessed in connection with this settlement agreement.

 

We also are in separate discussions with the EPA to resolve alleged deficiencies in risk management planning in connection with a fire-related incident arising out of tank cleaning and vacuum truck operations at our Shreveport refinery on October 30, 2008. The incident involved a third-party contractor and resulted in damage to an on-site aboveground storage tank. Following an investigation of the matter, the EPA issued five violations against us, alleging, among other things, inadequate contractor training and oversight, and has proposed a penalty of $0.2 million. We are currently evaluating our response to the EPA with respect to the matter.

 

Climate Change

 

Recent studies suggest that emissions of carbon dioxide and certain other gases, referred to as “greenhouse gases,” may be contributing to warming of the Earth’s atmosphere. In response, President Obama has expressed support for, and it is anticipated that the current session of Congress will consider, legislation to restrict or regulate emissions of greenhouse gases. In addition, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases. The most frequently utilized model for greenhouse gas emission control is a market-based cap-and-trade system, wherein regulated companies are required to obtain and surrender government-issued emission “allowances” based on the amount of greenhouse gases attributable to their facilities. Depending on how such allowances are allocated (i.e., for free or by auction), and whether a company has enough allowances to cover its greenhouse gas emissions, a company may be required to purchase allowances on the open market.

 

One form of cap-and-trade system that has been proposed is an “upstream” cap-and-trade system, wherein fuel producers, including refiners, would be required to maintain emission allowances covering the greenhouse gas emissions attributable to the combustion of their products. Were an upstream cap-and-trade system to be adopted at either the state, regional, or federal level, we could be required to purchase and surrender allowances for the greenhouse gas emissions attributable to the combustion of the fuels we produce. Although we would not be

impacted to a greater degree than other similarly situated refiners of oil, a stringent greenhouse gas control program could have an adverse effect on our operations, financial condition, and cash flows.

 

Also, as a result of the United States Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may regulate greenhouse gas emissions from mobile sources such as cars and trucks even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court’s holding in Massachusetts that greenhouse gases including carbon dioxide fall under the federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of carbon dioxide and other greenhouse gas emissions from stationary sources. In July 2008, EPA released an “Advance Notice of Proposed Rulemaking” regarding possible future regulation of greenhouse gas emissions under the Clean Air Act, in response to the Supreme Court’s decision in Massachusetts. In the notice, EPA evaluated the potential regulation of greenhouse gases under the Clean Air Act and other potential methods of regulating greenhouse gases. Although the notice did not propose any specific, new regulatory requirements for greenhouse gases, it indicates that federal regulation of greenhouse gas emissions could occur in the near future even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such new federal, regional or state restrictions on emissions of carbon dioxide or other greenhouse gases that may be imposed in areas in which we conduct business could also have an adverse effect on our cost of doing business and demand for the oil we refine.

 

Hazardous Substances and Wastes

 

The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as the “Superfund” law, and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. Such classes of persons include the current and past owners and operators of sites where a hazardous substance was released, and companies that disposed or arranged for disposal of hazardous substances at offsite locations, such as landfills. Under CERCLA, these “responsible persons” may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances into the environment. In the course of our operations, we generate wastes or handle substances that may be regulated as hazardous substances, and we could become subject to liability under CERCLA and comparable state laws.

 

We also may incur liability under the Resource Conservation and Recovery Act (“RCRA”), and comparable state laws, which impose requirements related to the handling, storage, treatment, and disposal of solid and hazardous wastes. In the course of our operations, we generate petroleum product wastes and ordinary industrial wastes, such as paint wastes, waste solvents, and waste oils, that may be regulated as hazardous wastes. In addition, our operations also generate solid wastes, which are regulated under RCRA and state law. We believe that we are in 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. During 2008, we determined that we will incur costs of approximately $0.7 million during 2009 at our Cotton Valley refinery in connection with continued remediation of groundwater impacts at that site.

 

Water

 

The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws impose restrictions and stringent controls on the discharge of pollutants, including oil, into federal and state waters. Such discharges are prohibited, except in accordance with the terms of a permit issued by the EPA or the appropriate state agencies. Any unpermitted release of pollutants, including crude or hydrocarbon specialty oils as well as refined products, could result in penalties, as well as significant remedial obligations. Spill prevention, control, and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak. We believe that we are in substantial compliance with the requirements of the Clean Water Act.

 

The primary federal law for oil spill liability is the Oil Pollution Act of 1990, as amended (“OPA”), which addresses three principal areas of oil pollution — prevention, containment, and cleanup. OPA applies to vessels, offshore facilities, and onshore facilities, including refineries, terminals, and associated facilities that may affect waters of the U.S. Under OPA, responsible parties, including owners and operators of onshore facilities, may be subject to oil cleanup costs and natural resource damages as well as a variety of public and private damages from oil spills. We believe that we are in substantial compliance with OPA and similar state laws.

 

Health and Safety

 

We are subject to various laws and regulations relating to occupational health and safety including OSHA, and comparable state laws. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We maintain safety, training, and maintenance programs as part of our ongoing efforts to ensure compliance with applicable laws and regulations. Our compliance with applicable health and safety laws and regulations has required and continues to require substantial expenditures. We have commissioned studies to assess the adequacy of our process safety management practices at our Shreveport refinery. Depending on the findings made in these studies, we may incur capital expenditures over the next several years to enhance these practices so that we may maintain our compliance with applicable OSHA regulations at this refinery. While we do not expect these expenditures to be material at this time, we have not yet received the reports from the engineering firms conducting the studies to reach final resolution. We believe that our operations are in substantial compliance with OSHA and similar state laws.

 

Other Environmental Items

 

We are indemnified by Shell Oil Company, as successor to Pennzoil-Quaker State Company and Atlas Processing Company, for specified environmental liabilities arising from operations of the Shreveport refinery prior to our acquisition of the facility. The indemnity is unlimited in amount and duration, but requires us to contribute up to $1.0 million of the first $5.0 million of indemnified costs for certain of the specified environmental liabilities.

 

We are indemnified on a limited basis by ConocoPhillips and M.E. Zuckerman Specialty Oil Corporation, former owners of Penreco, for pending, threatened, contemplated or contingent environmental claims against Penreco of which we were unaware upon our acquisition of Penreco. A significant portion of these indemnifications will expire in January 2010 without any claims having been asserted by us and are generally subject to a $2.0 million limit.

 

Insurance

 

Our operations are subject to certain hazards of operations, including fire, explosion and weather-related perils. We maintain insurance policies, including business interruption insurance for each of our facilities, with

insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent. We cannot, however, ensure that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices. We are not fully insured against certain risks because such risks are not fully insurable, coverage is unavailable, or premium costs, in our judgment, do not justify such expenditures.

 

Seasonality

 

The operating results for the fuel products segment and the selling prices of asphalt products we produce can be seasonal. Asphalt demand is generally lower in the first and fourth quarters of the year as compared to the second and third quarters due to the seasonality of annual road construction. Demand for gasoline is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic. In addition, our natural gas costs can be higher during the winter months. As a result, our operating results for the first and fourth calendar quarters may be lower than those for the second and third calendar quarters of each year as a result of 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Debt and Credit Facilities.”

