CLMT-2012.12.31-10K
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
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þ | | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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| | For the fiscal year ended December 31, 2012 |
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| | OR |
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¨ | | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission File number 000-51734
Calumet Specialty Products Partners, L.P.
(Exact Name of Registrant as Specified in Its Charter)
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Delaware | | 37-1516132 |
(State or Other Jurisdiction of Incorporation or Organization) | | (I.R.S. Employer Identification Number) |
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:
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Title of Each Class | | Name of Each Exchange on Which Registered |
Common units representing limited partner interests | | The NASDAQ Stock Market LLC |
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 þ No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No 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 ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
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Large accelerated filer þ |
| Accelerated filer ¨ |
| Non-accelerated filer ¨ |
| Smaller reporting company ¨ |
(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 ¨ No þ
The aggregate market value of the common units held by non-affiliates of the registrant was approximately $937.1 million on June 29, 2012, based on $23.78 per unit, the closing price of the common units as reported on the NASDAQ Global Select Market on such date.
On February 28, 2013, there were 63,279,778 common units outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
NONE.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
FORM 10-K — 2012 ANNUAL REPORT
Table of Contents
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PART I |
Items 1 and 2. | | |
Item 1A. | | |
Item 1B. | | |
Item 3. | | |
Item 4. | | |
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PART II |
Item 5. | | |
Item 6. | | |
Item 7. | | |
Item 7A. | | |
Item 8. | | |
Item 9. | | |
Item 9A. | | |
Item 9B. | | |
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PART III |
Item 10. | | |
Item 11. | | |
Item 12. | | |
Item 13. | | |
Item 14. | | |
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PART IV |
Item 15. | | |
FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K (this “Annual Report”) includes certain “forward-looking statements.” These statements can be identified by the use of forward-looking terminology including “may,” “intend,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or other similar words. The statements regarding (i) estimated capital expenditures as a result of the required audits or required operational changes or other environmental and regulatory liabilities, (ii) our anticipated levels of, use and effectiveness of derivatives to mitigate our exposure to crude oil price changes and fuel products price changes and (iii) our ability to meet our financial commitments, minimum quarterly distributions to our unitholders, debt service obligations, debt instrument covenants, contingencies and anticipated capital expenditures, as well as other matters discussed in this Annual Report that are not purely historical data, are forward-looking statements. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Known material factors that could cause our actual results to differ from those in the forward-looking statements are those described in Part I, Item 1A “Risk Factors” of this Annual Report. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.
References in this Annual Report to “Calumet Specialty Products Partners, L.P.,” “the Company,” “we,” “our,” “us” or like terms refer to Calumet Specialty Products Partners, L.P. and its subsidiaries. References to “Predecessor” in this Annual Report refer to Calumet Lubricants Co., Limited Partnership and its subsidiaries, the assets and liabilities of which were contributed to Calumet Specialty Products Partners, L.P. and its subsidiaries upon the completion of our initial public offering in 2006. References in this Annual Report to “our general partner” refer to Calumet GP, LLC, the general partner of Calumet Specialty Products Partners, L.P.
PART I
Items 1 and 2. Business and Properties
Overview
We are a leading independent producer of high-quality, specialty hydrocarbon products and fuel products in North America. We are headquartered in Indianapolis, Indiana and own facilities primarily located in Louisiana, Wisconsin, Montana, Texas and Pennsylvania. We own and lease additional blending and storage facilities, primarily related to production and distribution of specialty products, throughout the United States (“U.S.”). 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, waxes and asphalt. 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. We also blend and market specialty products through our brand Royal Purple. In our fuel products segment, we process crude oil into a variety of fuel and fuel-related products, including gasoline, diesel, jet fuel and heavy fuel oils. In connection with our production of specialty products and fuel products, we also produce asphalt and a limited number of other by-products. For the year ended December 31, 2012, approximately 47.9% of our sales and 60.1% of our gross profit were generated from our specialty products segment and approximately 52.1% of our sales and 39.9% of our gross profit were generated from our fuel products segment.
Our Primary Operating Assets
Our primary operating assets consist of:
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Refinery/Facility | | Location | | Date Acquired | | Throughput Capacity in barrels per day (“bpd”) | | Products |
Shreveport | | Louisiana | | 2001 | | 60,000 | | Specialty lubricating oils and waxes, gasoline, diesel and jet fuel |
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Superior | | Wisconsin | | 2011 | | 45,000 | | Gasoline, diesel, asphalt and heavy fuel oils |
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San Antonio | | Texas | | 2013 | | 14,500 | | Jet fuel, diesel, other fuel products and specialty solvents |
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Cotton Valley | | Louisiana | | 1995 | | 13,500 | | Specialty solvents that are used principally in the manufacture of paints, cleaners, automotive products and drilling fluids |
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Montana | | Montana | | 2012 | | 10,000 | | Gasoline, diesel, jet fuel and asphalt |
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Princeton | | Louisiana | | 1990 | | 10,000 | | Specialty lubricating oils, including process oils, base oils, transformer oils and refrigeration oils |
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Karns City | | Pennsylvania | | 2008 | | 5,500 | | White mineral oils, solvents, petrolatums, gelled hydrocarbons, cable fillers and natural petroleum sulfonates |
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Dickinson | | Texas | | 2008 | | 1,300 | | White mineral oils, compressor lubricants and natural petroleum sulfonates |
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Royal Purple | | Texas | | 2012 | | N/A | | Specialty products including industrial lubricating oils, gear oils and motor oils |
Storage, Distribution and Logistics Assets. We own and operate product terminals in Burnham, Illinois (“Burnham”), Rhinelander, Wisconsin (“Rhinelander”), Crookston, Minnesota (“Crookston”) and Proctor, Minnesota (“Duluth”) with aggregate storage capacities of approximately 150,000, 166,000, 156,000, and 200,000 barrels, respectively. These
terminals, as well as additional owned and leased facilities throughout the U.S., facilitate the distribution of products in the Upper Midwest and East Coast regions of the U.S. and Canada.
We also use approximately 2,700 leased railcars to receive crude oil or distribute our products throughout the U.S. and Canada. In total, we have approximately 12.2 million barrels of aggregate storage capacity at our facilities and leased storage locations.
Business Strategies
Our management team is dedicated to improving our operations by executing the following strategies:
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• | Concentrate on Stable Cash Flows. We intend to continue to focus on operating assets and businesses that generate stable cash flows. Approximately 47.9% of our sales and 60.1% of our gross profit in 2012 were generated by the sale of specialty products, a segment of our business which is characterized by stable customer relationships due to our customers’ requirements for the highly specialized products that we provide. In addition, we manage our exposure to crude oil price fluctuations in this segment by passing on incremental feedstock costs to our specialty products customers. In our fuel products segment, which accounted for 52.1% of our sales and 39.9% of our gross profit in 2012, we seek to mitigate our exposure to fuel products margin volatility by maintaining a longer-term fuel products hedging program. In addition, our recent acquisitions of various refineries located in different geographical locations provides for diversity of cash flows based on the refining margin environment in each such region. We believe the diversity of our operating assets, products, our broad customer base and our hedging activities help contribute to the stability of our cash flows. |
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• | Develop and Expand Our Customer Relationships. Due to the specialized nature of, and the long lead-time associated with, the development and production of many of our specialty products, our customers are incentivized to continue their relationships with us. We believe that our larger competitors do not work with customers as we do from product design to delivery for smaller volume specialty products like ours. We intend to continue to assist our existing customers in their efforts to expand their product offerings, as well as marketing specialty product formulations to new customers. By striving to maintain our long-term relationships with our broad base of existing customers and by adding new customers, we seek to limit our dependence on any one portion of our customer base. |
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• | Enhance Profitability of Our Existing Assets. We continue to evaluate opportunities to improve our existing asset base, to increase our throughput, profitability and cash flows. Following each of our asset acquisitions, we have undertaken projects designed to maximize the profitability of our acquired assets, such as the enhancement at our Superior refinery completed in November 2012, which enables the refinery to ship crude oil by railcar to our other facilities as well as third parties. We intend to further increase the profitability of our existing asset base through various measures which may include changing the product mix of our processing units, debottlenecking and expanding units as necessary to increase throughput, restarting idle assets and reducing costs by improving operations. We also continue to focus on optimizing current operations through energy savings initiatives, product quality enhancements and product yield improvements. |
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• | Pursue Strategic and Complementary Acquisitions. Since 1990, our management team has demonstrated the ability to identify opportunities to acquire assets and product lines where we can enhance operations and improve profitability. In the future, we intend to continue to consider strategic acquisitions of assets or agreements with third parties that offer the opportunity for operational efficiencies, the potential for increased utilization and expansion of facilities, or the expansion of product offerings in each of our specialty products and fuel products segments. In addition, we may pursue selected acquisitions in new geographic or product areas to the extent we perceive similar opportunities. For example, since 2011 we have completed the following acquisitions that we believe significantly enhance and diversify our existing specialty products and fuel products segments: |
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◦ | TruSouth Oil, LLC - a specialty petroleum packaging and distribution company acquired in January 2012. |
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◦ | Louisiana, Missouri facility - an aviation and refrigerant synthetic lubricants business of Hercules Incorporated acquired in January 2012. |
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◦ | Royal Purple, Inc. - a leading independent formulator and marketer of specialty synthetic lubricants acquired in July 2012. |
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◦ | Montana Refining Company, Inc. - a refinery that produces and sells gasoline, diesel, jet fuel and asphalt products acquired in October 2012. |
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◦ | San Antonio, Texas refinery - a refinery that produces and sells jet fuel, diesel, other fuel products and specialty solvents acquired in January 2013. |
See “—Recent Acquisitions” below for additional information regarding these acquisitions.
Competitive Strengths
We believe that we are well positioned to execute our business strategies successfully based on the following competitive strengths:
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• | We Offer Our Customers a Diverse Range of Specialty Products. We offer a wide range of over 3,500 specialty products. We believe that our ability to provide our customers with a more diverse selection of products than most of our competitors gives us an advantage in competing for new business. We believe that we are the only specialty products manufacturer that produces all four of naphthenic lubricating oils, paraffinic lubricating oils, waxes and solvents. A contributing factor in our ability to produce numerous specialty products is our ability to ship products between our facilities for product upgrading in order to meet customer specifications. |
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• | We Have Strong Relationships with a Broad Customer Base. We have long-term relationships with many of our customers and we believe that we will continue to benefit from these relationships. Our customer base includes over 4,900 active accounts and we are continually seeking new customers. No single customer accounted for more than 10% of our consolidated sales in each of the three years ended December 31, 2012, 2011 and 2010. |
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• | Our Facilities Have Advanced Technology. Our facilities are equipped with advanced, flexible technology that allows us to produce high-grade specialty products and to produce fuel products that comply with low sulfur fuel regulations. For example, our fuel products refineries have the capability to make ultra-low sulfur diesel and gasoline that meet federally mandated low sulfur standards and the Mobile Source Air Toxic Rule II standards (“MSAT II Standards”) set by the U.S. Environmental Protection Agency (“EPA”) requiring the reduction of benzene levels in gasoline. Also, unlike larger refineries, which lack some of the equipment necessary to achieve the narrow distillation ranges associated with the production of specialty products, our operations are capable of producing a wide range of products tailored to our customers’ needs. |
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• | We Have an Experienced Management Team. Our management has a proven track record of enhancing value through the acquisition, exploitation and integration of refining assets and the development and marketing of specialty products. Our senior management team has an average of over 25 years of industry experience. Our team’s extensive experience and contacts within the refining industry provide a strong foundation and focus for managing and enhancing our operations, accessing strategic acquisition opportunities and constructing and enhancing the profitability of new assets. |
Recent Acquisitions
Hercules Synthetic Lubricants Business
On January 3, 2012, we completed the acquisition of the aviation and refrigerant lubricants business (a polyolester based synthetic lubricants business) and a manufacturing facility located in Louisiana, Missouri from Hercules Incorporated, a subsidiary of Ashland, Inc., for aggregate consideration of approximately $19.6 million (“Missouri Acquisition”). The acquisition was financed with borrowings under our revolving credit facility and cash on hand.
TruSouth Oil
On January 6, 2012, we completed the acquisition of TruSouth Oil, LLC, a specialty petroleum packaging and distribution company located in Shreveport, Louisiana (“TruSouth”) for aggregate consideration of approximately $26.8 million (“TruSouth Acquisition”), which was financed with borrowings under our revolving credit facility. Please read Part III, Item 13 “Certain Relationships and Related Transactions and Director Independence — TruSouth Acquisition” for further discussion of our acquisition of TruSouth.
Royal Purple
On July 3, 2012, we completed the acquisition of Royal Purple, Inc. (“Royal Purple”), a Texas corporation which was converted into a Delaware limited liability company at closing, for aggregate consideration of approximately $331.2 million, net of cash acquired (“Royal Purple Acquisition”). Royal Purple is a leading independent formulator and marketer of premium industrial and consumer synthetic lubricants to a diverse customer base across several large markets including oil and gas, chemicals and refining, power generation, manufacturing and transportation, food and drug manufacturing and automotive aftermarket. The Royal Purple Acquisition was financed with net proceeds of $262.6 million from our June 2012 private placement of 9 5/8% senior notes due August 1, 2020 and cash on hand. We believe the Royal Purple Acquisition increases our position in the specialty lubricants markets, expands our geographic reach, increases our asset diversity and enhances our specialty products segment.
Montana
On October 1, 2012, we completed the acquisition from Connacher Oil and Gas Limited (“Connacher”) of all the shares of common stock of Montana Refining Company, Inc., which was converted into a Delaware limited liability company, Calumet Montana Refining, LLC (“Montana”), at closing, and an insignificant affiliated company for aggregate consideration of approximately $191.6 million, net of cash acquired, including an estimated $27.6 million of income taxes due to the conversion to a Delaware limited liability company and excluding certain purchase price adjustments (“Montana Acquisition”). Montana produces gasoline, diesel, jet fuel and asphalt, which are marketed primarily into local markets in Washington, Montana, Idaho and Alberta, Canada. The Montana Acquisition was funded primarily with cash on hand with the balance through borrowings under our revolving credit facility. We believe the Montana Acquisition further diversifies our crude oil feedstock slate, operating asset base and geographical presence.
San Antonio
On January 2, 2013, we completed the acquisition of the San Antonio, Texas refinery and associated crude oil pipeline, crude oil terminal, other operating and logistics assets and inventories (“San Antonio”) of NuStar Refining, LLC and NuStar Logistics, L.P., both wholly owned subsidiaries of NuStar Energy L.P., for aggregate consideration of approximately $115.7 million, including approximately $15.0 million for inventories acquired at closing, subject to customary purchase price adjustments (the “San Antonio Acquisition”). San Antonio produces jet fuel, diesel, other fuel products and specialty solvents. The San Antonio Acquisition was funded primarily with borrowings under our revolving credit facility with the balance through cash on hand. We believe the San Antonio Acquisition further diversifies our crude oil feedstock slate, operating asset base and geographical presence. Please see Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Cash Flows from Operating, Investing and Financing Activities” for additional information regarding the repayment of these revolving credit facility borrowings.
Ongoing Acquisition Activities
Consistent with our business growth strategy, we are continuously engaged in discussions with potential sellers regarding the possible purchase of assets and operations that are strategic and complementary to our existing operations. These acquisition efforts may involve participation by us in processes that have been made public and involve a number of potential buyers, commonly referred to as “auction” processes, as well as situations in which we believe we are the only potential buyer or one of a limited number of potential buyers in negotiations with the potential seller. These acquisition efforts often involve assets and operations which, if acquired, could have a material effect on our financial condition and results of operations and require special financing.
We typically do not announce a transaction until after we have executed a definitive acquisition agreement. However, in certain cases in order to protect our business interests or for other reasons, we may defer public announcement of an acquisition until closing or a later date. Past experience has demonstrated that discussions and negotiations regarding a potential acquisition can advance or terminate in a short period of time. Moreover, the closing of any transaction for which we have entered into a definitive acquisition agreement will be subject to customary and other closing conditions, which may not ultimately be satisfied or waived. Accordingly, we can give no assurance that our current or future acquisition efforts will be successful. Although we expect the acquisitions we make to be accretive in the long term, we can provide no assurance that our expectations will ultimately be realized.
Partnership Structure and Management
Calumet Specialty Products Partners, L.P. is a Delaware limited partnership formed on September 27, 2005. Our general partner is Calumet GP, LLC, a Delaware limited liability company. As of February 28, 2013, we had 63,279,778 common units and 1,291,424 general partner units outstanding. Our general partner owns 2% of the Company and all incentive distribution rights and has sole responsibility for conducting our business and managing our operations. For more information about our general partner’s board of directors, executive officers and other management, please read Part III, Item 10 “Directors, Executive Officers of Our General Partner and Corporate Governance.”
Our Operating Assets and Contractual Arrangements
General
The following tables set forth information about our combined operations and sales of our principal products by segment. Facility production volume differs from sales volume due to changes in inventory and the sale of purchased fuel product blendstocks such as ethanol and biodiesel in our fuel products segment sales. The tables include the results of operations at our Superior refinery commencing October 1, 2011, Missouri facility commencing January 3, 2012, TruSouth facility commencing January 6, 2012, Royal Purple facility commencing July 3, 2012 and Montana refinery commencing October 1, 2012.
