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:
•
overall demand for specialty hydrocarbon products, fuel and other refined products;
•
the level of foreign and domestic production of crude oil and refined products;
•
our ability to produce fuel and specialty products that meet our customers’ unique and precise specifications;
•
the marketing of alternative and competing products;
•
the extent of government regulation;
•
results of our hedging activities; and
•
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:
•
the level of capital expenditures we make, including those for acquisitions, if any;
•
our debt service requirements;
•
fluctuations in our working capital needs;
•
our ability to borrow funds and access capital markets;
•
restrictions on distributions and on our ability to make working capital borrowings for distributions contained in our debt instruments; and
•
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:
•
sell assets, including equity interests in our subsidiaries;
•
pay distributions or redeem or repurchase our units or repurchase our subordinated debt;
•
incur or guarantee additional indebtedness or issue preferred units;
•
create or incur certain liens;
•
make certain acquisitions and investments;
•
redeem or repay other debt or make other restricted payments;
•
enter into transactions with affiliates;
•
enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;
•
create unrestricted subsidiaries;
•
enter into sale and leaseback transactions;
•
enter into a merger, consolidation or transfer or sale of assets, including equity interests in our subsidiaries; and
•
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:
•
will not be required to lend any additional amounts to us;
•
could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable;
•
could elect to require that all obligations accrue interest at the default rate, if such rate has not already been imposed;
•
may have the ability to require us to apply all of our available cash to repay these borrowings;
•
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
•
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:
•
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;
•
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;
•
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
•
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:
•
performance from the acquired assets and businesses that is below the forecasts we used in evaluating the acquisition;
•
a significant increase in our indebtedness and working capital requirements;
•
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;
•
the incurrence of substantial seen or unforeseen environmental and other liabilities arising out of the acquired businesses or assets;
•
the diversion of management’s attention from other business concerns;
•
customer or key employee losses at the acquired businesses; and
•
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:
•
a recession or other adverse economic condition that results in lower spending by consumers on gasoline, diesel, and travel;
•
higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of fuel products;
•
an increase in fuel economy or the increased use of alternative fuel sources;
•
an increase in the market price of crude oil that lead to higher refined product prices, which may reduce demand for fuel products;
•
competitor actions; and
•
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:
•
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;
•
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;
•
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;
•
our general partner determines which costs incurred by it and its affiliates are reimbursable by us;
•
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;
•
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
•
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:
•
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;
•
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;
•
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
•
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:
•
our unitholders’ proportionate ownership interest in us may decrease;
•
the amount of cash available for distribution on each unit may decrease;
•
the relative voting strength of each previously outstanding unit may be diminished;
•
the market price of the common units may decline; and
•
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:
•
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
•
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:
•
our quarterly distributions;
•
our quarterly or annual earnings or those of other companies in our industry;
•
changes in commodity prices or refining margins;
•
loss of a large customer;
•
announcements by us or our competitors of significant contracts or acquisitions;
•
changes in accounting standards, policies, guidance, interpretations or principles;
•
general economic conditions;
•
the failure of securities analysts to cover our common units or changes in financial estimates by analysts;
•
future sales of our common units; and
•
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.
Item 1B. Unresolved Staff Comments
None.
Item 3.
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.
Item 4.
Item 4.
Mine Safety Disclosures
Not applicable.
PART II
Item 5.
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.
(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:
•
less the amount of cash reserves established by our general partner to:
•
provide for the proper conduct of our business;
•
comply with applicable law, any of our debt instruments or other agreements; and
•
provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters.
•
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:
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.
Item 6.
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
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The historical consolidated financial statements included in this Annual Report reflect all of the assets, liabilities and results of operations of the Company. The following discussion analyzes the financial condition and results of operations of the Company for the years ended December 31, 2012, 2011 and 2010. Unitholders should read the following discussion and analysis of the financial condition and results of operations of the Company in conjunction with the historical consolidated financial statements and notes of the Company included elsewhere in this Annual Report.