 

 

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 and approximately 14,500 square feet of office space in The Woodlands, Texas under a lease as a result of the Penreco acquisition that we are currently not using. While we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet our needs for the immediate future and that additional facilities will be available on commercially reasonable terms as needed. We expect that we will not renew our lease of our facility in The Woodlands, Texas at its expiration on April 30, 2012 and are actively engaged in efforts to sublease this office space for the remainder of the lease term.

 

Employees

 

As of February 26, 2009, our general partner employs approximately 640 people who provide direct support to the Company’s operations. Of these employees, approximately 360 are covered by collective bargaining agreements, including approximately 140 employees at the facilities acquired in the Penreco acquisition. Employees at the Princeton and Cotton Valley refineries are covered by separate collective bargaining agreements with the International Union of Operating Engineers, having expiration dates of October 31, 2011 and March 31, 2010, respectively. Employees at the Shreveport refinery are covered by a collective bargaining agreement with the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied-Industrial, and Service Workers International Union which expires on April 30, 2010. The Karns City, Pennsylvania facility employees are covered by a collective bargaining agreement with United Steel Workers that will expire on January 31, 2012. The Dickinson, Texas facility employees are covered by a collective bargaining agreement with the International Union of Operating Engineers that will expire in March 31, 2010. 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:

 

 

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 in print to anyone who requests it and is free of charge.

 

 

We may not have sufficient cash from operations to enable us to pay the minimum quarterly distribution following the establishment of cash reserves and payment of fees and expenses, including payments to our general partner.

 

We may not have sufficient available cash from operations each quarter to enable us to pay the minimum quarterly distribution. Under the terms of our partnership agreement, we must pay expenses, including payments to our general partner, and set aside any cash reserve amounts before making a distribution to our unitholders. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which is primarily dependent upon our producing and selling quantities of fuel and specialty products, or refined products, at margins that are high enough to cover our fixed and variable expenses. Crude oil costs, fuel and specialty products prices and, accordingly, the cash we generate from operations, will fluctuate from quarter to quarter based on, among other things:

 

 

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:

 

 

 

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.

 

Further 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, either of which would adversely affect our liquidity, financial condition and our ability to distribute cash to our unitholders.

 

The borrowing base under our revolving credit facility is redetermined weekly or monthly depending upon availability levels. Reductions in the value of our inventories as a result of lower crude oil prices could result in a reduction in our borrowing base, which would reduce our amount of financial resources available to meet our capital requirements. Further, if at any time our available capacity under our revolving credit facility falls below $35.0 million, we may be required by our lenders to take steps to reduce our leverage, pay off our debts on an accelerated basis, limit or eliminate distributions to our unitholders or take other similar measures. In addition, as a result of further decreases in the price of crude oil, we may be required to post substantial amounts of cash collateral to our hedging counterparties in order to maintain our hedging positions. At December 31, 2008, we had $51.9 million in availability under our revolving credit facility. Please read Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Debt and Credit Facilities” for additional information. If the borrowing base under our revolving credit facility decreases or we are required to post substantial amounts of cash collateral to our hedging counterparties, it would have a material adverse effect on our liquidity, financial condition and our ability to distribute cash to our unitholders.

 

Our credit agreements contain operating and financial restrictions that may restrict our business and financing activities.

 

The operating and financial restrictions and covenants in our credit agreements and any future financing agreements could restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities. For example, our credit agreements restrict our ability to:

 

 

Our ability to comply with the covenants and restrictions contained in our credit agreements may be affected by events beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our credit agreements, a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions may be inhibited and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit agreements are secured by substantially all of our assets and if we are unable to repay our indebtedness under our credit agreements, the lenders could seek to foreclose on our assets.

 

The new senior secured term loan credit agreement and amendment to our existing revolving credit facility that we executed on January 3, 2008 contain operating and financial restrictions similar to the above listed items. Financial covenants in the term loan credit agreement and the amended revolving credit facility agreement include a maximum consolidated leverage ratio of not more than 4.00 to 1.00 with a step down to 3.75 to 1.00 beginning with the quarter ended June 30, 2009 and a minimum consolidated interest coverage ratio of not less than 2.50 to 1.00 which increases to 2.75 to 1.00 beginning with the quarter ended June 30, 2009. 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.

 

We may not be able to obtain funding, obtain funding on acceptable terms or obtain funding under our revolving credit facility because of deterioration of the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.

 

Global financial market and economic conditions have been, and continue to be, disrupted and volatile. The debt and equity capital markets have been exceedingly distressed. These issues, along with significant write-offs in the financial services sector, the re-pricing of credit risk and the current weak economic conditions have made, and will likely continue to make, it difficult to obtain funding.

 

In particular, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and reduced and, in some cases, ceased to provide funding to borrowers.

 

In addition, we may be unable to obtain adequate funding under our revolving credit facility because (i) our lending counterparties may be unwilling or unable to meet their funding obligations or (ii) our borrowing base under our revolving credit facility is redetermined weekly or monthly depending upon availability levels and may decrease as a result of changes in selling prices of our products, our current material costs (primarily crude oil), lending requirements or regulations, or for any other reason.

 

Due to these factors, we cannot be certain that funding will be available if needed and to the extent required, on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due or be required to post collateral to support our obligations, or we may be unable to implement our business development plans, enhance our existing business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations.

 

Refining margins are volatile, and a reduction in our refining margins will adversely affect the amount of cash we will have available for distribution to our unitholders.

 

Historically, refining margins have been volatile, and they are likely to continue to be volatile in the future. Our financial results are primarily affected by the relationship, or margin, between our specialty products prices and fuel

products prices and the prices for crude oil and other feedstocks. The cost to acquire our feedstocks and the price at which we can ultimately sell our refined products depend upon numerous factors beyond our control.

 

A widely used benchmark in the fuel products industry to measure market values and margins is the “Gulf Coast 3/2/1 crack spread,” which represents the approximate gross margin resulting from refining crude oil, assuming that three barrels of a benchmark crude oil are converted, or cracked, into two barrels of gasoline and one barrel of heating oil. The Gulf Coast 3/2/1 crack spread, as reported by Bloomberg L.P., has averaged as follows:

 

 

Our actual refining margins vary from the Gulf Coast 3/2/1 crack spread due to the actual crude oil used and products produced, transportation costs, regional differences, and the timing of the purchase of the feedstock and sale of the refined products, but we use the Gulf Coast 3/2/1 crack spread as an indicator of the volatility and general levels of refining margins.

 

The prices at which we sell specialty products are strongly influenced by the commodity price of crude oil. If crude oil prices increase, our specialty products segment’s 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 the increased crude oil costs to our customers. In addition, we will not be able to completely eliminate our commodity risk through our hedging activities.

 

Because refining margins are volatile, unitholders should not assume that our current margins will be sustained. If our refining margins fall, it will adversely affect the amount of cash we will have available for distribution to our unitholders.

 

Because of the volatility of crude oil and refined products prices, our method of valuing our inventory may result in decreases in net income.

 

The nature of our business requires us to maintain substantial quantities of crude oil and refined product inventories. Because crude oil and refined products are essentially commodities, we have no control over the changing market value of these inventories. Because our inventory is valued at the lower of cost or market value, if the market value of our inventory were to decline to an amount less than our cost, we would record a write-down of inventory and a non-cash charge to cost of sales. In a period of decreasing crude oil or refined product prices, our inventory valuation methodology may result in decreases in net income.