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| Year Ended December 31, | | Year Ended December 31, |
| 2012 | | 2011 | | % Change | | 2011 | | 2010 | | % Change |
| (In bpd) | | | | (In bpd) | | |
Total sales volume (1) | 97,789 |
| | 66,134 |
| | 47.9 | % | | 66,134 |
| | 55,668 |
| | 18.8 | % |
Total feedstock runs (2) | 97,600 |
| | 69,295 |
| | 40.8 | % | | 69,295 |
| | 55,957 |
| | 23.8 | % |
Facility production: (3) | | | | | | | | | | | |
Specialty products: | | | | | | | | | | | |
Lubricating oils | 14,524 |
| | 14,427 |
| | 0.7 | % | | 14,427 |
| | 13,697 |
| | 5.3 | % |
Solvents | 9,332 |
| | 10,508 |
| | (11.2 | )% | | 10,508 |
| | 9,347 |
| | 12.4 | % |
Waxes | 1,280 |
| | 1,269 |
| | 0.9 | % | | 1,269 |
| | 1,220 |
| | 4.0 | % |
Packaged and synthetic specialty products | 1,351 |
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| | — |
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Fuels | 669 |
| | 556 |
| | 20.3 | % | | 556 |
| | 1,050 |
| | (47.0 | )% |
Asphalt and other by-products | 14,219 |
| | 10,090 |
| | 40.9 | % | | 10,090 |
| | 6,907 |
| | 46.1 | % |
Total specialty products | 41,375 |
| | 36,850 |
| | 12.3 | % | | 36,850 |
| | 32,221 |
| | 14.4 | % |
Fuel products: | | | | | | | | | | | |
Gasoline | 24,394 |
| | 13,409 |
| | 81.9 | % | | 13,409 |
| | 8,754 |
| | 53.2 | % |
Diesel | 22,438 |
| | 14,721 |
| | 52.4 | % | | 14,721 |
| | 10,800 |
| | 36.3 | % |
Jet fuel | 4,325 |
| | 4,520 |
| | (4.3 | )% | | 4,520 |
| | 5,004 |
| | (9.7 | )% |
Heavy fuel oils and other | 3,640 |
| | 1,409 |
| | 158.3 | % | | 1,409 |
| | 535 |
| | 163.4 | % |
Total fuel products | 54,797 |
| | 34,059 |
| | 60.9 | % | | 34,059 |
| | 25,093 |
| | 35.7 | % |
Total facility production (3) | 96,172 |
| | 70,909 |
| | 35.6 | % | | 70,909 |
| | 57,314 |
| | 23.7 | % |
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(1) | Total sales volume includes sales from the production at our facilities and certain third-party facilities pursuant to supply and/or processing agreements and sales of inventories. Total sales volume includes the sale of purchased fuel product blendstocks such as ethanol and biodiesel as components of finished fuel products in our fuel products segment sales. |
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(2) | Total feedstock runs represent the barrels per day of crude oil and other feedstocks processed at our facilities and at certain third-party facilities pursuant to supply and/or processing agreements. |
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(3) | Total facility production represents the barrels per day of specialty products and fuel products yielded from processing crude oil and other feedstocks at our facilities and at certain third-party facilities, pursuant to supply and/or processing agreements. The difference between total facility production and total feedstock runs is primarily a result of the time lag between the input of feedstocks and production of finished products and volume loss. |
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| Year Ended December 31, |
| 2012 | | 2011 | | 2010 |
| (In thousands) |
Sales of specialty products: | | | | | | | | | | | |
Lubricating oils | $ | 1,007,928 |
| | 22 | % | | $ | 947,798 |
| | 30 | % | | $ | 759,701 |
| | 35 | % |
Solvents | 491,114 |
| | 11 | % | | 495,934 |
| | 16 | % | | 396,894 |
| | 18 | % |
Waxes | 142,765 |
| | 3 | % | | 143,111 |
| | 5 | % | | 124,964 |
| | 6 | % |
Packaged and synthetic specialty products (1) | 161,673 |
| | 3 | % | | — |
| | — | % | | — |
| | — | % |
Fuels (2) | 2,029 |
| | — | % | | 3,432 |
| | — | % | | 5,507 |
| | — | % |
Asphalt and other by-products (3) | 426,093 |
| | 9 | % | | 217,351 |
| | 7 | % | | 121,806 |
| | 5 | % |
Total | 2,231,602 |
| | 48 | % | | 1,807,626 |
| | 58 | % | | 1,408,872 |
| | 64 | % |
Sales of fuel products: | | | | | | | | | | | |
Gasoline | 1,174,859 |
| | 25 | % | | 619,630 |
| | 20 | % | | 304,544 |
| | 14 | % |
Diesel | 941,047 |
| | 20 | % | | 513,334 |
| | 16 | % | | 330,756 |
| | 15 | % |
Jet fuel | 183,953 |
| | 4 | % | | 148,036 |
| | 5 | % | | 135,796 |
| | 6 | % |
Heavy fuel oils and other (4) | 125,821 |
| | 3 | % | | 46,297 |
| | 1 | % | | 10,784 |
| | 1 | % |
Total | 2,425,680 |
| | 52 | % | | 1,327,297 |
| | 42 | % | | 781,880 |
| | 36 | % |
Consolidated sales | $ | 4,657,282 |
| | 100 | % | | $ | 3,134,923 |
| | 100 | % | | $ | 2,190,752 |
| | 100 | % |
____________________
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(1) | Represents packaged and synthetic specialty products at the Royal Purple, TruSouth and Missouri facilities. |
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(2) | Represents fuels produced in connection with the production of specialty products at the Princeton and Cotton Valley refineries. |
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(3) | Represents asphalt and other by-products produced in connection with the production of specialty and fuel products at the Shreveport, Superior, Montana, Cotton Valley and Princeton refineries. |
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(4) | Represents heavy fuel oils and other products produced in connection with the production of fuels at the Shreveport, Superior and Montana refineries. |
Please read Note 14 “Segments and Related Information” in Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report for additional financial information about each of our segments and the geographical areas in which we conduct business.
Shreveport Refinery
The Shreveport refinery, located on a 240-acre site in Shreveport, Louisiana (“Shreveport”), currently has aggregate crude oil throughput capacity of 60,000 bpd and processes paraffinic crude oil and associated feedstocks into fuel products, paraffinic lubricating oils, waxes, asphalt and by-products.
The Shreveport refinery consists of 17 major processing units including hydrotreating, catalytic reforming and dewaxing units with approximately 3.3 million barrels of storage capacity in 130 storage tanks and related loading and unloading facilities and utilities. Since our acquisition of the Shreveport refinery in 2001, we have expanded the refinery’s capabilities by adding additional processing and blending facilities, adding a second reactor to the high pressure hydrotreater, resuming production of gasoline, diesel and other fuel products and adding both 18,000 bpd of crude oil throughput capacity and the capability to run up to 25,000 bpd of sour crude oil with an expansion project completed in May 2008. The following table sets forth historical information about production at our Shreveport refinery.
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| Shreveport Refinery |
| Year Ended December 31, |
| 2012 | | 2011 | | 2010 |
| (In bpd) |
Crude oil throughput capacity | 60,000 |
| | 60,000 |
| | 60,000 |
|
Total feedstock runs (1) (2) | 39,831 |
| | 39,910 |
| | 36,409 |
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Total refinery production (2) (3) | 39,825 |
| | 39,910 |
| | 36,395 |
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(1) | Total feedstock runs represents the barrels per day of crude oil and other feedstocks processed at our Shreveport refinery. Total feedstock runs do not include certain interplant feedstocks supplied by our Cotton Valley and Princeton refineries. |
For more information about the shutdown of the ExxonMobil pipeline, which impacted feedstock runs at the refinery during 2012, please read Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations.”
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(2) | Total refinery production represents the barrels per day of specialty products and fuel products yielded from processing crude oil and other feedstocks. The difference between total refinery production and total feedstock runs is primarily a result of the time lag between the input of feedstocks and production of finished products and volume loss. |
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(3) | Total refinery production includes certain interplant feedstock supplied to our Cotton Valley and Princeton refineries and Karns City facility. |
The Shreveport refinery has a flexible operational configuration and operating personnel that facilitate development of new product opportunities. Product mix may fluctuate from one period to the next to capture market opportunities. The refinery has an idle residual fluid catalytic cracking unit, alkylation unit, vacuum tower and a number of idle towers that can be utilized for future project needs. Certain idle towers were utilized as a part of the Shreveport refinery expansion project completed in 2008.
The Shreveport refinery currently makes jet fuel and ultra-low sulfur diesel and all of its gasoline production currently meets MSAT II Standards. To the extent we exceed the minimum requirements of the MSAT II Standards, we have the option to sell renewable identification number fuel credits (“RINs Credits”) and have the option to purchase RINs Credits if we operate the refinery in a manner that does not meet these minimum requirements.
The Shreveport refinery receives crude oil via tank truck, railcar and common carrier pipeline systems that are operated by subsidiaries of Plains All American Pipeline, L.P. (“Plains”) and Exxon Mobil Corporation (“ExxonMobil”) and 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; however, the pipeline has been shutdown since April 28, 2012. The enhancement project at our Superior refinery completed in November 2012 enables the Superior refinery to receive crude oil by railcar and subsequently ship crude oil by railcar to our Shreveport refinery. Crude oil is also purchased from various suppliers, including local producers, who deliver crude oil to the Shreveport refinery via tank truck.
The Shreveport refinery also has direct pipeline access to the Enterprise Products Partners L.P. pipeline (“TEPPCO pipeline”), on which it can ship all grades of gasoline, diesel and jet fuel. Further, the refinery 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 U.S. through both truck and railcar service.
Superior Refinery
The Superior refinery is located on a 245-acre site, with an additional 430 acres owned around the existing refinery, in Superior, Wisconsin (“Superior”). The Superior refinery currently has aggregate crude oil throughput capacity of 45,000 bpd and processes light and heavy crude oil from the Bakken shale oil formation in North Dakota and western Canada into fuel products and asphalt.
The Superior refinery consists of 14 major processing units including hydrotreating, catalytic reforming, fluid catalytic cracking and alkylation units with approximately 3.2 million barrels of storage capacity in 76 tanks and related loading and unloading facilities and utilities. The following table sets forth historical information about production at our Superior refinery since its acquisition on September 30, 2011.
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| Superior Refinery |
| Year Ended December 31, 2012 | | Three Months Ended December 31, 2011 |
| (In bpd) |
Crude oil throughput capacity | 45,000 |
| | 45,000 |
|
Total feedstock runs (1) (2) | 34,609 |
| | 35,335 |
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Total refinery production (2) | 34,742 |
| | 35,335 |
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(1) | Total feedstock runs represents the barrels per day of crude oil and other feedstocks processed at our Superior refinery. |
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(2) | Total refinery production represents the barrels per day of fuel products and specialty products yielded from processing crude oil and other feedstocks. The difference between total refinery production and total feedstock runs is primarily a result of the time lag between the input of feedstocks and production of finished products and volume loss. |
The Superior 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. Currently the Superior refinery produces gasoline, diesel, asphalt and heavy fuel oils. The Superior refinery is compliant with federal regulations for ultra-low sulfur diesel and low sulfur gasoline production. To the extent we exceed the minimum requirements of the MSAT II Standards, we have the option to sell RINs Credits, and have the option to purchase RINs Credits if we operate the refinery in a manner that does not meet these minimum requirements.
Finished fuel products produced at the Superior refinery are sold through the Superior refinery truck rack, several Magellan pipeline terminals in Minnesota, Wisconsin, Iowa, North Dakota and South Dakota and through our Duluth terminal. The Superior wholesale fuel business also sells gasoline wholesale to SPUR branded gas stations located throughout the Upper Midwest (including Minnesota, Wisconsin and Michigan), which are owned and operated by independent franchisees. The Superior refinery ships finished fuel products and asphalt by railcar and truck service. Asphalt products produced at the Superior refinery are sold through our terminals in Rhinelander and Crookston and through other leased terminals in the U.S.
Finished fuel products sales are primarily made through spot agreements and short-term contracts. Asphalt production is primarily sold through spot agreements and short-term contracts with asphalt customers primarily located in and around the Upper Midwest, North Dakota, South Dakota and Utah.
The Superior refinery receives crude oil via pipeline and railcar. The Enbridge Pipeline System (the “Enbridge Pipeline”) delivers crude oil to the Superior refinery and is adjacent to one of the Enbridge Pipeline’s first crude oil holding facilities after crossing the Canadian border into the U.S., providing reliable access to high quality crude oil from the Bakken shale oil formation in North Dakota and from western Canada. The refinery receives approximately 63% of its daily crude oil requirements under a crude oil purchase agreement (the “BP Purchase Agreement”) with BP Products North America Inc. (“BP”). In addition, the refinery receives up to 10,000 bpd of crude oil under a crude oil purchase agreement with Murphy Oil (“Murphy Crude Oil Supply Agreement”). For more information about the BP Purchase Agreement, please read the information provided under Note 5 “Commitments and Contingencies” in Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report. In November 2012, the Superior refinery completed an enhancement project which enables the refinery to receive crude oil by railcar and subsequently ship crude oil by railcar to our Shreveport refinery as well as other third parties.
San Antonio Refinery
The San Antonio refinery, located on a 32-acre site in San Antonio, Texas, has aggregate crude oil throughput capacity of 14,500 bpd and processes light crude oil from south Texas, including the Eagle Ford Shale formation, into a variety of transportation fuels, feedstocks and specialty products. The San Antonio refinery consists of five major processing units including hydrotreating, catalytic reforming and solvents distillation with approximately 162,000 barrels of storage capacity in 57 tanks and related loading and unloading facilities and utilities.
Currently, the San Antonio refinery produces jet fuel, diesel, gasoline, other fuel products and specialty solvents. The San Antonio refinery is compliant with federal regulations for ultra-low sulfur diesel. The San Antonio refinery ships products by railcar and truck. Product sales are primarily made through spot agreements and short-term contracts. The San Antonio refinery purchases crude oil and intermediate products from various suppliers and receives crude oil by pipeline originating from its crude oil terminal in Elmendorf, Texas (“Elmendorf”), providing reliable access to high quality crude oil from Texas, primarily the Eagle Ford Shale. The Elmendorf terminal has aggregate storage capacity of approximately 188,000 barrels.
Cotton Valley Refinery
The Cotton Valley refinery, located on a 77-acre site in Cotton Valley, Louisiana (“Cotton Valley”), currently has aggregate crude oil throughput capacity of 13,500 bpd, hydrotreating capacity of 6,200 bpd and processes crude oil into specialty solvents and residual fuel oil. The residual fuel oil is an important feedstock for the production of specialty products at our Shreveport refinery. We believe the Cotton Valley refinery produces the most complete, single-facility line of paraffinic solvents in the U.S.
The Cotton Valley refinery 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. Since our acquisition of the Cotton Valley refinery 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.
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| Cotton Valley Refinery |
| Year Ended December 31, |
| 2012 | | 2011 | | 2010 |
| (In bpd) |
Crude oil throughput capacity | 13,500 |
| | 13,500 |
| | 13,500 |
|
Total feedstock runs (1) (2) | 5,487 |
| | 5,806 |
| | 5,510 |
|
Total refinery production (2) (3) | 7,550 |
| | 7,951 |
| | 7,229 |
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(1) | Total feedstock runs do not include certain interplant solvent feedstocks supplied by our Shreveport refinery. |
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(2) | Total refinery production represents the barrels per day of specialty products yielded from processing crude oil and other feedstocks. The difference between total refinery production and total feedstock runs is primarily a result of the time lag between the input of feedstocks and production of finished products and volume loss. |
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(3) | Total refinery production includes certain interplant feedstocks supplied to our Shreveport refinery. |
The Cotton Valley 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, 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 finished product inventory requirements.
The Cotton Valley refinery receives crude oil via truck and through a pipeline system operated by a subsidiary of Plains. The Cotton Valley refinery’s feedstock is primarily low sulfur, paraffinic crude oil originating from north Louisiana and is purchased from various marketers and gatherers. In addition, the Cotton Valley refinery receives interplant feedstocks for solvent production from the Shreveport refinery. The Cotton Valley refinery ships finished products by both truck and railcar service.
Montana Refinery
The Montana refinery, located on an 86-acre site in Great Falls, Montana, currently has aggregate crude oil throughput capacity of 10,000 bpd and processes light and heavy crude oil from Canada into fuel and asphalt products.
The Montana refinery consists of 13 major processing units including hydrotreating, catalytic reforming, fluid catalytic cracking and alkylation units with approximately 939,000 barrels of storage capacity in 71 tanks and related loading and unloading facilities and utilities. The following table sets forth historical information about production at the Montana refinery since our acquisition of the refinery on October 1, 2012.