 

The price volatility of fuel and utility services may result in decreases in our earnings, profitability and cash flows.

 

The volatility in costs of fuel, principally natural gas, and other utility services, principally electricity, used by our refinery and other operations affect our net income and cash flows. Fuel and utility prices are affected by factors outside of our control, such as supply and demand for fuel and utility services in both local and regional markets.

Natural gas prices have historically been volatile. For example, daily prices for natural gas as reported on the New York Mercantile Exchange (“NYMEX”) ranged between $5.29 and $13.58 per million British thermal unit, or MMBtu, in 2008 and between $5.38 and $8.64 per MMBtu in 2007. 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 36.5% and 44.2% of our total operating expenses included in cost of sales for the years ended December 31, 2008 and 2007, respectively. If our natural gas costs rise, it will adversely affect the amount of cash we will have available for distribution to our unitholders.

 

Our hedging activities may not be effective in reducing the volatility of our cash flows and may reduce our earnings, profitability and cash flows.

 

We are exposed to fluctuations in the price of crude oil, fuel products, natural gas and interest rates. We utilize derivative financial instruments related to the future price of crude oil, natural gas and fuel products with the intent of reducing volatility in our cash flows due to fluctuations in commodity prices and derivative instruments related to interest rates for future periods with the intent of reducing volatility in our cash flows due to fluctuations in interest rates. We are not able to enter into derivative financial instruments to reduce the volatility of the prices of the specialty hydrocarbon products we sell as there is no established derivative market for such products.

 

The extent of our commodity price exposure is related largely to the effectiveness and scope of our hedging activities. For example, the derivative instruments we utilize are based on posted market prices, which may differ significantly from the actual crude oil prices, natural gas prices or fuel products prices that we incur or realize in our operations. Accordingly, our commodity price risk management policy may not protect us from significant and sustained increases in crude oil or natural gas prices or decreases in fuel products prices. Conversely, our policy may limit our ability to realize cash flows from crude oil and natural gas price decreases.

 

We have a policy to enter into derivative transactions related to only a portion of the volume of our expected purchase and sales requirements and, as a result, we will continue to have direct commodity price exposure to the unhedged portion of our expected purchase and sales requirements. For example, we historically have entered into monthly crude oil collars to hedge up to 14,000 bpd of crude purchases related to our specialty products segment, which had average total daily production for 2008 of 30,159 bpd. As of December 31, 2008, we had significantly reduced the volume and duration of our crude oil collars position and were hedging approximately 7,700 bpd through March 31, 2009. Thus, we could be exposed to significant crude oil cost increases on a portion of our purchases. Please read Item 7A “Quantitative and Qualitative Disclosures about Market Risk.”

 

Our actual future purchase and sales requirements may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, which may result in a substantial diminution of our liquidity. As a result, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows. In addition, our hedging activities are subject to the risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms of the derivative instruments are imperfect, and our hedging policies and procedures are not properly followed. It is possible that the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.

 

Our acquisition, asset reconfiguration and enhancement initiatives may not result in revenue or cash flow increases, may be subject to significant cost overruns and are subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our business, operating results, cash flows and financial condition.

 

We plan to grow our business in part through acquisition and the reconfiguration and enhancement of our existing refinery assets. As a specific example, we completed an expansion project at our Shreveport refinery to increase throughput capacity and crude oil processing flexibility in May 2008. This construction project and the

construction of other additions or modifications to our existing refineries have and will continue to involve numerous regulatory, environmental, political, legal, labor and economic uncertainties beyond our control, which could cause delays in construction or require the expenditure of significant amounts of capital, which we may finance with additional indebtedness or by issuing additional equity securities. For example, the Shreveport expansion project total cost was approximately $375.0 million and was significantly over budget due to increased construction labor costs. Future acquisition, reconfiguration and enhancement projects may not be completed at the budgeted cost, on schedule, or at all due to the risks described above which would significantly affect our cash flows and financial condition.

 

Our acquisition of Penreco could expose us to potential significant liabilities.

 

In connection with the Penreco acquisition, we purchased all of the partnership interests of Penreco rather than just its assets. As a result, we purchased the liabilities of Penreco subject to certain exclusions in the purchase and sale agreement, including unknown and contingent liabilities. We performed a certain level of due diligence in connection with the Penreco acquisition and attempted to verify the representations of the sellers and of Penreco management, but there may be pending, threatened, contemplated or contingent claims against Penreco related to environmental, title, regulatory, litigation or other matters of which we are unaware. Although the sellers agreed to indemnify us on a limited basis against some of these liabilities, a significant portion of these indemnification obligations will expire two years after the date the acquisition is completed without any claims having been asserted by us and these obligations are subject to limits. Each seller’s liability is limited to 50% of our loss. Each seller’s indemnification obligations are generally subject to a limit of $2.0 million limit for most matters and a deductible of $1.0 million per claim, or $10.0 million for all claims in the aggregate. We may not be able to collect on such indemnification because of disputes with the sellers or their inability to pay. Moreover, there is a risk that we could ultimately be liable for unknown obligations of Penreco, which could materially adversely affect our operations and financial condition.

 

Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.

 

We had approximately $477.6 million of outstanding indebtedness under our credit facilities as of December 31, 2008 and availability for borrowings of $51.9 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 “Management’s 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:

 

 

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.

 

Our recently acquired Penreco facilities are dependent upon ConocoPhillips for a majority of their feedstocks, and the balance of its feedstocks are not secured by long-term contracts and are subject to price increases and availability. To the extent we are unable to obtain necessary feedstocks, operations will be adversely affected.

 

Our Penreco facilities receive the majority of their feedstocks from ConocoPhillips pursuant to long-term supply contracts. In addition, one particular feedstock is produced at a unit operated by ConocoPhillips within one of its refineries, which has shut down production in the past under the force majeure provisions of a supply contract. In addition, we do not have long-term contracts with most of our other suppliers. Each of our Penreco facilities is dependent on these suppliers and the loss of these suppliers would adversely affect our financial results to the extent we were unable to find replacement suppliers.

 

We may be unable to consummate potential acquisitions we identify or successfully integrate such acquisitions.

 

We regularly consider and enter into discussions regarding potential acquisitions that we believe are complementary to our business. Any such purchase is subject to substantial due diligence, the negotiation of a definitive purchase and sale agreement and ancillary agreements, including, but not limited to supply, transition services and licensing agreements, and the receipt of various board of directors, governmental and other approvals. In the alternative, if we are successful in closing any such acquisitions, we will be subject to many risks including integration risks and the risk that a substantial portion of an acquired business may not produce “qualifying income” for purposes of the Internal Revenue Code. If our non-qualifying income exceeds 10% we would lose our election to be treated as a partnership for tax purposes and will be taxed as a corporation.

 

If our general financial condition deteriorates, we may be limited in our ability to issue letters of credit which may affect our ability to enter into hedging arrangements, to enter into leasing arrangements, or to purchase crude oil.

 

We rely on our ability to issue letters of credit to enter into hedging arrangements in an effort to reduce our exposure to adverse fluctuations in the prices of crude oil, natural gas and crack spreads. We also rely on our ability to issue letters of credit to purchase crude oil for our refineries, lease certain precious metals for use in our refinery operations and enter into cash flow hedges of crude oil and natural gas purchases and fuel products sales. If, due to our financial condition or other reasons, we are limited in our ability to issue letters of credit or we are unable to issue letters of credit at all, we may be required to post substantial amounts of cash collateral to our hedging counterparties, lessors or crude oil suppliers in order to continue these activities, which would adversely affect our liquidity and our ability to distribute cash to our unitholders.

 

We depend on certain key crude oil gatherers for a significant portion of our supply of crude oil, and the loss of any of these key suppliers or a material decrease in the supply of crude oil generally available to our refineries could materially reduce our ability to make distributions to unitholders.

 

We purchase crude oil from major oil companies as well as from various gatherers and marketers in east Texas and north Louisiana. In 2008, subsidiaries of Plains and Genesis Crude Oil, L.P. supplied us with approximately 59.1% and 6.2%, respectively, of our total crude oil supplies under term contracts and evergreen crude oil supply contracts. In addition, we received 7.7% of our total crude oil purchases from Legacy Resources, an affiliate of our general partner, in 2008 and we have expanded our supply from Legacy Resources in January 2009 through the execution of an additional crude oil supply contract. Each of our refineries is dependent on one or all of these suppliers and the loss of any of these suppliers would adversely affect our financial results to the extent we were unable to find another supplier of this substantial amount of crude oil. We do not maintain long-term contracts with most of our suppliers. Please read Items 1 and 2 “Business and Properties — Crude Oil and Feedstock Supply.”

To the extent that our suppliers reduce the volumes of crude oil that they supply us as a result of declining production or competition or otherwise, our revenues, net income and cash available for distribution would decline unless we were able to acquire comparable supplies of crude oil on comparable terms from other suppliers, which may not be possible in areas where the supplier that reduces its volumes is the primary supplier in the area. A material decrease in crude oil production from the fields that supply our refineries, as a result of depressed commodity prices, lack of drilling activity, natural production declines or otherwise, could result in a decline in the volume of crude oil we refine. Fluctuations in crude oil prices can greatly affect production rates and investments by third parties in the development of new oil reserves. Drilling activity generally decreases as crude oil prices decrease. We have no control over the level of drilling activity in the fields that supply our refineries, the amount of reserves underlying the wells in these fields, the rate at which production from a well will decline or the production decisions of producers, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, geological considerations, governmental regulation and the availability and cost of capital.

 

We are dependent on certain third-party pipelines for transportation of crude oil and refined products, and if these pipelines become unavailable to us, our revenues and cash available for distribution could decline.

 

Our Shreveport refinery is interconnected to pipelines that supply most of its crude oil and ship a portion of its refined fuel products to customers, such as pipelines operated by subsidiaries of TEPPCO Partners, L.P. and ExxonMobil. Since we do not own or operate any of these pipelines, their continuing operation is not within our control. If any of these third-party pipelines become unavailable to transport crude oil or our refined fuel products because of accidents, government regulation, terrorism or other events, our revenues, net income and cash available for distribution could decline.

 

Distributions to unitholders could be adversely affected by a decrease in the demand for our specialty products.

 

Changes in our customers’ products or processes may enable our customers to reduce consumption of the specialty products that we produce or make our specialty products unnecessary. Should a customer decide to use a different product due to price, performance or other considerations, we may not be able to supply a product that meets the customer’s new requirements. In addition, the demand for our customers’ end products could decrease, which would reduce their demand for our specialty products. Our specialty products customers are primarily in the industrial goods, consumer goods and automotive goods industries and we are therefore susceptible to changing demand patterns and products in those industries. Consequently, it is important that we develop and manufacture new products to replace the sales of products that mature and decline in use. If we are unable to manage successfully the maturation of our existing specialty products and the introduction of new specialty products our revenues, net income and cash available for distribution to unitholders could be reduced.

 

Distributions to unitholders could be adversely affected by a decrease in demand for fuel products in the markets we serve.

 

Any sustained decrease in demand for fuel products in the markets we serve could result in a significant reduction in our cash flows, reducing our ability to make distributions to unitholders. Factors that could lead to a decrease in market demand include:

 

 

 

We could be subject to damages based on claims brought against us by our customers or lose customers as a result of the failure of our products to meet certain quality specifications.

 

Our specialty products provide precise performance attributes for our customers’ products. If a product fails to perform in a manner consistent with the detailed quality specifications required by the customer, the customer could seek replacement of the product or damages for costs incurred as a result of the product failing to perform as guaranteed. A successful claim or series of claims against us could result in a loss of one or more customers and reduce our ability to make distributions to unitholders.

 

We are subject to compliance with stringent environmental, health and safety laws and regulations that may expose us to substantial costs and liabilities.

 

Our crude oil and specialty hydrocarbon refining and terminal operations are subject to stringent and complex federal, state and local environmental, health and safety laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection, worker health and safety. These laws and regulations impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of significant capital expenditures to limit or prevent releases of materials from our refineries, terminal, and related facilities, and the incurrence of substantial costs and liabilities for pollution resulting both from our operations and from those of prior owners. Numerous governmental authorities, such as the EPA, OSHA, and state agencies, such as the LDEQ, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. Failure to comply with laws, regulations, permits and orders may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations. Described below are examples of these costs and liabilities.

 

We are in discussions with the LDEQ regarding our participation in the Small Refinery and Single Site Refinery Initiative and anticipate that we will be entering into a settlement agreement with the LDEQ pursuant to which we will be required to make emissions reductions requiring capital investments between approximately $1.0 million and $3.0 million over a three to five year period at our three Louisiana refineries. Because the settlement agreement is also expected to resolve alleged air emissions issues at our Cotton Valley and Princeton refineries and consolidate any penalties associated with such issues, we further anticipate that a penalty of approximately $0.4 million will be assessed in connection with this settlement agreement.

 

We have commissioned studies to assess the adequacy of our process safety management practices at our Shreveport refinery. Depending on the findings made in these studies, we may incur capital expenditures over the next several years to enhance these practices so that we may maintain our compliance with applicable OSHA regulations at the refinery. While we do not expect these expenditures to be material at this time, we have not completed our negotiations with OSHA to reach final resolution.

 

Our business subjects us to the inherent risk of incurring significant environmental liabilities in the operation of our refineries and related facilities.

 

There is inherent risk of incurring significant environmental costs and liabilities in the operation of our refineries, terminal, and related facilities due to our handling of petroleum hydrocarbons and wastes, air emissions and water discharges related to our operations, and historical operations and waste disposal practices by prior owners. We currently own or operate properties that for many years have been used for industrial activities, including refining or terminal storage operations. Petroleum hydrocarbons or wastes have been released on or under 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.

 

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 will be limited. Furthermore, any acquisition involves potential risks, including, among other things:

 

 

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of our funds and other resources.

 

Our refineries, facilities and terminal operations face operating hazards, and the potential limits on insurance coverage could expose us to potentially significant liability costs.

 

Our operations are subject to significant interruption, and our cash from operations could decline if any of our facilities experiences a major accident or fire, is damaged by severe weather or other natural disaster, or otherwise is forced to curtail its operations or shut down. These hazards could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations.