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| Montana Refinery |
| Three Months Ended December 31, 2012 |
| (In bpd) |
Crude oil throughput capacity | 10,000 |
Total feedstock runs (1) (2) | 10,169 |
Total refinery production (2) | 10,170 |
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(1) | Total feedstock runs represents the barrels per day of crude oil and other feedstocks processed at our Montana refinery from October 1, 2012 through December 31, 2012. |
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(2) | Total refinery production represents the barrels per day of specialty products and fuel products yielded from processing crude oil and other feedstocks from October 1, 2012 through December 31, 2012. The difference between total refinery production and total feedstock runs is primarily a result of the time lag between the input of feedstocks and production of finished products and volume loss. |
Currently, the Montana refinery produces gasoline, diesel, jet fuel and asphalt products. The Montana refinery is compliant with federal regulations for ultra-low sulfur diesel and low sulfur gasoline production. To the extent we exceed the minimum requirements of the MSAT II Standards, we have the option to sell RINs Credits, and have the option to purchase RINs Credits if we operate the refinery in a manner that does not meet these minimum requirements.
The Montana refinery ships finished fuel and asphalt products by railcar and truck service. Finished fuel and asphalt products sales are primarily made through spot agreements and short-term contracts.
The Montana refinery purchases crude oil from various suppliers and receives crude oil by pipeline through the Front Range Pipeline (“Front Range”) via the Bow River Pipeline in Canada, providing reliable access to high quality crude oil from western Canada.
Princeton Refinery
The Princeton refinery, located on a 208-acre site in Princeton, Louisiana (“Princeton”), currently has aggregate crude oil throughput capacity of 10,000 bpd and processes naphthenic crude oil into lubricating oils, asphalt and feedstock for the Shreveport refinery for further processing into ultra-low sulfur diesel. The asphalt produced may be further processed or blended for coating and roofing product applications at the Princeton refinery or transported to the Shreveport refinery for further processing into bright stock.
The Princeton refinery 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.
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| Princeton Refinery |
| Year Ended December 31, |
| 2012 | | 2011 | | 2010 |
| (In bpd) |
Crude oil throughput capacity | 10,000 |
| | 10,000 |
| | 10,000 |
|
Total feedstock runs (1) | 6,914 |
| | 6,844 |
| | 6,096 |
|
Total refinery production (1) (2) | 6,971 |
| | 6,895 |
| | 6,138 |
|
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(1) | Total refinery production represents the barrels per day of specialty products yielded from processing crude oil and other feedstocks. The difference between total refinery production and total feedstock runs is primarily a result of the time lag between the input of feedstocks and production of finished products and volume loss. |
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(2) | Total refinery production includes certain interplant feedstocks supplied to our Shreveport 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. In addition, we have the necessary tankage and technology to process our asphalt into higher value product applications such as coatings, road paving and emulsions for road paving and specialty applications.
The Princeton refinery receives crude oil via tank truck, railcar and the Plains pipeline system. Its crude oil supply primarily originates from east Texas and north Louisiana, which is purchased directly from third-party suppliers under month-to-month evergreen supply contracts and on the spot market. The Princeton refinery ships its finished products throughout the U.S. via both truck and railcar service.
Royal Purple Facility
The Royal Purple facility, located on a 23-acre site in Porter, Texas, blends and packages high performance industrial and retail synthetic lubricants for use primarily in industrial, automotive, marine, motorcycle and consumer applications. The Royal Purple facility’s processing capability includes blending and packaging on 10 production lines. In addition, the facility has approximately 30,500 barrels of storage capacity in 91 tanks and related loading and unloading facilities and utilities. The facility receives its base oil feedstocks and additive chemicals by truck under supply agreements or spot agreements with various suppliers.
The Royal Purple facility is designed with the latest automated batch processing technology and design to maximize blending accuracy and flexibility to meet customer needs. The packaging operations utilize both in-house packaging equipment and outsourced packaging services for specific products.
Karns City and Dickinson Facilities and Other Processing Agreements
The Karns City facility, located on a 225-acre site in Karns City, Pennsylvania (“Karns City”), has aggregate base oil throughput capacity of 5,500 bpd and processes white mineral oils, solvents, petrolatums, gelled hydrocarbons, cable fillers and natural petroleum sulfonates. The Karns City facility’s processing capability includes hydrotreating, fractionation, acid treating, filtering, blending and packaging. In addition, the facility has approximately 817,000 barrels of storage capacity in 250 tanks and related loading and unloading facilities and utilities.
The Dickinson facility, located on a 28-acre site in Dickinson, Texas (“Dickinson”), has aggregate base oil throughput capacity of 1,300 bpd and processes white mineral oils, compressor lubricants and natural petroleum sulfonates. The Dickinson facility’s processing capability includes acid treating, filtering and blending, approximately 183,000 barrels of storage capacity in 186 tanks and related loading and unloading facilities and utilities.
The facilities each receive its base oil feedstocks by railcar and truck under supply agreements or spot purchases with various suppliers, the most significant of which is a long-term supply agreement with Phillips 66. Please read “— Crude Oil and Feedstock Supply” below for further discussion of the long-term supply agreement with Phillips 66.
The following table sets forth the combined historical information about production at our Karns City and Dickinson facilities. |
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| Combined Karns City, Dickinson and Other Facilities |
| Year Ended December 31, |
| 2012 | | 2011 | | 2010 |
| (in bpd) |
Feedstock throughput capacity (1) | 11,300 |
| | 11,300 |
| | 11,300 |
|
Total feedstock runs (2) (3) | 7,025 |
| | 7,823 |
| | 7,927 |
|
Total production (3) | 7,021 |
| | 7,803 |
| | 7,917 |
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(1) | Includes Karns City and Dickinson facilities only. |
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(2) | Includes feedstock runs at our Karns City and Dickinson facilities as well as throughput at certain third-party facilities pursuant to supply and/or processing agreements and includes certain interplant feedstocks supplied from our Shreveport refinery. For more information regarding our purchase commitments related to these supply and/or processing agreements, please read Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations and Commitments” for additional information. |
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(3) | Total production represents the barrels per day of specialty products yielded from processing feedstocks at our Karns City and Dickinson facilities and certain third-party facilities pursuant to supply and/or processing agreements. The difference between total production and total feedstock runs is primarily a result of the time lag between the input of feedstocks and the production of finished products. |
Terminals
Our terminals are complementary to our refineries and play a key role in moving our products to end-user markets by providing services including distribution and blending to achieve specified products and storage and inventory management. We operate the following terminals:
Burnham Terminal: We own and operate a terminal located on an 11-acre site, in Burnham, Illinois. The Burnham terminal receives specialty products from certain of our refineries by railcar and distributes them by truck to our customers in the Upper Midwest and East Coast regions of the U.S. and in Canada. The terminal includes a tank farm with 90 tanks having aggregate storage capacity of approximately 150,000 barrels, as well as blending equipment for producing engine oil additives and tackifiers.
Rhinelander Terminal: We own and operate a terminal located on an 18-acre site, in Rhinelander, Wisconsin. The Rhinelander terminal receives asphalt by truck from the Superior refinery and distributes the product by truck. Asphalt from this terminal is sold to customers in the Upper Midwest region of the U.S. The terminal includes a tank farm with four tanks with aggregate storage capacity of approximately 166,000 barrels.
Crookston Terminal: We own and operate a terminal located on a 19-acre site in Crookston, Minnesota. The Crookston terminal receives asphalt by truck from the Superior refinery and distributes by truck. Asphalt from this terminal is sold to customers in the Upper Midwest region of the U.S. The terminal includes a tank farm with three tanks with aggregate storage capacity of approximately 156,000 barrels.
Duluth Terminal: We own and operate a terminal located on a 49-acre site in Proctor, Minnesota. The Duluth terminal is supplied refined fuel products from the Superior refinery by the Magellan pipeline and receives ethanol and biodiesel products by truck and includes seven tanks with aggregate storage capacity of approximately 200,000 barrels. Fuel products from this terminal are distributed by truck to customers in Minnesota and northern Wisconsin.
In addition to the above terminals, we own and lease additional facilities, primarily related to distribution of finished products, throughout the U.S.
Other Logistics Assets
We also use approximately 2,700 railcars leased from various lessors. This fleet of railcars enables us to receive and ship crude oil and distribute various specialty products and fuel products throughout the U.S. and Canada to and from each of our facilities.
Our Crude Oil and Feedstock Supply
We purchase crude oil and other feedstocks from major oil companies, as well as from various crude oil gatherers and marketers in Texas, north Louisiana, North Dakota and Canada. Historically, the Shreveport refinery has received crude oil through the ExxonMobil pipeline system originating in St. James, Louisiana, providing the refinery with access to domestic crude oils and foreign crude oils through the LOOP or other terminal locations. However, the ExxonMobil pipeline has been shutdown since April 28, 2012, and as a result the Shreveport refinery received a portion of its crude oil requirements from other suppliers. For more information about the shutdown of the ExxonMobil pipeline, please read Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — 2012 Update.” The Superior refinery receives crude oil though the Enbridge Pipeline. The Superior refinery is adjacent to the first U.S. destination point for the Enbridge Pipeline after the U.S.-Canadian border, providing reliable access to crude oils from the Bakken shale oil formation in North Dakota and from western Canada. Further, in November 2012 we completed an expansion project at our Superior refinery, which enables the refinery to ship crude oil by railcar to our Shreveport refinery as well as third parties. The Montana refinery receives crude oil through the Front Range Pipeline via the Bow River Pipeline in Canada, providing reliable access to crude oil from western Canada. The San Antonio refinery receives crude oil through a pipeline connected to its Elmendorf terminal, providing reliable access to crude oil from the Eagle Ford Shale.
In 2012, subsidiaries of Plains supplied us with approximately 39.9% of our total crude oil supplies under term contracts and month-to-month evergreen crude oil supply contracts. In 2012, BP supplied us with approximately 25.1% of our total crude oil supplies under the BP Purchase Agreement. In addition, the Superior refinery receives up to 10,000 bpd of crude oil under the Murphy Crude Oil Supply Agreement. Each of our refineries is dependent on one or more key 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. For more information about the BP Purchase Agreement, please read the information provided under Note 5 “Commitments and Contingencies” in Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report.
We do not maintain long-term contracts with most of our crude oil suppliers. For example, our contracts with Plains are currently month-to-month, terminable upon 90 days’ notice. In April 2012, we amended and restated the BP Purchase Agreement, which has an initial term of one year ending April 1, 2013, and will automatically renew for successive one-year terms unless terminated by either party upon 90 days’ notice prior to the end of any renewal term. Since terminating crude oil supply agreements with Legacy Resources Co., L.P. (“Legacy Resources”) effective May 31, 2011, we have one remaining crude oil supply agreement with Legacy Resources under which we are not currently purchasing any crude oil; rather, we have purchased the crude oil supply for the Princeton and Shreveport refineries directly from third-party suppliers under month-to-month evergreen supply contracts and on the spot market. Refer to Part III, Item 13 “Certain Relationships and Related Transactions and Director Independence — Crude Oil Purchases” for further information on our related party crude oil purchases. We also purchase foreign crude oil when its spot market price is attractive relative to the price of crude oil from domestic sources. We believe that adequate supplies of crude oil will continue to be available to us.
Our cost to acquire crude oil and feedstocks and the prices for which we ultimately can sell refined products depend on a number of factors beyond our control, including regional and global supply of and demand for crude oil and other feedstocks and specialty and fuel products. These, in turn, are dependent upon, among other things, the availability of imports, overall economic conditions, production levels of domestic and foreign suppliers, U.S. relationships with foreign governments,
political affairs and the extent of governmental regulation. We have historically been able to pass on the costs associated with increased crude oil and feedstock prices to our specialty products customers, although the increase in selling prices for specialty products typically lags the rising cost of crude oil. From time to time, we use a hedging program to manage a portion of this commodity price risk. Please read Part II, Item 7A “Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk — Crude Oil Price Volatility and Hedging Policy” for a discussion of our crude oil hedging program for our specialty products segment.
We have various long-term supply agreements with Phillips 66, with remaining terms ranging from one to five years, with some agreements operating under the option to continue on a month-to-month basis thereafter, for feedstocks that are key to the operations of our Karns City and Dickinson facilities. In addition, certain products of our refineries can be used as feedstocks by these facilities. We believe that adequate supplies of feedstocks are available for these facilities.
Our Products, Markets and Customers
Products
We produce a full line of specialty products, including lubricating oils, solvents, waxes, packaged and synthetic specialty products, asphalt and other products, as well as a variety of fuel products. Our customers purchase these products primarily as raw material components for basic industrial, consumer and automotive goods. The following table depicts a representative sample of the diversity of end-use applications for the products we produce:
Representative Sample of End Use Applications by Product1
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Lubricating Oils | | Solvents | | Waxes | | Packaged and Synthetic Specialty Products | | Asphalt & Other By-Products | | Fuels & Fuel Related |
15% | | 10% | | 1% | | 1% | | 16% | | 57% |
| | | | | | | | | | |
• Hydraulic oils • Passenger car motor oils • Railroad engine oils • Cutting oils • Compressor oils • Metalworking fluids • Transformer oils • Rubber process oils • Industrial lubricants • Gear oils • Grease • Automatic transmission fluid • Animal feed dedusting • Baby oils • Bakery pan oils • Catalyst carriers • Gelatin capsule lubricants • Sunscreen | | • Waterless hand cleaners • Alkyd resin diluents • Automotive products • Calibration fluids • Camping fuel • Charcoal lighter fluids • Chemical processing • Drilling fluids • Printing inks • Water treatment • Paint and coatings • Stains
| | • Paraffin waxes • FDA compliant products • Candles • Adhesives • Crayons • Floor care • PVC • Paint strippers • Skin & hair care • Timber treatment • Waterproofing • Pharmaceuticals • Cosmetics | | • Refrigeration compressor oils • Commercial and military jet engine oil • Aviation hydraulic oils • High performance small engine fuels • Two cycle and four stroke engine oils • High performance passenger car oils • High performance industrial lubricants • High temperature chain lubricants • Charcoal lighter fluids • Engine treatment additives | | • Roofing • Paving | | • Gasoline • Diesel • Jet fuel • Marine diesel fuel • Biodiesel • Ethanol • Ethanol free fuels • Fluid catalytic cracking feedstock • Asphalt vacuum residuals • Mixed butanes • Heavy fuel oils
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(1) | Based on the percentage of actual total production for the year ended December 31, 2012 and includes the results of operations at our Missouri, TruSouth, Royal Purple and Montana operations commencing January 3, 2012, January 6, 2012, July 3, 2012 and October 1, 2012, respectively. Except for the listed fuel products and certain products sold by our Royal Purple and TruSouth facilities, we do not produce any of these end-use products. |
We have an experienced marketing department with average industry tenure of approximately 20 years. Our salespeople regularly visit customers and our marketing department works closely with both the laboratories at our refineries and our technical services 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 U.S., 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:
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• | industrial goods such as metalworking fluids, belts, hoses, sealing systems, batteries, hot melt adhesives, pressure sensitive tapes, electrical transformers, refrigeration compressors and drilling fluids; |
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• | consumer goods such as candles, petroleum jelly, creams, tonics, lotions, coating on paper cups, chewing gum base, automotive aftermarket car-care products (fuel injection cleaners, tire shines and polishes), lamp oils, charcoal lighter fluids, camping fuel and various aerosol products; and |
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• | automotive goods such as motor oils, greases, transmission fluid and tires. |
We have the capability to ship our specialty products worldwide. In the U.S. and Canada, we ship our specialty products via railcars, trucks and barges. In 2012, approximately 36.6% of our specialty products sales were shipped in our fleet of approximately 2,700 leased railcars, approximately 61.7% of our specialty products sales were shipped in trucks owned and operated by several different third-party carriers and the remaining 1.7% were shipped via water transportation. For shipments outside of North America, which accounted for less than 10% of our consolidated sales in 2012, we ship via railcars and trucks to several ports where the product is loaded on vessels for shipment to customers abroad.
Fuel Products. The fuel products market represents a large portion of the overall petroleum refining industry in the U.S. Of the nearly 150 refineries currently in operation in the U.S., a large number of the refineries are fuel products producers; however, only a few compete with us in our local markets.
Gulf Coast Market (PADD 3)
Fuel products produced at our Shreveport refinery can be sold locally or to the Midwest region of the U.S. through the TEPPCO pipeline. Local sales are made from the TEPPCO terminal in Bossier City, Louisiana, located approximately 15 miles from the Shreveport refinery, as well as from our own Shreveport refinery terminal.
Gasoline, diesel and jet fuel from the Shreveport refinery is sold primarily into the Louisiana, Texas and Arkansas markets, and any excess volumes are sold to marketers further up the TEPPCO pipeline. Should the appropriate market conditions arise, we have the capability to redirect and sell additional volumes into the Louisiana, Texas and Arkansas markets rather than transport them to the Midwest region via the TEPPCO pipeline.
The Shreveport refinery has the capacity to produce about 9,000 bpd of commercial jet fuel that can be marketed to the U.S. Department of Defense, sold as Jet-A locally or via the TEPPCO pipeline, or occasionally transferred to the Cotton Valley refinery to be processed further as a feedstock to produce solvents. We have a sales contract with the U.S. Department of Defense for approximately 3,900 bpd of jet fuel. This contract is effective until September 2013 and is bid annually.
Fuel products produced at our San Antonio refinery are sold locally in Texas. Additionally, the San Antonio refinery produces commercial and specialty jet fuel that can be marketed to the U.S. Department of Defense or sold locally as Jet-A fuel. We have a sales contract with the U.S. Department of Defense for approximately 550 bpd of jet fuel. This contract is effective until March 2014 with one year renewal increments through March 2017 at the option of the U.S. Department of Defense.
Additionally, we produce a number of fuel-related products including fluid catalytic cracking (“FCC”) feedstock, vacuum residuals and mixed butanes. FCC feedstock is sold to other refiners as a feedstock for their FCC units to make fuel products. Vacuum residuals are blended or processed further to make specialty asphalt products. Volumes of vacuum residuals which we cannot process are sold locally into the fuel oil market or sold via railcar to other refiners. Mixed butanes are primarily available in the summer months and are primarily sold to local marketers. If the mixed butanes are not sold, they are blended into our gasoline production.
Upper Midwest Market (PADD 2)
Fuel products produced at our Superior refinery can be sold locally and in the Upper Midwest region of the U.S. and in Canada. The Superior wholesale business sells fuel products produced at the Superior refinery through several Magellan pipeline terminals in Minnesota, Wisconsin, Iowa, North Dakota and South Dakota and through its own leased or owned product terminals located in Superior, Wisconsin and Duluth, Minnesota. The Superior wholesale business also sells gasoline wholesale to SPUR branded gas stations throughout the Upper Midwest, which are owned and operated by independent franchisees.
Northwest Market (PADD 4)
Fuel products produced at our Montana refinery can be sold locally and in Idaho and Canada via tank and railcar. Seasonally, the Montana refinery transports fuel products to terminals in Washington.
Customers
Specialty Products. We have a diverse customer base for our specialty products, with approximately 4,900 active accounts. Many of our customers are long-term customers who use our products in specialty applications, which after an approval process ranging from six months to two years. No single customer of our specialty products segment accounted for more than 10% of our consolidated sales in each of the three years ended December 31, 2012, 2011 and 2010.
Fuel Products. We have a diverse customer base for our fuel products, with approximately 330 active accounts. Our diverse customer base includes wholesale distributors and retail chains. We are able to sell the majority of the fuel products we produce at the Shreveport refinery to the local markets of Louisiana, Texas and Arkansas. We also have the ability to ship additional fuel products from the Shreveport refinery to the Midwest region through the TEPPCO pipeline should the need arise. Additionally, we are able to sell the majority of the fuel products we produce at the Superior refinery to local markets in Minnesota and Wisconsin. We also have the ability to ship additional fuel products from the Superior refinery to the Upper Midwest region through the Magellan pipeline. The majority of our fuel products produced at our Montana refinery are sold to local markets in Montana and Idaho as well as in Canada. Fuel products produced at our San Antonio refinery are sold to local markets in Texas. No single customer of our fuel products segment represented 10% or greater of consolidated sales in each of the three years ended December 31, 2012, 2011 and 2010.
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 exploration and production, 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, Phillips 66, Petro-Canada, HollyFrontier Corporation and Sonneborn Refined Products.
Paraffin Waxes. Our primary competitors in producing paraffin waxes include ExxonMobil and The International Group Inc.
Solvents. Our primary competitors in producing solvents include CITGO Petroleum Corporation, ExxonMobil Chemical and Phillips 66.
Packaged and Synthetic Specialty Products. Our primary competitors in retail packaged and synthetic specialty products include ExxonMobil (Mobil 1), Ashland, Inc. (Valvoline) and BP Lubricants, USA (Castrol). Our primary competitors in industrial packaged and synthetic specialty products include ExxonMobil, Shell and Chevron.
Fuel Products and By-Products. Our primary competitors in producing fuel products in the local markets in which we operate include Delek Refining, Ltd., Lion Oil Company, Flint Hills Resources, Northern Tier Energy, Inc., ExxonMobil, Valero Energy Corporation, Phillips 66 and Cenex.
Our ability to compete effectively depends on our responsiveness to customer needs and our ability to maintain competitive prices and product offerings. We believe that our flexibility and customer responsiveness differentiate us from many of our larger competitors. However, it is possible that new or existing competitors could enter the markets in which we operate, which could negatively affect our financial performance.
Environmental and Occupational Health and Safety Matters
We operate crude oil and specialty hydrocarbon refining and terminal operations, which are subject to stringent and complex federal, state, regional and local laws and regulations governing worker health and safety, the discharge of materials into the environment and environmental protection. These laws and regulations impose obligations that are applicable to our operations, such as requiring the acquisition of permits to conduct regulated activities, restricting the manner in which we may release materials into the environment, requiring remedial activities or capital expenditures to mitigate pollution from former or current operations, requiring the application of specific health and safety criteria addressing worker protection and imposing substantial liabilities on us for pollution resulting from our operations. Certain of these 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 or enforcement and other complaints from regulatory agencies alleging non-compliance with applicable environmental laws and regulations.
On December 23, 2010, we entered into a settlement agreement with the Louisiana Department of Environmental Quality (“LDEQ”) under LDEQ’s “Small Refinery and Single Site Refinery Initiative,” covering our Shreveport, Princeton and Cotton Valley refineries. This settlement agreement became effective on January 31, 2012. The settlement agreement, termed the “Global Settlement,” resolved alleged violations of the federal Clean Air Act and federal Clean Water Act regulations prior to December 31, 2010. Among other things we agreed to complete beneficial environmental programs and implement emissions reduction projects at our Shreveport, Cotton Valley and Princeton refineries, on an agreed-upon schedule. As of December 31, 2012, we have incurred approximately $4.2 million in expenditures and we estimate additional expenditures of approximately $2.0 million to $6.0 million of capital expenditures and expenditures related to additional personnel and environmental studies over the next three years as a result of the implementation of those requirements. These capital investment requirements will be incorporated into our annual capital expenditures budget and we do not expect any additional capital expenditures as a result of the required audits or required operational changes included in the settlement to have a material adverse effect on our financial results or operations. For additional information regarding the impact on our capital expenditures, please read Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Capital Expenditures.”
In connection with the Montana Acquisition which closed on October 1, 2012, we became a party to an existing 2002 Refinery Initiative consent decree (“Montana Consent Decree”) with the EPA and Montana Department of Environmental Quality (“MDEQ”). The material obligations imposed by the Montana Consent Decree have been completed. Periodic reporting is the primary current obligation under the Montana Consent Decree. On September 27, 2012, Montana Refining Company, Inc. received a final Corrective Action Order on Consent, replacing the refinery’s previous Hazardous Waste Permit. This Corrective Action Order on Consent governs the investigation and remediation of contamination at the Montana refinery. We believe that all such contamination is subject to the indemnification of Montana Refining Company, Inc. by Holly Corporation (“Holly”) for pre-existing conditions. We believe we are indemnified by Holly under that certain asset purchase agreement between Holly and Connacher, and we became a party to such indemnification rights to through the share purchase agreement between us and Connacher. Holly is responsible for existing environmental conditions at the Montana refinery and has been reimbursing Connacher for remedial actions subject to the indemnification.
In connection with the Superior Acquisition, we became a party to an existing consent decree (“Superior Consent Decree”) with the EPA and the Wisconsin Department of Natural Resources (“WDNR”) that applies, in part, to our Superior refinery. Under the Superior Consent Decree, we will have to complete certain reductions in air emissions at the Superior refinery as well as report upon certain emissions from the facility to the EPA and WDNR, and we currently estimate costs of approximately $3.0 million to make known equipment upgrades and conduct other discrete tasks in compliance with the Superior Consent Decree. Failure to perform required tasks under the Superior Consent Decree could result in the imposition of stipulated penalties, which could be significant. In addition, we may have to pursue certain additional environmental and safety-related projects at the Superior refinery including, but not limited to: (i) installing process equipment pursuant to applicable EPA fuel content regulations; (ii) purchasing emission credits on an interim basis until such time as any process equipment that may be required under the EPA fuel content regulations is installed and operational; (iii) performing monitoring of historical contamination at the facility; (iv) upgrading treatment equipment or possibly pursuing other remedies, as necessary, to satisfy new effluent discharge limits under a federal Clean Water Act permit renewal that is pending; and (v) pursuing various voluntary programs at the Superior refinery, including removing asbestos-containing materials or enhancing process safety or other maintenance practices. Completion of these additional projects would result in us incurring
additional costs, which could be substantial. During 2012 and 2011, we incurred approximately $2.4 million and $2.3 million, respectively, in costs related to installing process equipment pursuant to the fuel content regulations.
On June 29, 2012, the EPA issued a Finding of Violation/Notice of Violation to our Superior refinery. This finding is in response to information provided to the EPA by us in response to an information request. The EPA alleges that the efficiency of the flares our Superior refinery is lower than regulatory requirements. We are contesting the allegations and attended an informal conference with the EPA held September 12, 2012. We do not believe that the resolution of these allegations will have a material adverse effect on our financial results or operations.
The 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 Emissions
Our operations are subject to the federal Clean Air Act, as amended, and comparable state and local laws. The federal 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 federal Clean Air Act, facilities that emit volatile organic compounds or nitrogen oxides face increasingly stringent regulations, including requirements to install various levels of control technology on sources of pollutants. In addition, the petroleum refining sector has come under stringent new EPA regulations, imposing maximum achievable control technology (“MACT”) on refinery equipment emitting certain listed hazardous air pollutants. Some of our facilities have been included within the categories of sources regulated by MACT rules. In addition, air permits are required for our refining and terminal operations that result in the emission of regulated air contaminants. These permits incorporate stringent control technology requirements and are subject to extensive review and periodic renewal. We believe that we are in substantial compliance with the federal Clean Air Act and similar state and local laws.
The federal 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 U.S. 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”). Additionally, the EPA promulgated the Mobile Source Air Toxics II (“MSAT II”) standards that require reduced benzene levels in refined products. The Shreveport, Superior, Montana and San Antonio refineries have implemented the sulfur standard with respect to produced gasoline and produces diesel meeting the ultra-low sulfur standard. To the extent we exceed the minimum requirements of the MSAT II Standards, we have the option to sell RINs Credits and have the option to purchase RINs Credits if we operate a refinery in a manner that does not meet these minimum requirements. We cannot currently predict the future prices of RINs Credits or waiver credits, but the costs to obtain the necessary number of RINs Credits and waiver credits could be material.
Pursuant to the Energy Act of 2005 and 2007, the EPA has issued Renewable Fuels Standards II (“RFS II”) that implement mandates to blend renewable fuels into the petroleum fuels produced at our refineries. Under RFS II, the EPA establishes a volume of renewable fuels that obligated refineries must blend into their finished petroleum fuels. While the minimum volume of renewable fuels that must be blended with refined petroleum fuels is currently set, existing laws and regulations could change and require increases in such volume. Any such increase in volume displaces volume of our Shreveport, Superior, Montana and San Antonio refineries’ product pool, potentially resulting in lower earnings and materially adversely affecting our ability to make distributions. In addition, we are required to meet the MSAT II regulations to reduce the benzene content of motor gasoline produced at our facilities. We have completed capital projects at our Shreveport and Superior refineries to comply with these fuel quality requirements.
Climate Change
In response to findings by the EPA in December 2009 that emissions of carbon dioxide, methane and other “greenhouse gases” (“GHG”) present an endangerment to public health and the environment because emissions of such gases are
contributing to the warming of the earth’s atmosphere and other climate changes, the EPA has adopted regulations under existing provisions of the federal Clean Air Act, establishing Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit program requiring reviews for GHG emissions from certain large stationary sources. Facilities required to obtain PSD permits for their GHG emissions will also be required to meet “best available control technology” standards, which will be established by the states or, in some instances, by the EPA on a case-by-case basis. Moreover, on December 23, 2010, the EPA entered a settlement agreement with environmental groups requiring the agency to propose by December 10, 2011 GHG New Source Performance Standards (“NPNS”) for refineries and to finalize these rules by November 15, 2012. To date, the EPA has not completed those rulemakings and we do not know when they will be completed. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified large GHG emission sources in the United States, including petroleum refineries, on an annual basis. These EPA policies and rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities.
In addition, from time to time Congress has considered legislation to reduce emissions of GHG, and almost one-half of the states have already taken legal measures to reduce emissions of GHG, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of any legislation or regulations that requires reporting of GHG or otherwise limits emissions of GHG from our equipment and operations could require us to incur costs to reduce emissions of GHG associated with our operations or could adversely affect demand for the refined petroleum products that we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHG in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations.
Hazardous Substances and Wastes
The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as the “Superfund” law, and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. Such classes of persons include the current and past owners and operators of sites where a hazardous substance was released, and companies that disposed or arranged for disposal of hazardous substances at offsite locations, such as landfills. Under CERCLA, these “responsible persons” may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances into the environment. In the course of our operations, we generate wastes or handle substances that may be regulated as hazardous substances, and we could become subject to liability under CERCLA and comparable state laws.
We also may incur liability under the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state laws, which impose requirements related to the handling, storage, treatment and disposal of hazardous and non-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 non-hazardous solid wastes, which are regulated under RCRA and state laws. We believe that we are in substantial compliance with the existing requirements of RCRA and similar state and local laws, and the cost involved in complying with these requirements is not material.
We currently own or operate, and have in the past owned or operated, properties that for many years have been used for refining and terminal activities. These properties have in the past been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons and wastes was not under our control. Although we used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes have been released on or under the properties owned or operated by us. These properties and the materials disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes or property contamination, or to perform remedial activities to prevent future contamination.
In addition, new laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement or other developments could require us to make additional unforeseen expenditures. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. For example, on June 1, 2012, the EPA issued final amendments to the NSPS for petroleum refineries, including standards for emissions of nitrogen oxides from process heaters and work practice standards and monitoring requirements for flares. We are currently evaluating the effect that the NSPS rule may have on our operations.
Voluntary remediation of subsurface contamination is in process at each of our refinery sites. These projects are being overseen by the appropriate state agencies. Based on current investigative and remedial activities, we believe that the groundwater contamination at these refineries can be controlled or remedied without having a material adverse effect on our financial condition. However, such costs are often unpredictable and, therefore, there can be no assurance that the future costs will not become material. We incurred approximately $0.4 million and $0.3 million in 2012 and 2011, respectively, of such capital expenditures at our Cotton Valley refinery.
Water Discharges
The Federal Water Pollution Control Act of 1972, as amended, also known as the federal 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 oil 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 federal Clean Water Act and similar state laws.
The primary federal law for oil spill liability is the Oil Pollution Act of 1990, as amended (“OPA”), which addresses three principal areas of oil pollution — prevention, containment and cleanup. OPA applies to vessels, offshore facilities and onshore facilities, including refineries, terminals and associated facilities that may affect waters of the U.S. Under OPA, responsible parties, including owners and operators of onshore facilities, may be subject to oil cleanup costs and natural resource damages as well as a variety of public and private damages from oil spills. We believe that we are in substantial compliance with OPA and similar state laws.
Occupational Health and Safety
We are subject to various laws and regulations relating to occupational health and safety, including the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state laws. These laws and 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, contractors, state and local government authorities and customers. We maintain safety and training programs as part of our ongoing efforts to ensure compliance with applicable laws and regulations. We have implemented an internal program of inspection designed to monitor and enforce compliance with worker safety requirements as well as a quality system that meets the requirements of the ISO-9001-2008 Standard. The integrity of our ISO-9001-2008 Standard certification is maintained through surveillance audits by our registrar at regular intervals designed to ensure adherence to the standards. Our compliance with applicable health and safety laws and regulations has required and continues to require substantial expenditures. Changes in occupational safety and health laws and regulations or a finding of non-compliance with current laws and regulations could result in additional capital expenditures or operating expenses, as well as civil penalties and, in the event of a serious injury or fatality, criminal charges.
We have completed studies to assess the adequacy of our process safety management practices at our Shreveport refinery with respect to certain consensus codes and standards. As of December 31, 2012, we have incurred approximately $0.7 million of capital expenditures and expect to incur between $1.0 million and $4.0 million of capital expenditures during 2013 to address OSHA compliance issues identified in these studies. We expect these capital expenditures will enhance our equipment such that the equipment maintains compliance with applicable consensus codes and standards.
In the first quarter of 2011, OSHA conducted an inspection of the Cotton Valley refinery’s process safety management program under OSHA’s National Emphasis Program. On March 14, 2011, OSHA issued a Citation and Notification of Penalty (the “Cotton Valley Citation”) to us as a result of our Cotton Valley inspection, which included a proposed penalty amount of $0.2 million. We have contested the Cotton Valley Citation and associated penalties and are currently in negotiations with OSHA to reach a settlement allowing an extended abatement period for a new refinery flare system study and for completion of facility site modifications, including relocation and hardening of structures. Notwithstanding the Cotton Valley Citation, we believe our total operations are in substantial compliance with OSHA and similar state laws.
Other Environmental and Maintenance 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 the 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.