We are not fully insured against all risks incident to our business. Furthermore, we may be unable to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Our business interruption insurance will not apply unless a business interruption exceeds 90 days. We are not insured for environmental accidents. If we were to incur a significant liability for which we were not fully insured, it could diminish our ability to make distributions to unitholders.

 

Downtime for maintenance at our refineries and facilities will reduce our revenues and cash available for distribution.

 

Our refineries and facilities consist of many processing units, a number of which have been in operation for a long time. One or more of the units may require additional unscheduled downtime for unanticipated maintenance or repairs that are more frequent than our scheduled turnaround for each unit every one to five years. Scheduled and unscheduled maintenance reduce our revenues during the period of time that our processing units are not operating and could reduce our ability to make distributions to our unitholders.

 

We are subject to strict regulations at many of our facilities regarding employee safety, and failure to comply with these regulations could reduce our ability to make distributions to our unitholders.

 

The workplaces associated with the facilities we operate are subject to the requirements of the federal OSHA and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that we maintain information about hazardous materials used or produced in our operations and that we provide this information to employees, state and local government authorities, and local residents. Failure to comply with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances could reduce our ability to make distributions to our unitholders if we are subjected to fines or significant compliance costs.

 

We face substantial competition from other refining companies.

 

The refining industry is highly competitive. Our competitors include large, integrated, major or independent oil companies that, because of their more diverse operations, larger refineries and stronger capitalization, may be better positioned than we are to withstand volatile industry conditions, including shortages or excesses of crude oil or refined products or intense price competition at the wholesale level. If we are unable to compete effectively, we may lose existing customers or fail to acquire new customers. For example, if a competitor attempts to increase market share by reducing prices, our operating results and cash available for distribution to our unitholders could be reduced.

 

An increase in interest rates will cause our debt service obligations to increase.

 

Borrowings under our revolving credit facility bear interest at a floating rate (3.75% as of December 31, 2008). Borrowings under our term loan facility bear interest at a floating rate (6.15% as of December 31, 2008). The interest rates are subject to adjustment based on fluctuations in the London Interbank Offered Rate (“LIBOR”) or prime rate. The interest rate under our term loan credit facility, entered into on January 3, 2008, is LIBOR plus 4.0%. An increase in the interest rates associated with our floating-rate debt would increase our debt service costs and affect our results of operations and cash flow available for distribution to our unitholders. In addition, an increase in interest rates could adversely affect our future ability to obtain financing or materially increase the cost of any additional financing.

 

Due to our lack of asset and geographic diversification, adverse developments in our operating areas would reduce our ability to make distributions to our unitholders.

 

We rely exclusively on sales generated from products processed at the facilities we own. Furthermore, the majority of our assets and operations are located in northwest Louisiana. Due to our lack of diversification in asset type and location, an adverse development in these businesses or areas, including adverse developments due to

catastrophic events or weather, decreased supply of crude oil 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 and Shreveport refineries are employed under collective bargaining agreements that expire in October 2011, March 2010 and April 2010, respectively. Substantially all of the operating personnel acquired through the Penreco acquisition are employed under collective bargaining agreements that expire in January 2012 and March 2010. 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 fuels 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.

 

If we fail to maintain an effective system of internal controls, we may not be able to report our financial results accurately, or prevent fraud which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.

 

Effective internal controls are necessary for us to provide reliable financial reports to prevent fraud and to operate successfully as a publicly traded partnership. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain adequate controls over our financial processes and reporting in the future, including compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as Section 404. For example, Section 404 requires us, among other things, annually to review and report on, and our independent registered public accounting firm annually to attest to, our internal control over financial reporting. Any failure to develop or maintain effective controls, or difficulties encountered in their implementation or other effective improvement of our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.

Risks Inherent in an Investment in Us

 

The families of our chairman and chief executive officer and president, The Heritage Group and certain of their affiliates own a 58.2% limited partner interest in us and own and control our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to other unitholders’ detriment.

 

The families of our chairman and chief executive officer and president, the Heritage Group, and certain of their affiliates own a 58.2% limited partner interest in us. In addition, The Heritage Group and the families of our chairman and chief executive officer and president own our general partner. Conflicts of interest may arise between our general partner and its affiliates, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, the general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:

 

 

The Heritage Group and certain of its affiliates may engage in limited competition with us.

 

Pursuant to the omnibus agreement we entered into in connection with our initial public offering, The Heritage Group and its controlled affiliates have agreed not to engage in, whether by acquisition or otherwise, the business of refining or marketing specialty lubricating oils, solvents and wax products as well as gasoline, diesel and jet fuel products in the continental United States (“restricted business”) for so long as it controls us. This restriction does not apply to certain assets and businesses which are more fully described under Item 13 “Certain Relationships, Related Party 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 partner’s 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:

 

 

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 management’s decisions regarding our business. Unitholders do not elect our general partner or its board of directors, and have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen by the members of our general partner. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they have little ability to remove our general partner. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

 

Even if unitholders are dissatisfied, they cannot remove our general partner without its consent.

 

The unitholders are unable to remove the general partner without its consent because the general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 662/3% of all outstanding units voting together as a single class is required to remove the general partner. The owners of our general partner and certain of their affiliates own 58.2% of our common and subordinated units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on the common units will be extinguished. A removal of the general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.

Cause is narrowly defined in our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner during the subordination period because of the unitholders’ dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period.

 

Our partnership agreement restricts the voting rights of those unitholders owning 20% or more of our common units.

 

Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

 

Control of our general partner may be transferred to a third party without unitholder consent.

 

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the members of our general partner from transferring their respective membership interests in our general partner to a third party. The new members of our general partner would then be in a position to replace the board of directors and officers of our general partner with their own choices and thereby control the decisions taken by the board of directors.

 

We do not have our own officers and employees and rely solely on the officers and employees of our general partner and its affiliates to manage our business and affairs.

 

We do not have our own officers and employees and rely solely on the officers and employees of our general partner and its affiliates to manage our business and affairs. We can provide no assurance that our general partner will continue to provide us the officers and employees that are necessary for the conduct of our business nor that such provision will be on terms that are acceptable to us. If our general partner fails to provide us with adequate personnel, our operations could be adversely impacted and our cash available for distribution to unitholders could be reduced.

 

We may issue additional common units without unitholder approval, which would dilute our current unitholders’ existing ownership interests.

 

In general, during the subordination period, we may issue up to 6,533,000 additional common units without obtaining unitholder approval, which units we refer to as the “basket.” Our general partner can also issue an unlimited number of common units in connection with accretive acquisitions and capital improvements that increase cash flow from operations per unit on an estimated pro forma basis. We can also issue additional common units if the proceeds are used to repay certain of our indebtedness.

 

The issuance of additional common units or other equity securities of equal or senior rank to the common units will have the following effects:

 

 

After the end of the subordination period, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Our partnership agreement does not give our unitholders the right to approve our issuance of equity securities ranking junior to the common units at any time. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities, which may effectively rank senior to the common units.

 

Our general partner’s determination of the level of cash reserves may reduce the amount of available cash for distribution to unitholders.