In addition, we are indemnified by Murphy Oil for specified environmental liabilities arising from the operations of the Superior refinery including: (i) certain obligations arising out of the Superior Consent Decree (including payment of a civil penalty required under the Superior Consent Decree), (ii) certain liabilities arising in connection with Murphy Oil’s transport of certain wastes and other materials to specified offsite real properties for disposal or recycling prior to the Superior Acquisition and (iii) certain liabilities for certain third party actions, suits or proceedings alleging exposure, prior to the Superior Acquisition, of an individual to wastes or other materials at the specified on-site real property, which wastes or other materials were spilled, released, emitted or discharged by Murphy Oil. We are also indemnified by Murphy Oil for two years following the Superior Acquisition for liabilities arising from breaches of certain environmental representations and warranties made by Murphy Oil, subject to a maximum liability of $22.0 million, for which we are required to contribute up to the first $6.6 million.
We perform preventive and normal maintenance on all of our refining and logistics assets and make repairs and replacements when necessary or appropriate. We also conduct inspections of these assets as required by law or regulation.
Insurance
Our operations are subject to certain hazards of operations, including fire, explosion and weather-related perils. We maintain insurance policies, including business interruption insurance for each of our facilities, with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent. We cannot, however, ensure that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices. We are not fully insured against certain risks because such risks are not fully insurable, coverage is unavailable, or premium costs, in our judgment, do not justify such expenditures.
Seasonality
The operating results for the fuel products segment and the selling prices of asphalt products we produce can be seasonal. Asphalt demand is generally lower in the first and fourth quarters of the year as compared to the second and third quarters due to the seasonality of annual road construction. Demand for gasoline is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic. In addition, our natural gas costs can be higher during the winter months. As a result, our operating results for the first and fourth calendar quarters may be lower than those for the second and third calendar quarters of each year due to this seasonality.
Properties
We own and lease the properties listed below. The properties we own are pledged as collateral under our Collateral Trust Agreement as discussed in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Debt and Credit Facilities.” We believe that all properties are suitable for their intended purpose, are being efficiently utilized and provide adequate capacity to meet demand for the next several years.
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Property | | Business Segments | | Acres | | Owned / Leased | | Location |
Shreveport refinery | | Fuels and Specialty | | 240 |
| | Owned | | Shreveport, Louisiana |
Superior refinery and terminal | | Fuels and Specialty | | 675 |
| | Owned | | Superior, Wisconsin |
Montana refinery | | Fuels and Specialty | | 86 |
| | Owned | | Great Falls, Montana |
San Antonio refinery | | Fuels | | 32 |
| | Owned | | San Antonio, Texas |
Princeton refinery | | Specialty | | 208 |
| | Owned | | Princeton, Louisiana |
Cotton Valley refinery | | Specialty | | 77 |
| | Owned | | Cotton Valley, Louisiana |
Burnham terminal | | Specialty | | 11 |
| | Owned | | Burnham, Illinois |
Karns City facility | | Specialty | | 225 |
| | Owned | | Karns City, Pennsylvania |
Dickinson facility | | Specialty | | 28 |
| | Owned | | Dickinson, Texas |
Rhinelander terminal | | Specialty | | 18 |
| | Owned | | Rhinelander, Wisconsin |
Crookston terminal | | Specialty | | 19 |
| | Owned | | Crookston, Minnesota |
Missouri facility | | Specialty | | 22 |
| | Owned | | Louisiana, Missouri |
TruSouth facility | | Specialty | | 10 |
| | Leased | | Shreveport, Louisiana |
Royal Purple facility | | Specialty | | 23 |
| | Owned | | Porter, Texas |
Elmendorf terminal | | Fuels | | 8 |
| | Owned | | Elmendorf, Texas |
Duluth terminal | | Fuels | | 49 |
| | Owned | | Proctor, Minnesota |
Duluth marine terminal | | Fuels | | 3 |
| | Leased | | Duluth, Minnesota |
In addition to the items listed above, we lease or own a number of storage tanks, railcars, equipment, land and precious metals.
Office Facilities
In addition to our refineries and terminals discussed above, we occupy the following square feet of office space, all of which are under leases:
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Location | | Square Feet |
Indianapolis, Indiana | | 36,566 |
El Dorado, Arkansas | | 1,600 |
Louisiana, Missouri | | 4,600 |
Kingwood, Texas | | 2,466 |
San Antonio, Texas | | 41,000 |
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.
Employees
As of February 28, 2013, our general partner employs approximately 1,250 people who provide direct support to our operations. Of these employees, approximately 580 are covered by collective bargaining agreements. Employees at the following locations are covered by the following separate collective bargaining agreements:
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Facility/ Refinery | | Union | | Expiration Date |
Superior | | International Union of Operating Engineers | | June 30, 2017 |
Cotton Valley | | International Union of Operating Engineers | | March 31, 2013 |
Princeton | | International Union of Operating Engineers | | October 31, 2014 |
Dickinson | | International Union of Operating Engineers | | March 31, 2013 |
Shreveport | | United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied-Industrial and Service Workers International Union | | April 30, 2013 |
Missouri | | United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied-Industrial and Service Workers International Union | | April 30, 2014 |
Karns City | | United Steel, Paper and Forestry, Rubber, Manufacturing, Energy Allied-Industrial and Service Workers International Union | | January 31, 2015 |
Montana | | United Steel, Paper and Forestry, Rubber, Manufacturing, Energy Allied-Industrial and Service Workers International Union | | January 31, 2015 |
None of the employees at the San Antonio refinery, TruSouth facility, Royal Purple facility or at the Burnham, Rhinelander, Crookston, Duluth or Elmendorf terminals 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.
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. We make available, free of charge on our website, our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These documents are located on our website at http://www.calumetspecialty.com — by selecting the “Investor Relations” link and then selecting the “SEC Filings” link. We also make available, free of charge on our website, our Charters for the Audit, Compensation and Conflicts Committees, Related Party Transactions Policy and Code of Business Conduct and Ethics. These documents are located on our website at http://www.calumetspecialty.com — by selecting the “Investor Relations” link and then selecting the “Corporate Governance” link.
The above information is available to anyone who requests it and is free of charge either in print from our website or upon request by contacting Investor Relations using the contact information listed above. Information on our website is not incorporated into this Annual Report or our other securities filings and is not a part of them.
Item 1A. Risk Factors
Risks Relating to our Business
We may not have sufficient cash from operations to enable us to pay the minimum quarterly distribution following the establishment of cash reserves and payment of fees and expenses, including payments to our general partner.
We may not have sufficient available cash from operations each quarter to enable us to pay the minimum quarterly distribution. Under the terms of our partnership agreement, we must pay expenses, including payments to our general partner, and set aside any cash reserve amounts before making a distribution to our unitholders. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which is primarily dependent upon our producing and selling quantities of fuel and specialty products, or refined products, at margins that are high enough to cover our fixed and variable expenses. Crude oil costs, fuel and specialty products prices and, accordingly, the cash we generate from operations, will fluctuate from quarter to quarter based on, among other things:
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• | overall demand for specialty hydrocarbon products, fuel and other refined products; |
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• | the level of foreign and domestic production of crude oil and refined products; |
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• | our ability to produce fuel and specialty products that meet our customers’ unique and precise specifications; |
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• | the marketing of alternative and competing products; |
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• | the extent of government regulation; |
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• | results of our hedging activities; and |
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• | overall economic and local market conditions. |
In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:
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• | the level of capital expenditures we make, including those for acquisitions, if any; |
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• | our debt service requirements; |
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• | fluctuations in our working capital needs; |
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• | our ability to borrow funds and access capital markets; |
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• | restrictions on distributions and on our ability to make working capital borrowings for distributions contained in our debt instruments; and |
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• | the amount of cash reserves established by our general partner for the proper conduct of our business. |
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 and for payments of our debt obligations.
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 ranged from a high of $40.47 per barrel to a low of $14.42 per barrel during 2012 and averaged $26.34 per barrel during 2012 compared to an average of $25.41 in 2011 and $9.90 in 2010.
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 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 quickly enough 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 an 18.3% increase in the average sales price per barrel of our specialty products. It is possible we may not be able
to pass on all or any portion of increased crude oil costs to our customers. In addition, we are not able to completely eliminate our commodity risk through our hedging activities.
Because refining margins are volatile, unitholders should not assume that our current margins will be sustained. If our refining margins fall, it will adversely affect the amount of cash we will have available for distribution to our unitholders.
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. From time to time, 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. Historically, we have utilized derivative instruments related to interest rates for future periods with the intent of reducing volatility in our cash flows due to fluctuations in interest rates. We are not able to enter into derivative financial instruments to reduce the volatility of the prices of the specialty products we sell as there is no established derivative market for such products.
The extent of our commodity price exposure is related largely to the effectiveness and scope of our hedging activities. 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. For example, excluding our crude oil basis swaps, all of the crude oil derivatives in our hedge portfolio are based on the market price of NYMEX WTI and the fuel products derivatives are all based on U.S. Gulf Coast market prices. In recent periods, the spread between NYMEX WTI and other crude oil indices (specifically Light Louisiana Sweet, Western Canadian Select and Brent, on which a portion of our crude oil purchases are priced) has widened, which has reduced the effectiveness of certain crude oil hedges. Accordingly, our commodity price risk management policy may not protect us from significant and sustained increases in crude oil or natural gas prices or decreases in fuel products prices. Conversely, our policy may limit our ability to realize cash flows from crude oil and natural gas price decreases.
We have a policy to enter into derivative transactions related to only a portion of the volume of our expected purchase and sales requirements and, as a result, we will continue to have direct commodity price exposure to the unhedged portion of our expected purchase and sales requirements. For example, during 2010 we entered into monthly crude oil collars and swaps to hedge up to approximately 11,000 bpd of crude oil purchases related to our specialty products segment, which had average total daily production for 2010 of approximately 32,000 bpd. During 2011, we had significantly reduced the volume and duration of our crude oil collars and derivative instruments and hedged approximately 3,100 bpd of crude oil purchases through March 31, 2011. Thus, we could be exposed to significant crude oil cost increases on a portion of our purchases. Please read Part II, Item 7A “Quantitative and Qualitative Disclosures About Market Risk.”
Our actual future purchase and sales requirements may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, which may result in a substantial diminution of our liquidity. As a result, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows. In addition, our hedging activities are subject to the risks that a counterparty may not perform its obligations under the applicable derivative instrument, the terms of the derivative instruments are imperfect, and our hedging policies and procedures are not properly followed. It is possible that the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.
Our financing arrangements contain operating and financial provisions that restrict our business and financing activities.
The operating and financial restrictions and covenants in our financing arrangements, including our revolving credit facility, indentures governing the 2019 Notes and 2020 Notes (as defined under Note 6 “Long-Term Debt” in Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report) and master derivative contracts, do currently restrict, 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, including restrictions on our ability to, among other things:
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• | sell assets, including equity interests in our subsidiaries; |
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• | pay distributions or redeem or repurchase our units or repurchase our subordinated debt; |
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• | incur or guarantee additional indebtedness or issue preferred units; |
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• | create or incur certain liens; |
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• | make certain acquisitions and investments; |
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• | redeem or repay other debt or make other restricted payments; |
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• | enter into transactions with affiliates; |
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• | enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us; |
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• | create unrestricted subsidiaries; |
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• | enter into sale and leaseback transactions; |
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• | enter into a merger, consolidation or transfer or sale of assets, including equity interests in our subsidiaries; and |
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• | engage in certain business activities. |
Our revolving credit facility also contains a springing financial covenant which provides that, if availability under the revolving credit facility falls below the greater of (i) 12.5% of the lesser of (a) the Borrowing Base (as defined in the revolving credit agreement) (without giving effect to the LC Reserve (as defined in the revolving credit agreement)) and (b) the revolving credit agreement commitments then in effect and (ii) $46.4 million, then we will be required to maintain as of the end of each fiscal quarter a Fixed Charge Coverage Ratio (as defined in the revolving credit agreement) of at least 1.0 to 1.0.
Our existing indebtedness imposes, and any future indebtedness may impose, a number of covenants on us regarding collateral maintenance and insurance maintenance. As a result of these covenants and restrictions, we will be limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.
Our ability to comply with the covenants and restrictions contained in our financing arrangements may be affected by events beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants and restrictions may be impaired. A failure to comply with the covenants, ratios or tests in our financing arrangements or any future indebtedness could result in an event of default under these financing arrangements, which, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations. Among other things, in the event of any default on our indebtedness, our debt holders and lenders:
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• | will not be required to lend any additional amounts to us; |
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• | could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable; |
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• | could elect to require that all obligations accrue interest at the default rate, if such rate has not already been imposed; |
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• | may have the ability to require us to apply all of our available cash to repay these borrowings; |
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• | may prevent us from making debt service payments under our other agreements, any of which could result in an event of default under our other financing arrangements; or |
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• | in the case of our revolving credit facility, foreclose on the collateral pledged pursuant to the terms of the revolving credit facility. |
If an acceleration of our debt 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 indebtedness or it may not be on terms that are acceptable to us.
If our existing indebtedness were to be accelerated, there can be no assurance that we would have, or be able to obtain, sufficient funds to repay such indebtedness in full. In addition, our obligations under our revolving credit facility are secured by a first priority lien on our cash, accounts receivable, inventory and certain other personal property and our obligations under our master derivative contracts are secured by a first priority lien on our real property, plant and equipment, fixtures, intellectual property, certain financial assets, certain investment property, commercial tort claims, chattel paper, documents, instruments and proceeds of the forgoing (including proceeds of hedge agreements), and if we are unable to repay our indebtedness under the revolving credit facility or master derivative contracts, the lenders under our revolving credit facility and the counterparties to our master derivative contracts could seek to foreclose on these assets. Please read Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Debt and Credit Facilities,” “—Short Term Liquidity,” “—Long-Term Financing,” and “—Master Derivative Contracts” for additional information regarding our long-term debt.
Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.
We had approximately $880.5 million of outstanding indebtedness as of December 31, 2012 and availability for borrowings of $355.1 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 an aggregate principal amount of $850.0 million at any time outstanding, subject to borrowing base limitations, under our senior secured revolving credit facility. Our level of indebtedness could have important consequences to us, including the following:
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• | our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms; |
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• | covenants contained in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities; |
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• | we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and payments of our debt obligations, including the 2019 Notes and 2020 Notes; and |
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• | our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally. |
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 to our unitholders, 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. Please read Part II, 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 regarding our indebtedness.
Decreases in the price of crude oil may lead to a reduction in the borrowing base under our revolving credit facility and our ability to issue letters of credit or the requirement that we post substantial amounts of cash collateral for derivative instruments, which could adversely affect our liquidity, financial condition and our ability to distribute cash to our unitholders.
We rely on borrowings and letters of credit under our revolving credit agreement to purchase crude oil or other feedstocks for our facilities, lease certain precious metals for use in our refinery operations and enter into derivative instruments of crude oil and natural gas purchases and fuel products sales. We also rely on our ability to issue letters of credit to enter into certain hedging arrangements in an effort to reduce our exposure to adverse fluctuations in the prices of crude oil, natural gas and crack spreads. The borrowing base under our revolving credit facility is determined weekly or monthly depending upon availability levels or the existence of a default or event of default. 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 the amount of financial resources available to meet our capital requirements. If, under certain circumstances, our available capacity under our revolving credit facility falls below certain threshold amounts, or a default or event of default exists, then our cash balances in a dominion account established with the administrative agent will be applied on a daily basis to our outstanding obligations under our revolving credit facility. In addition, decreases in the price of crude oil may require us to post substantial amounts of cash collateral to our hedging counterparties in order to maintain our derivative instruments. If, due to our financial condition or other reasons, the borrowing base under our revolving credit facility decreases, we are limited in our ability to issue letters of credit or we are required to post substantial amounts of cash collateral to our hedging counterparties, our liquidity, financial condition and our ability to distribute cash to our unitholders could be materially and adversely affected. Please read Part II, 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.
A failure in our information technology infrastructure or applications could negatively affect our business.
We have begun implementing a new enterprise resource planning (“ERP”), system to further enhance operating efficiencies and provide more effective management of our business operations. The new ERP system is being deployed for use throughout our company in a number of “go live” phases, the first of which occurred during the first quarter of 2013 with company-wide deployment expected to be completed by the end of 2013. Implementing a new ERP system is costly and involves risks inherent in the conversion to a new computer system, including loss of information, disruption to our normal operations, changes in accounting procedures and internal control over financial reporting, as well as problems achieving
accuracy in the conversion of electronic data. Failure to properly or adequately address these issues could result in increased costs, the diversion of management’s and employees’ attention and resources and could materially adversely affect our operating results, internal controls over financial reporting and ability to manage our business effectively. While the ERP system is intended to further improve and enhance our information systems, large scale implementation of a new information system exposes us to the risks of starting up the new system and integrating that system with our existing systems and processes, including possible disruption of our financial reporting, which could lead to a failure to make required filings under the federal securities laws on a timely basis.
We depend on certain key crude oil and other feedstock suppliers for a significant portion of our supply of crude oil and other feedstocks, and the loss of any of these key suppliers or a material decrease in the supply of crude oil and other feedstocks generally available to our facilities could materially reduce our ability to make distributions to unitholders.
We purchase crude oil and other feedstocks from major oil companies as well as from various crude oil gatherers and marketers primarily in Texas, north Louisiana, North Dakota and Canada. In 2012, subsidiaries of Plains supplied us with approximately 39.9% of our total crude oil supplies under term contracts and month-to-month evergreen crude oil supply contracts. In 2012, BP supplied us with approximately 25.1% of our total crude oil supplies under the BP Purchase Agreement. In addition, the Superior refinery receives up to 10,000 bpd of crude oil under the Murphy Crude Oil Supply Agreement. Each of our facilities is dependent on one or more of these suppliers and the loss of any of these suppliers would adversely affect our financial results to the extent we were unable to find another supplier of this substantial amount of crude oil. We do not maintain long-term contracts with most of our suppliers. For example, our contracts with Plains are currently month-to-month and terminable upon 90 days’ notice and our contract with BP was amended and restated in April 2012 and has an initial term of one year ending April 1, 2013, will automatically renew for successive one-year terms unless terminated by either party upon 90 days’ notice.
We purchase all of the crude oil supply directly from third-party suppliers, under month-to-month evergreen supply contracts and on the spot market. These evergreen contracts are generally terminable upon 30 days’ notice and purchases on the spot market may expose us to changes in commodity prices. For additional discussion regarding our crude oil and feedstock supply, please read Items 1 and 2 “Business and Properties — Our Crude Oil and Feedstock Supply.”
To the extent that our suppliers reduce the volumes of crude oil and other feedstocks that they supply us as a result of declining production or competition or otherwise, our sales, net income and cash available for distribution to unitholders and payments of our debt obligations would decline unless we were able to acquire comparable supplies of crude oil and other feedstocks on comparable terms from other suppliers, which may not be possible in areas where the supplier that reduces its volumes is the primary supplier in the area. 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. A material decrease in either the crude oil production from or the drilling activity in the fields that supply our refineries, as a result of depressed commodity prices, natural production declines, governmental moratoriums on drilling or production activities, the availability and the cost of capital or otherwise, could result in a decline in the volume of crude oil we refine.
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 distributions to our unitholders and payment of our debt obligations could decline.
Our Shreveport refinery is interconnected to pipelines that supply most of its crude oil and ship a portion of its refined fuel products to customers, such as pipelines operated by subsidiaries of Enterprise Products Partners L.P. and ExxonMobil. Our Superior refinery receives crude oil though the Enbridge Pipeline and the Superior wholesale business transports products produced at the Superior refinery through several Magellan pipeline terminals in Minnesota, Wisconsin, Iowa, North Dakota and South Dakota. Our Montana refinery receives crude oil through the Front Range pipeline system via the Bow River Pipeline in Canada. Since we do not own or operate any of these pipelines, their continuing operation is not within our control. In addition, any of these third-party pipelines could become unavailable to transport crude oil or our refined fuel products because of acts of God, accidents, earthquakes or hurricanes, government regulation, terrorism or other third-party events. For example, our refinery run rates were affected by an approximately three-week shutdown during May and June 2011 of the ExxonMobil crude oil pipeline serving our Shreveport refinery resulting from the Mississippi River flooding occurring during this period. In addition, ExxonMobil shut down this pipeline on April 28, 2012 after a leak was discovered, and the portion of this pipeline serving our Shreveport refinery remains shutdown. Also, on June 20, 2012, excessive flooding caused our Superior refinery to reduce its run rate to approximately half its usual throughput for one day and shut down the portion of the Magellan pipeline that connects our Superior refinery to our Duluth terminal. The unavailability of any of these third-party pipelines for the transportation of crude oil or our refined fuel products, because of acts of God, accidents, earthquakes or hurricanes,
government regulation, terrorism or other third-party events, could lead to disputes or litigation with certain of our suppliers or a decline in our sales, net income and cash available for distributions to our unitholders and payments of our debt obligations.
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 $1.91 and $3.90 per million British thermal unit, or MMBtu, in 2012 and between $2.99 and $4.85 per MMBtu in 2011. 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 16.2% and 19.6% of our total operating expenses included in cost of sales for the years ended December 31, 2012 and 2011, 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 refineries, terminals and related facility operations face operating hazards, and the potential limits on insurance coverage could expose us to potentially significant liability costs.
Our refineries, terminals and related facility operations are subject to certain operating hazards, and our cash flow from those operations could decline if any of our facilities experiences a major accident, pipeline rupture or spill, explosion or fire, is damaged by severe weather or other natural disaster, or otherwise is forced to curtail its operations or shut down. For example, on February 5, 2010, our Shreveport refinery experienced an explosion that caused us to shut down one of this refinery’s environmental operating units until August 2010 when it was replaced with a newly constructed unit, resulting in modified operations during the interim period, including lower throughput rates at certain times during this period. These operating hazards could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in significant curtailment or suspension of our related operations.
Although we maintain insurance policies, including personal and property damage and business interruption insurance for each of our facilities with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent, we cannot ensure that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or significant interruption of operations. Our business interruption insurance will not apply unless a business interruption exceeds 90 days. Furthermore, we may be unable to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. In addition, we are not fully insured against all risks incident to our business because certain risks are not fully insurable, coverage is unavailable, or premium costs, in our judgment, do not justify such expenditures. For example, we are not insured for environmental accidents at all of our facilities. If we were to incur a significant liability for which we were not fully insured, it could diminish our ability to make distributions to our unitholders.
Our business subjects us to the inherent risk of incurring significant environmental costs and liabilities in the operation of our refineries, terminals and related facilities.
There is inherent risk of incurring significant environmental costs and liabilities in the operation of refineries, terminals, and related facilities due to our handling of petroleum hydrocarbons and wastes, because of air emissions and water discharges related to our operations, and as a result of historical operations and waste disposal practices of prior owners of our facilities. We currently own or operate properties that for many years have been used for industrial activities, including refining or terminal storage operations, sometimes by third parties over whom we had no control with respect to their operations or waste disposal activities. Petroleum hydrocarbons or wastes have been released on, under or from the properties owned or operated by us. For example, we are currently investigating and remediating, in some cases pursuant to government order, soil and groundwater contamination at our Montana refinery arising from a predecessor operators’ handling of petroleum hydrocarbons and wastes. Our costs in pursuing these investigatory and remedial activities are subject to reimbursement under a contractual indemnification we received from our predecessor operator in the share purchase agreement transferring ownership of this refinery. We expect that our costs in completing these investigatory and remedial activities will be reimbursed under the contractual indemnification. Joint and several strict liability may be incurred in connection with releases of petroleum hydrocarbons and wastes on, under or from our properties and facilities. 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. 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. To the extent that the costs associated with meeting any or all of these requirements are substantial and not adequately provided for, there could be a material adverse effect on our business, financial condition, and results of operations.
We are subject to compliance with stringent environmental and occupational health and safety laws and regulations that may expose us to substantial costs and liabilities.
Our refining, terminal and related facility operations are subject to stringent and complex federal, regional, state and local laws and regulations governing worker health and safety, the discharge of materials into the environment and environmental protection. These laws and regulations impose numerous obligations that are applicable to our operations, including the obligation to obtain permits to conduct regulated activities, the incurrence of significant capital expenditures for air pollution control equipment or otherwise limit or prevent releases of pollutants from our refineries, terminals, and related facilities, the expenditure of significant monies in the application of specific health and safety criteria addressing worker protection, the requirement to maintain information about hazardous materials used or produced in our operations and to provide this information to employees, state and local government authorities, and local residents and the incurrence of substantial costs and liabilities for pollution resulting from our operations or from those of prior owners or operators of our facilities. Numerous governmental authorities, such as the EPA, OSHA and state agencies, such as the LDEQ and the WDNR, 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 these laws, regulations, permits and orders may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations or corrective actions, and the issuance of injunctions limiting or preventing some or all of our operations. On occasion, we receive notices of violation, enforcement proceedings and regulatory inquiries from governmental agencies alleging non-compliance with applicable environmental and occupational health and safety laws and regulations. In addition, new laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement or other developments could require us to make additional unforeseen expenditures. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. For example, on September 12, 2012, the EPA issued final amendments to the NSPS for petroleum refineries, including standards for emissions of nitrogen oxides from process heaters and work practice standards and monitoring requirements for flares. We are currently evaluating the effect that the NSPS rule may have on our refinery operations. We are not able to predict the impact of new or changed laws or regulations or changes in the ways that such laws or regulations are administered, interpreted or enforced but we may incur increased operating costs and capital expenditures to comply, which could be material. To the extent that the costs associated with meeting any of these requirements are substantial and not adequately provided for, our results of operations and cash flows could suffer. Please read Items 1 and 2 “Business and Properties — Environmental and Occupational Health and Safety Matters” for additional information regarding our communications with the LDEQ and OSHA.
Renewable fuels mandates may reduce demand for the petroleum fuels we produce, which could have a material adverse effect on our results of operations and financial condition, and our ability to make distributions to our unitholders.
Pursuant to the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007, the EPA has issued Renewable Fuels Standards (“RFS”) implementing mandates to blend renewable fuels into the petroleum fuels produced and sold in the United States. Under RFS, the volume of renewable fuels that obligate refineries like the Shreveport, Superior, Montana and San Antonio refineries, for example, to blend into their finished petroleum fuels increases annually over time until 2022. To the extent we exceed the minimum requirements of MSAT II standards in our operations, we have the option to sell renewable identification number credits (“RINs Credits”) and have the option to purchase RINs Credits if we operate the refineries in a manner that does not meet these minimum requirements. We cannot currently predict the future prices of RINs or waiver credits, but the costs to obtain the necessary number of RINs Credits and waiver credits could be material. On October 13, 2010, the EPA raised the maximum amount of ethanol allowed under federal law from 10% to 15% for cars and light trucks manufactured since 2007, and on January 21, 2011, EPA extended the maximum allowable ethanol content of 15% to apply to cars and light trucks manufactured since 2001. The maximum amount allowed under federal law currently remains at 10% ethanol for all other vehicles. Existing laws and regulations could change, and the minimum volumes of renewable fuels that must be blended with refined petroleum fuels may increase. Moreover, increasing the volume of renewable fuels that must be blended into our products displaces an increasing volume of our Shreveport, Superior, Montana and San Antonio refineries’ fuel products pool, potentially resulting in lower earnings and materially adversely affecting our ability to make distributions.
Downtime for maintenance at our refineries and facilities will reduce our revenues and cash available for distributions to our unitholders and payments of our debt obligations.
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 and increase our operating expenses during the period of time that our processing units are not operating and could reduce our ability to make distributions to our unitholders.
If we do not successfully execute our growth through acquisitions, our future growth and ability to increase distributions to our unitholders 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 consummate acquisitions on favorable terms, (3) unable to obtain financing for these acquisitions on economically acceptable terms, or (4) outbid by competitors, then our future growth and ability to increase distributions to our unitholders will be limited. Furthermore, any acquisition, including the Superior Acquisition, Missouri Acquisition, TruSouth Acquisition, Royal Purple Acquisition, Montana Acquisition and San Antonio Acquisition, our most recent acquisitions, involve potential risks, including, among other things:
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• | performance from the acquired assets and businesses that is below the forecasts we used in evaluating the acquisition; |
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• | a significant increase in our indebtedness and working capital requirements; |
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• | an inability to timely and effectively integrate the operations of recently acquired businesses or assets, particularly those in new geographic areas or in new lines of business; |
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• | the incurrence of substantial seen or unforeseen environmental and other liabilities arising out of the acquired businesses or assets; |
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• | the diversion of management’s attention from other business concerns; |
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• | customer or key employee losses at the acquired businesses; and |
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• | significant changes in our capitalization and results of operations. |
We may not be successful in acquiring additional assets, and any acquisitions that we do consummate may not produce the anticipated benefits or may have adverse effects on our business and operating results.
Our asset reconfiguration and enhancement initiatives may not result in revenue or cash flow increases, may be subject to significant cost overruns and are subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our business, operating results, cash flows and financial condition.
Historically we have grown our business in part through the reconfiguration and enhancement of our existing refinery assets. As a specific example, we completed an expansion project at our Shreveport refinery to increase throughput capacity and crude oil processing flexibility in May 2008. This expansion project and the construction of other additions or modifications to our existing refineries have and will continue to involve numerous regulatory, environmental, political, legal, labor and economic uncertainties beyond our control, which could cause delays in construction or require the expenditure of significant amounts of capital, which we may finance with additional indebtedness or by issuing additional equity securities. Our forecasted internal rates of return on such projects are also based on our projections of future market fundamentals, which are not within our control, including changes in general economic conditions, available alternative supply and customer demand. For example, the total cost of the Shreveport refinery expansion project completed in 2008 was approximately $375.0 million and was significantly over budget due primarily to increased construction labor costs. Future reconfiguration and enhancement projects may not be completed at the budgeted cost, on schedule, or at all due to the risks described above which could significantly affect our cash flows and financial condition.
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 and payments of our debt obligations could be reduced.
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.
Distributions to unitholders and payments of our debt obligations 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 could reduce their demand for our specialty products. Our specialty products customers are primarily in the industrial goods, consumer goods and automotive goods industries and we are therefore susceptible to overall economic conditions, which may change demand patterns and products in those industries. Consequently, it is important that we develop and manufacture new products to replace the sales of products that mature and decline in use. If we are unable to manage successfully the maturation of our existing specialty products and the introduction of new specialty products our revenues, net income and cash available for distribution to our unitholders and payments of our debt obligations could be reduced.
Distributions to unitholders and payments of our debt obligations 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 and payments of our debt obligations. Factors that could lead to a decrease in market demand include:
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• | a recession or other adverse economic condition that results in lower spending by consumers on gasoline, diesel, and travel; |
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• | higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of fuel products; |
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• | an increase in fuel economy or the increased use of alternative fuel sources; |
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• | an increase in the market price of crude oil that lead to higher refined product prices, which may reduce demand for fuel products; |
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• | availability of raw materials. |
We depend on unionized labor for the operation of our facilities. Any work stoppages or labor disturbances at these facilities could disrupt our business.
Substantially all of our operating personnel at our Shreveport, Superior, Montana, Princeton, Cotton Valley, Karns City, Dickinson and Missouri facilities are employed under collective bargaining agreements that expire in April 2013, June 2017, January 2015, October 2014, March 2013, January 2015, March 2013 and April 2014, respectively. Our inability to renegotiate these agreements as they expire, any work stoppages or other labor disturbances at these facilities could have an adverse effect on our business and reduce our ability to make distributions to our unitholders. In addition, employees who are not currently represented by labor unions may seek union representation in the future, and any renegotiation of current collective bargaining agreements may result in terms that are less favorable to us.
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 operating results for our fuel products segment and the asphalt we produce and sell are seasonal and generally lower in the first and fourth quarters of the year.
The operating results for the fuel products segment and the selling prices of asphalt products we produce can be seasonal. Asphalt demand is generally lower in the first and fourth quarters of the year as compared to the second and third quarters due to the seasonality of road construction. Demand for gasoline is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic. In addition, our natural gas costs can be higher during the winter months. Our operating results for the first and fourth calendar quarters may be lower than those for the second and third calendar quarters of each year as a result of this seasonality.
Due to our lack of asset and geographic diversification, adverse developments in our operating areas would reduce our ability to make distributions to our unitholders.
We rely primarily on sales generated from products processed at the facilities we own. Furthermore, the majority of our assets and operations are located in Louisiana, Wisconsin, Montana and Texas. Due to our lack of diversification in asset type and location, an adverse development in these businesses or areas, including adverse developments due to catastrophic events or weather, decreased supply of crude oil and feedstocks and/or decreased demand for refined petroleum products, would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets in more diverse locations.
Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and a decreased demand for our refined products.
In 2009, the EPA adopted rules for establishing a reporting program for emissions of carbon dioxide, methane and other GHG from specified large GHG emissions sources in the U.S., including refineries, and subsequently expanded the scope of this rule to include the reporting of GHG emissions from onshore oil and natural gas processing, transmission, storage and distribution facilities. Operators of covered sources in the U.S. must annually monitor and report these GHG emissions to EPA and certain state agencies. Our refineries and certain of our other facilities are subject to the federal GHG reporting requirements because of combustion GHG emissions and potential fugitive emissions that exceed reporting thresholds. While our compliance with this reporting program has increased our operating costs, we presently do not believe that these increased costs have a material adverse effect on our results of operations.
Following its determination in December 2009 that emissions of GHG present a danger to public health and the environment, the EPA promulgated regulations in 2010 establishing Title V and PSD, permitting requirements for large sources of GHG that apply to certain of our facilities, including our refineries, which are potential major sources of GHG emissions. In the absence of any control requirements for GHG for our facilities that would need to be incorporated into existing Title V permits, we believe the impact of these permitting requirements on our facilities will not be material. However, we may be required to install “best available control technology” to limit emissions of GHG from any new or significantly modified facilities that we may seek to construct in the future if they would otherwise emit large volumes of GHG. Best available control technology is determined on a case-by-case basis by the relevant permitting agency to date, whether EPA or state. PSD permits with GHG emissions limitations have generally required efficient combustion requirements on sources that burn large volumes of fossil fuels rather than post-combustion GHG capture requirements. If the EPA imposes efficient combustion requirements, we do not anticipate that they will have a material adverse effect on the cost of our operations. Moreover, as part of a settlement in December 2010 with certain environmental groups derived out of legal challenges seeking judicial review of an EPA final rule on standards of performance for petroleum refineries, the EPA agreed to propose new source performance standards for GHG emissions from petroleum refineries by December 10, 2011. While no such standards have been proposed by the EPA to date, we expect the agency to pursue this rulemaking in 2013. Depending on the nature of the requirements imposed by the EPA as part of this rulemaking, we could encounter increased operating costs and capital expenditures that could be significant.