 

Our partnership agreement requires our general partner to deduct from operating surplus cash reserves that it establishes are necessary to fund our future operating expenditures. In addition, our partnership agreement also permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These reserves will affect the amount of cash available for distribution to unitholders.

 

Cost reimbursements due to our general partner and its affiliates will reduce cash available for distribution to unitholders.

 

Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf. Any such reimbursement will be determined by our general partner and will reduce the cash available for distribution to unitholders. These expenses will include all costs incurred by our general partner and its affiliates in managing and operating us. Please read Item 13 “Certain Relationships, Related Party 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. Our general partner and its affiliates own approximately 31.7% of the common units. At the end of the subordination period, assuming no additional issuances of common units, our general partner and its affiliates will own approximately 59.4% 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:

 

 

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

 

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, which we call the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Purchasers of units who become limited partners are liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to the purchaser of the units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

 

Our common units have a limited trading history compared to other units representing limited partner interests.

 

Our common units are traded publicly on the NASDAQ Global Market under the symbol “CLMT.” However, our common units have a limited trading history and low average daily trading volume compared to many other units representing limited partner interests quoted on the NASDAQ. The price of our common units may continue to be volatile.

 

The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:

 

 

Tax Risks to Common Unitholders

 

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service, or IRS, treats us as a corporation or we become subject to additional amounts of entity-level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to common unitholders.

 

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes.

 

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we are so treated, a change in our business (or a change in current law) could

cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

 

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35% and would likely pay state income tax at varying rates. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to the unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, our treatment as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

 

Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. At a state level, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, beginning in 2008, we are required to pay Texas franchise tax at a maximum effective rate of 0.7% of our gross income apportioned to Texas in the prior year. Imposition of such a tax on us by Texas and, if applicable, by any other state will reduce the cash available for distribution to unitholders.

 

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution levels will be adjusted to reflect the impact of that law on us.

 

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

 

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, members of Congress have recently considered substantive changes to the existing federal income tax laws that would have affected certain publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Although the considered legislation would not have appeared to affect our tax treatment as a partnership, we are unable to predict whether any of these changes, or other proposals, will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

 

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution.

 

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

 

Unitholders may be required to pay taxes on income from us even if they do not receive any cash distributions from us.

 

Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

Tax gain or loss on disposition of common units could be more or less than expected.

 

If unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount they realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the units sold will, in effect, become taxable income to unitholders if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if unitholders sell their units they may incur a tax liability in excess of the amount of cash they receive from the sale.

 

Tax-exempt entities and non-United States persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

 

Investment in our common units by tax-exempt entities, such as individual retirement accounts (“IRAs”), other retirement plans, and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal tax returns and pay tax on their share of our taxable income. Tax-exempt entities and non-U.S. persons should consult their tax advisors before investing in our common units.

 

We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

 

Because we cannot match transferors and transferees of common units and because of other reasons, we take depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns.

 

We have a subsidiary that is treated as a corporation for federal income tax purposes and subject to corporate-level income taxes.

 

We conduct all or a portion of our operations in which we market finished petroleum products to certain end-users through a subsidiary that is organized as a corporation. We may elect to conduct additional operations through this corporate subsidiary in the future. This corporate subsidiary is subject to corporate-level tax, which will reduce the cash available for distribution to us and, in turn, to our unitholders. If the IRS were to successfully assert that this corporation has more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, our cash available for distribution to our unitholders would be further reduced.

 

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

 

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

 

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

 

We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

 

When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methodologies, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.

 

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

 

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

 

We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders which could result in us filing two tax returns (and unitholders receiving two Schedule K-1s) for one fiscal year. Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.

 

Unitholders may be subject to state and local taxes and return filing requirements.

 

In addition to federal income taxes, our common unitholders will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if unitholders do not live in any of those jurisdictions. Our common unitholders will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, unitholders may be subject

to penalties for failure to comply with those requirements. We own assets and/or do business in Arkansas, Arizona, California, Connecticut, Delaware, Florida, Georgia, Indiana, Illinois, Kansas, Kentucky, Louisiana, Massachusetts, Michigan, Minnesota, Mississippi, Missouri, New Jersey, New York, Ohio, Oregon, Pennsylvania, South Carolina, Texas, Utah, Virginia and Wisconsin. Each of these states, other than Texas and Florida, currently imposes a personal income tax as well as an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or do business in additional states that impose a personal income tax. It is the responsibility of our common unitholders to file all United States federal, foreign, state and local tax returns.

 

 

None.

 

 

We are not a party to any material litigation. Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. Please see Items 1 and 2 “Business and Properties — Environmental Matters” for a description of our current regulatory matters related to the environment.

 

 

None.

 

 

Market Information

 

Our common units are quoted and traded on the NASDAQ Global 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, 2008 and 2007, identical cash distributions per unit were paid among all outstanding common and subordinated units.

 

 

As of February 26, 2009, 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 26, 2009, there were 32,232,000 units outstanding. The number of units outstanding on this date includes the 13,066,000 subordinated units for which there is no

established trading market. The last reported sale price of our common units by NASDAQ on February 26, 2009 was $12.16.

 

On November 20, 2007, we completed a follow-on public offering of common units in which we sold 2,800,000 common units to the underwriters of this offering at a price to the public of $36.98 per common unit and received net proceeds of $98.2 million. Additionally, the general partner contributed an additional $2.1 million to us to retain its 2% general partner interest.

 

Cash Distribution Policy

 

General.  Within 45 days after the end of each quarter, we distribute our available cash (as defined in the 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:

 

 

 

 

Intent to Distribute the Minimum Quarterly Distribution.  We distribute to the holders of common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.45 per unit, or $1.80 per year, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on the units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. We will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default is existing, under our credit agreements. Please read Item 7 “Management’s 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 13, 2009, we paid a quarterly cash distribution of $0.45 per unit on all outstanding units totaling $14.8 million for the quarter ended December 31, 2008 to all unitholders of record as of the close of business on February 3, 2009.

 

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 657,796 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 partner’s 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 $0.45 per unit. The maximum distribution of 50% includes distributions paid to our general partner on its 2% general partner interest, and assumes that our general partner maintains its general partner interest at 2%. The maximum distribution of 50% does not include any distributions that our general partner may receive on units that it owns. We paid $1.0 million to our general partner in incentive distributions pursuant to its incentive distribution rights during the year ended December 31, 2008.

Operating Surplus and Capital Surplus

 

General.  All cash distributed to unitholders will be characterized as either “operating surplus” or “capital surplus.” Our partnership agreement requires that we distribute available cash from operating surplus differently than available cash from capital surplus.

 

Operating Surplus.  Operating surplus generally consists of:

 

 

Maintenance capital expenditures represent capital expenditures made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. Expansion capital expenditures represent capital expenditures made to expand the existing operating capacity of our assets or to expand the operating capacity or revenues of existing or new assets, whether through construction or acquisition. Costs for repairs and minor renewals to maintain facilities in operating condition and that do not extend the useful life of existing assets will be treated as operations and maintenance expenses as we incur them. Our partnership agreement provides that our general partner determines how to allocate a capital expenditure for the acquisition or expansion of our assets between maintenance capital expenditures and expansion capital expenditures.