While the U.S. Congress has from time to time considered legislation to reduce emissions of GHG, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation in the U.S., a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions. Two of the more significant non-federal GHG programs are the Regional Greenhouse Gas Initiative, or “RGGI,” and California’s cap-and-trade program. RGGI, which includes a number of states in the northeastern U.S., implemented a cap-and-trade program in 2009. At present, this program only applies to utility power plants. None of our facilities are affected by RGGI. California’s cap-and-trade program will enter into force in January 2013 and will impose
compliance obligations upon certain industrial GHG emitters. At present, California is evaluating a formal linkage with Quebec’s cap-and-trade program under the WCI. We do not operate in California and do not expect that our operations will be impacted by the implementation of California’s cap-and-trade program.
If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform will include a carbon tax. A carbon tax could impose additional direct costs on our operations and reduce demand for refined products. The ultimate impact of any carbon tax on our operations would further depend upon whether a carbon tax supplanted the other federal GHG regulations to which we are currently subject or is administered as an additional program.
Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our services, results of operations, and cash flows. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHG in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events that could have an adverse effect on our assets and operations.
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 and payments of our debt obligations.
The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to hedge risks associated with our business.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Act requires the Commodity Futures Trading Commission (“CFTC”) and the SEC to promulgate rules and regulations implementing the Act. In its rulemaking under the Act, the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or derivative instruments would be exempt from these position limits. The position limits rule was vacated by the United States District Court for the District of Colombia in September 2012 although the CFTC recently has stated that it will appeal the District Court’s decision. The CFTC also has finalized other regulations, including critical rulemakings on the definition of “swap,” “security-based swap,” “swap dealer” and “major swap participant.” Some regulations, however, remain to be finalized and it is not possible at this time to predict when this will be accomplished and when the compliance date for those regulations will commence. The Act also may require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivatives activities, although the application of those provisions to us and the schedule for effectiveness of those regulations is uncertain at this time. The Act also may require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The Act and any new regulations could significantly increase the cost of derivative instruments (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative instruments, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivatives contracts, and increase our exposure to less creditworthy counterparties. An increase in the cost of derivatives contracts would affect our results of operations and cash flow available for distribution to our unitholders and payments of our debt obligations. If we reduce our use of derivatives as a result of the Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and make distributions to our unitholders and payments of our debt obligations. Finally, the Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our business, our financial condition, and our results of operations.
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.
An increase in interest rates will cause our debt service obligations to increase.
Borrowings under our revolving credit facility bear interest at a rate equal to prime plus a basis points margin or LIBOR plus a basis points margin, at our option. As of December 31, 2012, there were no borrowings outstanding under our revolving credit facility. The interest rate is subject to adjustment based on fluctuations in the London Interbank Offered Rate (“LIBOR”) or prime rate, as applicable. 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.
A change of control could result in us facing substantial repayment obligations under our revolving credit agreement, our 2019 Notes, 2020 Notes and our Collateral Trust Agreement.
Certain events relating to a change of control of our general partner, our partnership and our operating subsidiaries would constitute an event of default under our revolving credit agreement, the indentures governing our 2019 Notes and 2020 Notes and our Collateral Trust Agreement. In addition, an event of default under our revolving credit agreement would likely constitute an event of default under our master derivatives contracts and a crude oil purchase agreement with BP (the “BP Purchase Agreement”). As a result, upon a change of control event, we may be required immediately to repay the outstanding principal, any accrued interest on and any other amounts owed by us under our revolving credit facility and the 2019 Notes and 2020 Notes and the outstanding payment obligations under our master derivatives contracts and the BP Purchase Agreement. The source of funds for these repayments would be our available cash or cash generated from other sources and there can be no assurance that we would have, or be able to obtain, sufficient funds to repay such indebtedness and other payment obligations in full. In addition, our obligations under our revolving credit facility are secured by a first priority lien on our cash, accounts receivable, inventory and certain related assets and our obligations under our master derivatives contracts and the BP Purchase Agreement are secured by a first priority lien on our real property, plant and equipment, fixtures, intellectual property, certain financial assets, certain investment property, commercial tort claims, chattel paper, documents, instruments and proceeds of the forgoing (including proceeds of hedge agreements). If we are unable to repay our indebtedness under the revolving credit facility, the payment obligations under our master derivative contracts or the payment obligations under the BP Purchase Agreement or obtain waivers of such defaults, then the lenders under our revolving credit facility, the derivative counterparties under our master derivative contracts and BP would have the right to foreclose on those assets, which would have a material adverse effect on us. There is no restriction in our partnership agreement on the ability of our general partner to enter into a transaction which would trigger the change of control provisions of our revolving credit facility agreement, the indentures governing our 2019 Notes and 2020 Notes or our Collateral Trust Agreement.
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 derivative instruments. 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 and payments of our debt obligations.
Risks Inherent in an Investment in Us
At February 28, 2013, the families of our chairman, chief executive officer and vice chairman, The Heritage Group and certain of their affiliates own a 28.7% 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.
At February 28, 2013, the families of our chairman, chief executive officer and vice chairman, the Heritage Group, and certain of their affiliates own a 28.7% limited partner interest in us. In addition, The Heritage Group and the families of our chairman and chief executive officer and vice chairman own our general partner. Conflicts of interest may arise between our general partner and its affiliates, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, the general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:
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• | our general partner is allowed to take into account the interests of parties other than us, such as its affiliates, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders; |
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• | our general partner has limited its liability and reduced its fiduciary duties under our partnership agreement and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty. As a result of purchasing common units, unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under Delaware law; |
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• | our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities, and reserves, each of which can affect the amount of cash that is distributed to unitholders; |
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• | our general partner determines which costs incurred by it and its affiliates are reimbursable by us; |
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• | our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is a maintenance capital expenditure, which reduces operating surplus, or a capital expenditure for acquisitions or capital improvements, which does not. This determination can affect the amount of cash that is available for distribution to our unitholders and payments of our debt obligations; |
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• | our general partner has the flexibility to cause us to enter into a broad variety of derivative transactions covering different time periods, the net cash receipts from which will increase operating surplus and adjusted operating surplus, with the result that our general partner may be able to shift the recognition of operating surplus and adjusted operating surplus between periods to increase the distributions it and its affiliates receive on their incentive distribution rights; and |
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• | in some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions. |
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 U.S. for so long as it controls us. This restriction does not apply to certain assets and businesses which are more fully described under Part III, Item 13 “Certain Relationships and Related Transactions and Director Independence — Omnibus Agreement.”
Although Mr. Grube is prohibited from competing with us pursuant to the terms of his employment agreement, the owners of our general partner, other than The Heritage Group, are not prohibited from competing with us.
Our partnership agreement limits our general 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:
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• | Permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of our partnership or amendment of our partnership agreement; |
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• | Provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership; |
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• | Generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms |
no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us. In determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and
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• | Provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that such person’s conduct was criminal. |
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 66 2/3% of all outstanding units voting together as a single class is required to remove the general partner. At February 28, 2013, the owners of our general partner and certain of their affiliates own 28.7% of our common units.
Our partnership agreement restricts the voting rights of those unitholders owning 20% or more of our common units.
Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
Control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the members of our general partner from transferring their respective membership interests in our general partner to a third party. The new members of our general partner would then be in a position to replace the board of directors and officers of our general partner with their own choices and thereby control the decisions taken by the board of directors.
We do not have our own officers and employees and rely solely on the officers and employees of our general partner and its affiliates to manage our business and affairs.
We do not have our own officers and employees and rely solely on the officers and employees of our general partner and its affiliates to manage our business and affairs. We can provide no assurance that our general partner will continue to provide us the officers and employees that are necessary for the conduct of our business nor that such provision will be on terms that are acceptable to us. If our general partner fails to provide us with adequate personnel, our operations could be adversely impacted and our cash available for distribution to unitholders and payments of our debt obligations could be reduced.
We may issue additional common units without unitholder approval, which would dilute our current unitholders’ existing ownership interests.
We may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Our partnership agreement does not give our unitholders the right to approve our issuance of equity securities ranking junior to the
common units at any time. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities, which may effectively rank senior to the common units. The issuance of additional common units or other equity securities of equal or senior rank to the common units will have the following effects:
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• | our unitholders’ proportionate ownership interest in us may decrease; |
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• | the amount of cash available for distribution on each unit may decrease; |
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• | the relative voting strength of each previously outstanding unit may be diminished; |
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• | the market price of the common units may decline; and |
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• | the ratio of taxable income to distributions may increase. |
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.
We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets and our ability to distribute cash to our unitholders and make payments of our debt obligations depends on the performance of our subsidiaries and their ability to distribute funds to us.
We are a holding company, and our subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets other than the equity interests in our subsidiaries. As a result, our ability to distribute cash to our unitholders and payments of debt obligations depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, our revolving credit facility, the indentures governing our 2019 Notes and 2020 Notes and applicable state laws and other laws and regulations. If we are unable to obtain the funds necessary to distribute cash to our unitholders or make payments of debt obligations, we may be required to adopt one or more alternatives, such as a refinancing of our indebtedness or incurring borrowings under our revolving credit facility. We cannot assure unitholders that we would be able to refinance our indebtedness or that the terms on which we could refinance our indebtedness would be favorable.
Cost reimbursements due to our general partner and its affiliates will reduce cash available for distribution to unitholders and payments of our debt obligations.
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 and payments of our debt obligations. These expenses will include all costs incurred by our general partner and its affiliates in managing and operating us. Please read Part III, Item 13 “Certain Relationships and Related Transactions and Director Independence.”
Our general partner has a limited call right that may require unitholders to sell their units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80% of the issued and outstanding common units, our general partner will have the right, but not the obligation, which right it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their common units to our general partner, its affiliates or us at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their common units. At February 28, 2013, our general partner and its affiliates own approximately 28.7% of the common units.
Unitholder liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other
states in which we do business. Unitholders could be liable for any and all of our obligations as if they were a general partner if:
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• | a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or |
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• | unitholders’ right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business. |
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, which we call the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Purchasers of units who become limited partners are liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to the purchaser of the units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
Our common units have a low trading volume compared to other units representing limited partner interests.
Our common units are traded publicly on the NASDAQ Global Select Market under the symbol “CLMT.” However, our common units have a low average daily trading volume compared to many other units representing limited partner interests quoted on the NASDAQ Global Select Market. The price of our common units may continue to be volatile.
The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:
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• | our quarterly distributions; |
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• | our quarterly or annual earnings or those of other companies in our industry; |
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• | changes in commodity prices or refining margins; |
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• | loss of a large customer; |
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• | announcements by us or our competitors of significant contracts or acquisitions; |
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• | changes in accounting standards, policies, guidance, interpretations or principles; |
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• | general economic conditions; |
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• | the failure of securities analysts to cover our common units or changes in financial estimates by analysts; |
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• | future sales of our common units; and |
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• | the other factors described in Item 1A “Risk Factors” of this Annual Report. |
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for U.S. 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, were to treat us as a corporation for federal income tax purposes or we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to our unitholders could be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes.
Despite the fact that we are organized as 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 will be 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 our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our 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, treatment of us 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.
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 anticipated quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. 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 changes or differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Currently, one such legislative proposal would eliminate the qualifying income exception upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. 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. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible to meet the expectation for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes.
Unitholders will be required to pay taxes on their share of our income 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 that could be different in amount than the cash we distribute, unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income whether or not they receive 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 which results from that income.
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 as a partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could 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 the calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, after our termination we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income result in a decrease in such unitholder’s tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the units they sell will, in effect, become taxable income to our 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 of depreciation and deductions and certain other items. 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-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investments in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (or “IRAs”), 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, and non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their shares of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing 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 to our unitholders.
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 by the IRS may materially and adversely impact the market for our common units and the price at which they trade. Our costs of any contest by the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.
We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units, we will adopt 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 unitholder’s sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to their tax returns.
We have historically conducted portions of our operations through a subsidiary that is treated as a corporation for U.S. federal income tax purposes, and is therefore subject to corporate-level income taxes and may conduct additional activities in subsidiaries treated as a corporation in the future.
We have historically conducted portions of our operations in which we market finished petroleum products to certain customers through a subsidiary that was organized as a corporation. We may elect to conduct additional operations through this corporate subsidiary in the future. This corporate subsidiary is obligated to pay corporate income taxes, which reduce the corporation’s cash available for distribution to us and, in turn, to our unitholders. If the IRS were to successfully assert that this corporation has more tax liability than we anticipate or legislation were enacted that increased the corporate tax rate, our cash available for distribution to our unitholders would be further reduced.
We will 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 generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. Nonetheless, we allocate certain deductions for depreciation of capital additions based upon the date the underlying property is placed in service. The use of this proration method may not be permitted under existing Treasury Regulations, and although the U.S. Treasury Department issued proposed Treasury Regulations allowing a similar monthly simplifying convention, such regulations are not final and do not specifically authorize the use of the proration method we have adopted. If the IRS were to successfully challenge our proration method, we may be required to change the allocation of items of income, gain, loss, and deduction among our unitholders.
We have adopted certain valuation methodologies for U.S. federal income tax purposes that may result in a shift of income, gain, loss, and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss, and deduction between certain unitholders and our general partner, which may be unfavorable to such
unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss, and deduction between our general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units) may be considered as having disposed of those common units. If so, he would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
Because there is no tax concept of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, he may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common 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 should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.
Unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our common units.
In addition to U.S. federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. We own assets and conduct business in 44 states. Our unitholders may be required to file state and local income tax returns and pay state and local income taxes in any state in which we now or may conduct business in the future. Further, they may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is the responsibility of our unitholders to file all U.S. federal, foreign, state and local tax returns.
Item 1B. Unresolved Staff Comments
None.
Item 3. Legal Proceedings
We are not a party to, and our property is not the subject of, any pending legal proceedings other than ordinary routine litigation incidental to our business. Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. Please see Items 1 and 2 “Business and Properties — Environmental and Occupational Health and Safety Matters” for a description of our current regulatory matters related to the environment, health and safety. Additionally, the information provided under Note 5 “Commitments and Contingencies” in Part II, Item 8 “Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements” is incorporated herein by reference.
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Item 4. | Mine Safety Disclosures |
Not applicable.
PART II
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Item 5. | Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities |
Market Information
Our common units are quoted and traded on the NASDAQ Global Select Market (“NASDAQ”) under the symbol “CLMT.” 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.
|
| | | | | | | | | | | |
| Low | | High | | Cash Distribution per Unit (1) |
2011: | | | | | |
First quarter | $ | 19.81 |
| | $ | 24.95 |
| | $ | 0.475 |
|
Second quarter | $ | 20.00 |
| | $ | 23.75 |
| | $ | 0.495 |
|
Third quarter | $ | 16.05 |
| | $ | 23.95 |
| | $ | 0.50 |
|
Fourth quarter | $ | 15.99 |
| | $ | 20.17 |
| | $ | 0.53 |
|
2012: | | | | | |
First quarter | $ | 20.00 |
| | $ | 27.50 |
| | $ | 0.56 |
|
Second quarter | $ | 20.76 |
| | $ | 27.74 |
| | $ | 0.59 |
|
Third quarter | $ | 24.01 |
| | $ | 32.02 |
| | $ | 0.62 |
|
Fourth quarter | $ | 27.53 |
| | $ | 33.96 |
| | $ | 0.65 |
|
| |
(1) | We also paid cash distributions to our general partner with respect to its 2% general partner interest and, to the extent distributions exceeded $0.495 per unit, its incentive distribution rights, as described below in “Cash Distribution Policy — General Partner Interest and Incentive Distribution Rights.” |
As of February 28, 2013, there were approximately 30 unitholders of record of our common units. The actual number of unitholders is greater than the number of holders of record. As of February 28, 2013, there were 63,279,778 common units outstanding. The last reported sale price of our common units by NASDAQ on February 28, 2013 was $38.36.
Cash Distribution Policy
General. Within 45 days after the end of each quarter, we distribute our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date.
Available Cash. Available cash generally means, for any quarter, all cash on hand at the end of the quarter:
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• | less the amount of cash reserves established by our general partner to: |
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• | provide for the proper conduct of our business; |
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• | comply with applicable law, any of our debt instruments or other agreements; and |
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• | provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters. |
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• | plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being made. Working capital borrowings are generally borrowings that will be made under our revolving credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners. |
Intent to Distribute the Minimum Quarterly Distribution. We distribute to the holders of common units on a quarterly basis at least the minimum quarterly distribution of $0.45 per unit, or $1.80 in aggregate 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 exists, under our debt instruments, including our revolving credit agreement and the indentures governing our 2019 and 2020 Notes. 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 debt instruments that restrict our ability to make distributions. On February 14, 2013, we paid a quarterly cash distribution of $0.65 per unit on all outstanding units totaling approximately $44.5 million for the quarter ended December 31, 2012 to all unitholders of record as of the close of business on February 4, 2013.