 

Capital Surplus.  Capital surplus consists of:

 

 

Characterization of Cash Distributions.  We will treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since we began operations equals the operating surplus as of the most recent date of determination of available cash. We will treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As reflected above, operating surplus includes $10.0 million. This amount does not reflect actual cash on hand that is available for distribution to our unitholders. Rather, it is a provision that will enable us, if we choose, to distribute as operating surplus up to this amount of cash we receive in the future from non-operating sources, such as asset sales, issuances of securities and borrowings, that would otherwise be distributed as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

 

Subordination Period

 

General.  Our partnership agreement provides that, during the subordination period (defined below), the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.45 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash

from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the existence of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units. All of the outstanding subordinated units are owned by affiliates of our general partner.

 

Subordination Period.  The subordination period will extend until the first day of any quarter beginning after December 31, 2010 that each of the following tests are met:

 

 

Expiration of the Subordination Period.  When the subordination period expires, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and units held by the general partner and its affiliates are not voted in favor of such removal:

 

 

Adjusted Operating Surplus.  Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods. Adjusted operating surplus consists of:

 

 

Distributions of Available Cash from Operating Surplus During the Subordination Period

 

We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

 

 

 

The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

 

Distributions of Available Cash from Operating Surplus After the Subordination Period

 

We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

 

 

The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

 

Incentive Distribution Rights

 

Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement.

 

If for any quarter:

 

 

then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and the general partner in the following manner:

 

 

In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterly distribution. The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

Percentage Allocations of Available Cash from Operating Surplus

 

The following table illustrates the percentage allocations of the additional available cash from operating surplus between the unitholders and our general partner up to the various target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution,” until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2% general partner interest and assume our general partner has contributed any additional capital to maintain its 2% general partner interest and has not transferred its incentive distribution rights.

 

 

Distributions from Capital Surplus

 

How Distributions from Capital Surplus Will Be Made.  Our partnership agreement requires that we make distributions of available cash from capital surplus, if any, in the following manner:

 

 

Effect of a Distribution from Capital Surplus.  Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the “unrecovered initial unit price.” Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution, after any of these distributions are made, it may be easier for the general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

 

Once we distribute capital surplus on a unit in an amount equal to the initial unit price, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels will be reduced to zero. Our partnership agreement specifies that we then make all future distributions from operating surplus, with 50% being paid to the holders of units and 50% to the general partner. The percentage interests shown for our general partner include its 2% general partner interest and assume the general partner has not transferred the incentive distribution rights.

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 on Form 10-K.

 

Sales of Unregistered Securities

 

None.

 

Issuer Purchases of Equity Securities

 

None.

 

The following table shows selected historical consolidated financial and operating data of Calumet Specialty Products Partners, L.P. and its consolidated subsidiaries (“Calumet”) and Calumet Lubricants Co., Limited Partnership (“Predecessor”). The selected historical financial data as of December 31, 2008 includes the operations acquired as part of the Penreco acquisition from their date of acquisition, January 3, 2008. The selected historical financial data as of December 31, 2005 and 2004 and for the years ended December 31, 2005 and 2004, are derived from the consolidated financial statements of the Predecessor. The results of operations for the years ended December 31, 2006 for Calumet include the results of operations of the Predecessor for the period of January 1, 2006 through January 31, 2006.

 

The following table includes the non-GAAP financial measures EBITDA and Adjusted EBITDA. For a reconciliation of EBITDA and Adjusted EBITDA to net income and net cash provided by (used in) operating activities, our most directly comparable financial performance and liquidity measures calculated in accordance with GAAP, please read “Non-GAAP Financial Measures.”

 

We derived the information in the following table from, and that information should be read together with and is qualified in its entirety by reference to, the historical consolidated financial statements and the accompanying notes included in Item 8 “Financial Statements and Supplementary Data” of this Annual Report on Form 10-K except for operating data such as sales volume, feedstock runs and production. The table also should be read together with Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

 

 

Non-GAAP Financial Measures

 

We include in this Annual Report on Form 10-K the non-GAAP financial measures EBITDA and Adjusted EBITDA, and provide reconciliations of EBITDA and Adjusted EBITDA to net income and net cash provided by (used in) operating activities, our most directly comparable financial performance and liquidity measures calculated and presented in accordance with GAAP.

 

EBITDA and Adjusted EBITDA are used as supplemental financial measures by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:

 

 

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. On January 3, 2008, we entered into a new senior secured term loan credit facility and amended our existing senior secured revolving credit facility. Please refer to Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Debt and Credit Facilities” within this item for additional details regarding our credit agreements.

 

EBITDA and Adjusted EBITDA should not be considered alternatives to net income, operating income, net cash provided by (used in) operating activities or any other measure of financial performance presented in accordance with GAAP. Our EBITDA and Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate EBITDA and Adjusted EBITDA in the same manner. The following table presents a reconciliation of both net income to EBITDA and Adjusted EBITDA and Adjusted

EBITDA and EBITDA to net cash provided by (used in) operating activities, our most directly comparable GAAP financial performance and liquidity measures, for each of the periods indicated.

 

 

 

The historical consolidated financial statements included in this Annual Report on Form 10-K reflect all of the assets, liabilities and results of operations of Calumet Specialty Products Partners, L.P. (“Calumet”). The following discussion analyzes the financial condition and results of operations of Calumet for the years ended December 31, 2008, 2007, and 2006. The financial condition and results of operations for the year ended December 31, 2006 are of Calumet and include the results of operation of the Calumet Lubricants Co., Limited Partnership, our predecessor, from January 1, 2006 to January 31, 2006. Unitholders should read the following discussion and analysis of the financial condition and results of operations for Calumet in conjunction with the historical consolidated financial statements and notes of Calumet included elsewhere in this Annual Report on Form 10-K.

 

Overview

 

We are a leading independent producer of high-quality, specialty hydrocarbon products in North America. We own plants located in Princeton, Louisiana, Cotton Valley, Louisiana, Shreveport, Louisiana, Karns City, Pennsylvania, and Dickinson, Texas, and a terminal located in Burnham, Illinois. Our business is organized into two segments: specialty products and fuel products. In our specialty products segment, we process crude oil and other feedstocks into a wide variety of customized lubricating oils, white mineral oils, solvents, petrolatums and waxes. Our specialty products are sold to domestic and international customers who purchase them primarily as raw material components for basic industrial, consumer and automotive goods. In our fuel products segment, we process crude oil into a variety of fuel and fuel-related products, including gasoline, diesel and jet fuel. In connection with our production of specialty products and fuel products, we also produce asphalt and a limited number of other by-products. The asphalt and other by-products produced in connection with the production of specialty products at our Princeton, Cotton Valley and Shreveport refineries are included in our specialty products segment. The by-products produced in connection with the production of fuel products at our Shreveport refinery are included in our fuel products segment. The fuels produced in connection with the production of specialty products at our Princeton and Cotton Valley refineries are included in our specialty products segment. In 2008, approximately 73.9% of our gross profit was generated from our specialty products segment and approximately 26.1% of our gross profit was generated from our fuel products segment.