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 1,174,077 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 in our partnership agreement) in excess of $0.495 per unit. The maximum distribution of 50% includes distributions paid to our general partner on its 2% general partner interest, and assumes that our general partner maintains its general partner interest at 2%. The maximum distribution of 50% does not include any distributions that our general partner may receive on units that it owns. Our general partner earned incentive distribution rights of approximately $5.4 million and $0.3 million during the years ended December 31, 2012 and December 31, 2011, respectively.
Conversion of Subordinated Units. In February 2011, we satisfied the last of the earnings and distribution tests contained in our partnership agreement for the automatic conversion of all 13,066,000 outstanding subordinated units into common units on a one-for-one basis. The last of these requirements was met upon payment of the quarterly distribution paid on February 14, 2011. Two days following this quarterly distribution to unitholders, or February 16, 2011, all of the outstanding subordinated units automatically converted to common units.
Our general partner is entitled to incentive distributions if the amount we distribute to unitholders with respect to any quarter exceeds specified target levels shown below:
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| | | | | | | |
| Total Quarterly Distribution Target Amount Per Common Unit | | Marginal Percentage Interest in Distributions |
| | Unitholders | | General Partner |
Minimum Quarterly Distribution | $0.45 | | 98 | % | | 2 | % |
First Target Distribution | up to $0.495 | | 98 | % | | 2 | % |
Second Target Distribution | above $0.495 up to $0.563 | | 85 | % | | 15 | % |
Third Target Distribution | above $0.563 up to $0.675 | | 75 | % | | 25 | % |
Thereafter | above $0.675 | | 50 | % | | 50 | % |
Equity Compensation Plans
The equity compensation plan information required by Item 201(d) of Regulation S-K in response to this Item 5 is incorporated by reference into Part III, Item 12 “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters,” of this Annual Report.
Sales of Unregistered Securities
None.
Issuer Purchases of Equity Securities
None.
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Item 6. | Selected Financial Data |
The following table shows selected historical consolidated financial and operating data of the Company. The selected historical consolidated financial data as of and after December 31, 2008 and December 31, 2012, includes the operations acquired as part of the acquisitions of Penreco, Superior, Missouri, TruSouth, Royal Purple and Montana from their respective dates of acquisition, January 3, 2008, September 30, 2011, January 3, 2012, January 6, 2012, July 3, 2012 and October 1, 2012.
The following table includes the non-GAAP financial measures EBITDA, Adjusted EBITDA and Distributable Cash Flow. For a reconciliation of EBITDA, Adjusted EBITDA and Distributable Cash Flow to net income and net cash provided by operating activities, our most directly comparable financial performance and liquidity measures calculated in accordance with U.S. generally accepted accounting principles (“GAAP”), please read “—Non-GAAP Financial Measures.”
We derived the information in the following table from, and the information should be read together with, and is qualified in its entirety by reference to, the historical consolidated financial statements and the accompanying notes included in Item 8 “Financial Statements and Supplementary Data” except for operating data, such as sales volume, feedstock runs and facility production. The following table also should be read together with Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
|
| | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2012 | | 2011 | | 2010 | | 2009 | | 2008 |
| (In thousands, except unit, per unit and operating data) |
Summary of Operations Data: | | | | | | | | | |
Sales | $ | 4,657,282 |
| | $ | 3,134,923 |
| | $ | 2,190,752 |
| | $ | 1,846,600 |
| | $ | 2,488,994 |
|
Cost of sales | 4,144,105 |
| | 2,860,793 |
| | 1,992,003 |
| | 1,673,498 |
| | 2,235,111 |
|
Gross profit | 513,177 |
| | 274,130 |
| | 198,749 |
| | 173,102 |
| | 253,883 |
|
Operating costs and expenses: | | | | | | | | | |
Selling | 41,556 |
| | 12,237 |
| | 8,436 |
| | 9,389 |
| | 10,986 |
|
General and administrative | 60,904 |
| | 38,599 |
| | 26,788 |
| | 23,181 |
| | 23,281 |
|
Transportation | 107,900 |
| | 94,187 |
| | 85,471 |
| | 67,967 |
| | 84,702 |
|
Taxes other than income taxes | 9,073 |
| | 5,661 |
| | 4,601 |
| | 3,839 |
| | 4,598 |
|
Insurance recoveries | — |
| | (8,698 | ) | | — |
| | — |
| | — |
|
Other | 7,816 |
| | 6,852 |
| | 1,963 |
| | 1,366 |
| | 1,576 |
|
Operating income | 285,928 |
| | 125,292 |
| | 71,490 |
| | 67,360 |
| | 128,740 |
|
Other income (expense): | | | | | | | | | |
Interest expense | (85,573 | ) | | (48,747 | ) | | (30,497 | ) | | (33,573 | ) | | (33,938 | ) |
Debt extinguishment costs | — |
| | (15,130 | ) | | — |
| | — |
| | (898 | ) |
Realized gain (loss) on derivative instruments | 9,452 |
| | (7,909 | ) | | (7,704 | ) | | 8,342 |
| | (58,833 | ) |
Unrealized gain (loss) on derivative instruments | (3,787 | ) | | (10,383 | ) | | (15,843 | ) | | 23,736 |
| | 3,454 |
|
Gain on sale of mineral rights | — |
| | — |
| | — |
| | — |
| | 5,770 |
|
Other | 470 |
| | 842 |
| | (147 | ) | | (3,929 | ) | | 399 |
|
Total other expense | (79,438 | ) | | (81,327 | ) | | (54,191 | ) | | (5,424 | ) | | (84,046 | ) |
Income before income taxes | 206,490 |
| | 43,965 |
| | 17,299 |
| | 61,936 |
| | 44,694 |
|
Income tax expense | 753 |
| | 929 |
| | 598 |
| | 151 |
| | 257 |
|
Net income | $ | 205,737 |
| | $ | 43,036 |
| | $ | 16,701 |
| | $ | 61,785 |
| | $ | 44,437 |
|
|
| | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2012 | | 2011 | | 2010 | | 2009 | | 2008 |
| (In thousands, except unit, per unit and operating data) |
Weighted average limited partner units outstanding: | | | | | | | | | |
Basic | 55,559,000 |
| | 42,599,000 |
| | 35,334,720 |
| | 32,372,000 |
| | 32,232,000 |
|
Diluted | 55,677,000 |
| | 42,644,000 |
| | 35,351,020 |
| | 32,372,000 |
| | 32,232,000 |
|
Limited partners’ interest basic net income per unit | $ | 3.51 |
| | $ | 0.98 |
| | $ | 0.46 |
| | $ | 1.87 |
| | $ | 1.35 |
|
Limited partners’ interest diluted net income per unit | $ | 3.50 |
| | $ | 0.98 |
| | $ | 0.46 |
| | $ | 1.87 |
| | $ | 1.35 |
|
Cash distributions declared per limited partner unit | $ | 2.30 |
| | $ | 1.94 |
| | $ | 1.83 |
| | $ | 1.80 |
| | $ | 1.98 |
|
Balance Sheet Data (at period end): | | | | | | | | | |
Property, plant and equipment, net | $ | 986,875 |
| | $ | 842,101 |
| | $ | 612,433 |
| | $ | 629,275 |
| | $ | 659,684 |
|
Total assets | 2,253,045 |
| | 1,732,058 |
| | 1,016,672 |
| | 1,031,856 |
| | 1,081,062 |
|
Accounts payable | 333,416 |
| | 302,826 |
| | 171,565 |
| | 106,926 |
| | 90,177 |
|
Long-term debt | 863,501 |
| | 587,090 |
| | 369,275 |
| | 401,058 |
| | 465,091 |
|
Total partners’ capital | 889,793 |
| | 728,900 |
| | 398,279 |
| | 485,347 |
| | 473,212 |
|
Cash Flow Data: | | | | | | | | | |
Net cash flow provided by (used in): | | | | | | | | | |
Operating activities | $ | 380,108 |
| | $ | 63,778 |
| | $ | 134,143 |
| | $ | 100,854 |
| | $ | 130,341 |
|
Investing activities | (624,234 | ) | | (460,424 | ) | | (34,759 | ) | | (22,714 | ) | | (480,461 | ) |
Financing activities | 276,236 |
| | 396,673 |
| | (99,396 | ) | | (78,139 | ) | | 350,133 |
|
Other Financial Data: | | | | | | | | | |
EBITDA | $ | 383,732 |
| | $ | 170,851 |
| | $ | 108,083 |
| | $ | 157,244 |
| | $ | 135,396 |
|
Adjusted EBITDA | 404,610 |
| | 211,020 |
| | 138,462 |
| | 151,117 |
| | 126,534 |
|
Distributable Cash Flow | 281,125 |
| | 127,158 |
| | 76,202 |
| | 98,667 |
| | 78,153 |
|
Operating Data (bpd): | | | | | | | | | |
Total sales volume (1) | 97,789 |
| | 66,134 |
| | 55,668 |
| | 57,086 |
| | 56,232 |
|
Total feedstock runs (2) | 97,600 |
| | 69,295 |
| | 55,957 |
| | 60,081 |
| | 56,243 |
|
Total facility production (3) | 96,172 |
| | 70,909 |
| | 57,314 |
| | 58,792 |
| | 55,330 |
|
| |
(1) | Total sales volume includes sales from the production at our facilities and certain third-party facilities pursuant to supply and/or processing agreements, and sales of inventories. Total sales volume includes the sale of purchased fuel product blendstocks such as ethanol and biodiesel as components of finished fuel products in our fuel products segment sales. |
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(2) | Total feedstock runs represents the barrels per day of crude oil and other feedstocks processed at our facilities and certain third-party facilities pursuant to supply and/or processing agreements. |
| |
(3) | Total facility production represents the barrels per day of specialty products and fuel products yielded from processing crude oil and other feedstocks at our facilities and certain third-party facilities pursuant to supply and/or processing agreements. The difference between total facility production and total feedstock runs is primarily a result of the time lag between the input of feedstocks and production of finished products and volume loss. |
Non-GAAP Financial Measures
We include in this Annual Report the non-GAAP financial measures EBITDA, Adjusted EBITDA and Distributable Cash Flow, and provide reconciliations of EBITDA, Adjusted EBITDA and Distributable Cash Flow to net income and net cash provided by operating activities, our most directly comparable financial performance and liquidity measures calculated and presented in accordance with GAAP.
EBITDA, Adjusted EBITDA and Distributable Cash Flow are used as supplemental financial measures by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:
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• | the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; |
| |
• | the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; |
| |
• | our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure; and |
| |
• | the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities. |
We believe that these non-GAAP measures are useful to analysts and investors as they exclude transactions not related to our core cash operating activities and provide metrics to analyze our ability to pay distributions. We believe that excluding these transactions allows investors to meaningfully trend and analyze the performance of our core cash operations.
We define EBITDA for any period as net income (loss) plus interest expense (including debt issuance and extinguishment costs), income taxes and depreciation and amortization.
We define Adjusted EBITDA for any period as: (1) net income (loss) plus (2)(a) interest expense; (b) income taxes; (c) depreciation and amortization; (d) unrealized losses from mark to market accounting for hedging activities; (e) realized gains under derivative instruments excluded from the determination of net income (loss); (f) non-cash equity based compensation expense and other non-cash items (excluding items such as accruals of cash expenses in a future period or amortization of a prepaid cash expense) that were deducted in computing net income (loss); (g) debt refinancing fees, premiums and penalties and (h) all extraordinary, unusual or non-recurring items of gain or loss, or revenue or expense; minus (3)(a) unrealized gains from mark to market accounting for hedging activities; (b) realized losses under derivative instruments excluded from the determination of net income and (c) other non-recurring expenses and unrealized items that reduced net income (loss) for a prior period, but represent a cash item in the current period.
We define Distributable Cash Flow for any period as Adjusted EBITDA less replacement capital expenditures, turnaround costs, cash interest expense (consolidated interest expense less non-cash interest expense) and income tax expense. Distributable Cash Flow is used by us and our investors and analysts to analyze our ability to pay distributions.
The definitions of Adjusted EBITDA and Distributable Cash Flow that are presented in this Annual Report have been updated to reflect the calculation of “Consolidated Cash Flow” contained in the indentures governing our 2019 Notes and 2020 Notes (as defined in this Annual Report). We are required to report Consolidated Cash Flow to the holders of our 2019 Notes and 2020 Notes and Adjusted EBITDA to the lenders under our revolving credit facility, and these measures are used by them to determine our compliance with certain covenants governing those debt instruments. Adjusted EBITDA and Distributable Cash Flow that are presented in this Annual Report for prior periods have been updated to reflect the use of the new calculations. 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 details regarding the covenants governing our debt instruments.
EBITDA, Adjusted EBITDA and Distributable Cash Flow should not be considered alternatives to net income (loss), operating income (loss), net cash provided by (used in) operating activities or any other measure of financial performance presented in accordance with GAAP. In evaluating our performance as measured by EBITDA, Adjusted EBITDA and Distributable Cash Flow, management recognizes and considers the limitations of these measurements. EBITDA, Adjusted EBITDA and Distributable Cash Flow do not reflect our obligations for the payment of income taxes, interest expense or other obligations such as capital expenditures. Accordingly, EBITDA, Adjusted EBITDA and Distributable Cash Flow are only three of the measurements that management utilizes. Moreover, our EBITDA, Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of another company because all companies may not calculate EBITDA, Adjusted EBITDA and Distributable Cash Flow in the same manner. The following tables present a reconciliation of both net income to EBITDA, Adjusted EBITDA and Distributable Cash Flow, and Distributable Cash Flow, Adjusted EBITDA and EBITDA to net cash provided by (used in) operating activities, our most directly comparable GAAP financial performance and liquidity measures, for each of the periods indicated.
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| | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2012 | | 2011 | | 2010 | | 2009 | | 2008 |
| (In thousands) |
Reconciliation of Net income to EBITDA, Adjusted EBITDA and Distributable Cash Flow: | | | | | | | | |
Net income | $ | 205,737 |
| | $ | 43,036 |
| | $ | 16,701 |
| | $ | 61,785 |
| | $ | 44,437 |
|
Add: | | | | | | | | | |
Interest expense | 85,573 |
| | 48,747 |
| | 30,497 |
| | 33,573 |
| | 33,938 |
|
Debt extinguishment costs | — |
| | 15,130 |
| | — |
| | — |
| | 898 |
|
Depreciation and amortization | 91,669 |
| | 63,009 |
| | 60,287 |
| | 61,735 |
| | 55,866 |
|
Income tax expense | 753 |
| | 929 |
| | 598 |
| | 151 |
| | 257 |
|
EBITDA | $ | 383,732 |
| | $ | 170,851 |
| | $ | 108,083 |
| | $ | 157,244 |
| | $ | 135,396 |
|
Add: | | | | | | | | | |
Unrealized (gain) loss on derivatives | $ | 3,787 |
| | $ | 10,383 |
| | $ | 15,843 |
| | $ | (23,736 | ) | | $ | (3,454 | ) |
Realized gain (loss) on derivatives, not included in net income | (5,033 | ) | | 10,996 |
| | 2,990 |
| | 9,278 |
| | (8,055 | ) |
Amortization of turnaround costs | 13,356 |
| | 11,384 |
| | 10,006 |
| | 7,256 |
| | 2,468 |
|
Non-cash equity based compensation and other non-cash items | 8,768 |
| | 7,406 |
| | 1,540 |
| | 1,075 |
| | 179 |
|
Adjusted EBITDA | $ | 404,610 |
| | $ | 211,020 |
| | $ | 138,462 |
| | $ | 151,117 |
| | $ | 126,534 |
|
Less: | | | | | | | | | |
Replacement capital expenditures (1) | 28,341 |
| | 23,862 |
| | 24,345 |
| | 15,508 |
| | 6,304 |
|
Cash interest expense (2) | 79,492 |
| | 45,019 |
| | 26,633 |
| | 29,901 |
| | 30,543 |
|
Turnaround costs | 14,899 |
| | 14,052 |
| | 10,684 |
| | 6,890 |
| | 11,277 |
|
Income tax expense | 753 |
| | 929 |
| | 598 |
| | 151 |
| | 257 |
|
Distributable Cash Flow | $ | 281,125 |
| | $ | 127,158 |
| | $ | 76,202 |
| | $ | 98,667 |
| | $ | 78,153 |
|
| |
(1) | Replacement capital expenditures are defined as those capital expenditures which do not increase operating capacity or reduce operating costs and exclude turnaround costs. |
| |
(2) | Represents consolidated interest expense less non-cash interest expense. |
|
| | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2012 | | 2011 | | 2010 | | 2009 | | 2008 |
| (In thousands) |
Reconciliation of Distributable Cash Flow, Adjusted EBITDA and EBITDA to Net cash provided by operating activities: | | | | | | | | |
Distributable Cash Flow | $ | 281,125 |
| | $ | 127,158 |
| | $ | 76,202 |
| | $ | 98,667 |
| | $ | 78,153 |
|
Add: | | | | | | | | | |
Replacement capital expenditures (1) | 28,341 |
| | 23,862 |
| | 24,345 |
| | 15,508 |
| | 6,304 |
|
Cash interest expense (2) | |