 

Industry Dynamics

 

The specialty petroleum products refining industry and, in general, the overall refining industry experienced significant volatility during 2008, which created many challenges for refiners. We faced the same economic challenges that affected most companies in the industry, primarily driven by the extreme fluctuations in crude oil and other feedstock prices during the year. As a whole, the specialty petroleum products refining industry increased prices significantly for specialty products during the first half of 2008, but these product price increases lagged the unprecedented pace of increases in the price of crude oil. The historic increase in crude oil to approximately $145 per barrel on the NYMEX in June 2008 was followed by a decrease in crude oil prices even more severe than the increase. In December 2008, crude oil prices on the NYMEX averaged approximately $42 per barrel. As a result, in 2008, most companies in the industry experienced cash flow volatility, significant fluctuations in gross profit, significant hedging losses in the second half of the year and increased liquidity issues due to the devaluation in the market prices of inventories of crude oil and refined products. Calumet was no different, as our specialty products segment gross profit on a quarterly basis experienced volatility as it was $22.3 million, $21.5 million, $66.1 million and $77.7 million in the first, second, third and fourth quarters of 2008, respectively.

 

Related to specialty products crude oil hedging, our realized hedging results fluctuated from a gain of $22.8 million through the six months ended June 30, 2008 as compared to a loss of $47.9 million for the six months ended December 31, 2008. Most recently, the industry has experienced bankruptcy filings of certain refiners and chemical companies due to this period of difficult industry dynamics. Given the current fuel products crack spread being at a much lower level than in recent years and the demand impact of the economic downturn, the upcoming period will likely continue to be challenging for refiners, including specialty products refiners like us.

 

Calumet has sought to differentiate itself from its competitors and mitigate the impacts of the challenging economic environment through modifications to our hedging program, continued focus on specialty products,

working capital reduction initiatives, reducing our quarterly cash distributions to the minimum quarterly distribution early in 2008, and other initiatives to help improve liquidity.

 

Acquisition and Refinery Expansion

 

On January 3, 2008, we acquired Penreco, a Texas general partnership, for $269.1 million. Penreco was owned by ConocoPhillips and M.E. Zukerman Specialty Oil Corporation. Penreco manufactures and markets highly refined products and specialty solvents including white mineral oils, petrolatums, natural petroleum sulfonates, cable-filling compounds, refrigeration oils, food-grade compressor lubricants and gelled products. The acquisition included facilities in Karns City, Pennsylvania and Dickinson, Texas, as well as several long-term supply agreements with ConocoPhillips. We funded the transaction through a portion of the combined proceeds from a public equity offering and a new senior secured first lien term loan facility. For further discussion please read “Liquidity and Capital Resources — Debt and Credit Facilities.” We believe that this acquisition provides several key long term strategic benefits, including market synergies within our solvents and lubricating oil product lines, additional operational and logistics flexibility and overhead cost reductions. The acquisition has broadened our customer base and has given the Company access to new markets.

 

In the second quarter of 2008 we completed a $374.0 million expansion project at our Shreveport refinery to increase aggregate crude oil throughput capacity from approximately 42,000 bpd to approximately 60,000 bpd and improve feedstock flexibility. For further discussion of this project, please read “Liquidity and Capital Resources — Capital Expenditures.”

 

Key Performance Measures

 

Our sales and net income are principally affected by the price of crude oil, demand for specialty and fuel products, prevailing crack spreads for fuel products, the price of natural gas used as fuel in our operations and our results from derivative instrument activities.

 

Our primary raw materials are crude oil and other specialty feedstocks and our primary outputs are specialty petroleum and fuel products. The prices of crude oil, specialty products and fuel products are subject to fluctuations in response to changes in supply, demand, market uncertainties and a variety of additional factors beyond our 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 which 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, 2008, we have hedged approximately 18.5 million barrels of fuel products through December 2011 at an average refining margin of $11.48 per barrel with average refining margins ranging from a low of $11.32 in 2010 to a high of $11.99 in 2011. During the fourth quarter of 2008, we entered into derivative transactions for 5,000 bpd in 2009 to sell crude oil and buy gasoline which economically secured existing gains on the derivative position of $9.70 per barrel. As a result of these positions, we are now economically exposed to deterioration of gasoline crack spreads below $(2.13) per barrel for 5,000 bpd in 2009. As of December 31, 2008, we have 0.7 million barrels of crude oil options through March 2009 to hedge our purchases of crude oil for specialty products production. The strike prices and types of crude oil options vary. Please refer to Item 7a “Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk — Existing Commodity Derivative Instruments” for a detailed listing of our derivative instruments.

 

Our management uses several financial and operational measurements to analyze our performance. These measurements include the following:

 

 

Sales volumes.  We view the volumes of specialty products and fuels products sold as an important measure of our ability to effectively utilize our refining assets. Our ability to meet the demands of our customers is driven by the volumes of crude oil and feedstocks that we run at our facilities. Higher volumes improve profitability both through the spreading of fixed costs over greater volumes and the additional gross profit achieved on the incremental volumes.

 

Production yields.  We seek the optimal product mix for each barrel of crude oil we refine, which we refer to as production yield, in order to maximize our gross profit and minimize lower margin by-products.

 

Specialty products and fuel products gross profit.  Specialty products and fuel products gross profit are important measures of our ability to maximize the profitability of our specialty products and fuel products segments. We define specialty products and fuel products gross profit as sales less the cost of crude oil and other feedstocks and other production-related expenses, the most significant portion of which include labor, plant fuel, utilities, contract services, maintenance, depreciation and processing materials. We use specialty products and fuel products gross profit as indicators of our ability to manage our business during periods of crude oil and natural gas price fluctuations, as the prices of our specialty products and fuel products generally do not change immediately with changes in the price of crude oil and natural gas. The increase in selling prices typically lags behind the rising costs of crude oil feedstocks for specialty products. Other than plant fuel, production-related expenses generally remain stable across broad ranges of throughput volumes, but can fluctuate depending on maintenance activities performed during a specific period.

 

In addition to the foregoing measures, we also monitor our selling, general and administrative expenditures, substantially all of which are incurred through our general partner, Calumet GP, LLC.

 

High crude oil prices and the volatility of crude oil prices posed significant challenges for us during 2008. The average of the prompt month NYMEX contract for crude oil, which approximates our cost of crude oil, has fluctuated significantly throughout 2008 as follows:

 

 

As a result, we have experienced significant volatility in our gross profit and realized hedging results throughout the year. In response to this volatility, we implemented multiple rounds of specialty product price increases to customers during the first three quarters of 2008 and implemented reductions in our specialty products pricing being during the fourth quarter of 2008 in line with the substantial decline in the price of crude oil. Also, we continue to work diligently on other strategic initiatives, including optimizing our new assets from our Shreveport refinery expansion project and Penreco acquisition, using derivative instruments to mitigate the risk of price fluctuations in crude oil input prices, and maintaining our working capital reductions we achieved during the 2008 fiscal year. For further discussion of our strategic initiatives and our progress on such initiatives during the fourth quarter of 2008, please read “Liquidity and Capital Resources.” While we are taking steps to mitigate the adverse impact of this volatile environment on our operating results, we can provide no assurances as to the sustainability of the improvements in our operating results and to the extent we experience further periods of rapidly escalating or declining crude oil prices, our operating results and liquidity could be adversely affected.

Results of Operations

 

The following table sets forth information about our combined operations. Facility production volume differs from sales volume due to changes in inventory.