Overview
We are a leading independent producer of high-quality, specialty hydrocarbon products 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 facilities, primarily related to production and distribution of specialty products, throughout the 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 Royal Purple brand. 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.
2012 Update
For the years ended December 31, 2012 and 2011, 39.1% and 46.8%, respectively, of our sales volume and 60.1% and 94.4%, respectively, of our gross profit was generated from our specialty products segment while, for the same periods, 60.9% and 53.2%, respectively, of our sales volume and approximately 39.9% and 5.6%, respectively, of our gross profit was generated from our fuel products segment.
Generally, we continued to see strength in product demand in our specialty products segment in 2012, noting a slight softening in demand toward the end of 2012 due to some seasonality of product demand in the segment. Overall, we achieved a 23.6% increase in barrels of specialty products sold, including the impact of incremental sales from the Superior, Royal Purple, Montana, TruSouth and Missouri Acquisitions. Our specialty products segment generated a gross profit margin of 13.8% in 2012, as compared to a gross profit margin of 14.3% in 2011, as specialty products sales pricing slightly lagged fluctuations in crude oil prices.
Higher sales and production volume in our fuel products segment during 2012 allowed us to take advantage of higher market crack spreads. We achieved a 69.2% increase in barrels of fuel products sold in 2012 compared to 2011, driven primarily by incremental sales from the Superior and Montana refineries. Negatively impacting production levels during the second half of 2012 were reduced run rates at our Shreveport refinery resulting from the April 28, 2012 shutdown by ExxonMobil of a crude oil pipeline serving the refinery for a portion of its crude oil requirements. During the fourth quarter of 2012, the Shreveport refinery began receiving Bakken crude oil by rail from the Superior refinery to supplement the loss of crude oil related to the ExxonMobil pipeline shutdown and to take advantage of lower priced Bakken crude oil. The fuel products segment generated a gross profit margin of 8.4% in 2012 compared to 1.2% in 2011 despite the recognition of increased realized derivative losses of $55.2 million during 2012 compared to 2011 due to the strength of settled market crack spreads compared to our hedged crack spreads. As of December 31, 2012, we have entered 17.8 million barrels of crack spread derivatives for calendar years 2013 through 2015 at an average of $26.74 per barrel.
During 2012, the Western Canadian Select (“WCS”) heavy crude oil differential to NYMEX WTI averaged $21.98 per barrel below NYMEX WTI, an increase of $6.34 from 2011. During 2012, the Bakken light crude oil differential to NYMEX WTI averaged $5.74 per barrel below NYMEX WTI, an increase of $8.26 from 2011. Both the WCS and Bakken differentials to NYMEX WTI create an unhedged crude oil cost advantage for our Superior refinery. During 2012, the Bow River heavy crude oil differential to NYMEX WTI averaged $19.88 per barrel below NYMEX WTI, an increase of $3.68 from 2011, creating an unhedged crude oil cost advantage for our Montana refinery. On the sales side, while Group 3 fuel product differentials to U.S. Gulf Coast were not quite as strong as in 2011, we saw continued increases throughout the second half of 2012 with the Group 3 diesel pricing differential to U.S. Gulf Coast diesel, for example, widening $0.30 per barrel compared to the average differential in the third quarter of 2012 and hitting a high of $16.32 per barrel in October 2012. As we currently use U.S. Gulf Coast fuel products swaps to hedge a portion of our Group 3 fuel products selling price exposure, we continue to benefit from this Group 3 pricing strength relative to U.S. Gulf Coast pricing.
Our 2012 total legacy facility production decreased by 1.9% year over year, excluding the impact of the Superior, Missouri, TruSouth, Royal Purple and Montana Acquisitions, due primarily to decreased run rates at our Superior, Karns City and Dickinson facilities.
We remained active in the capital markets in 2012 by completing a public offering of common units in May 2012 which generated net proceeds (including our general partner’s contribution) of $149.7 million and completing in June 2012 a private placement offering of an aggregate of $275.0 million in senior unsecured notes due 2020 (“June 2012 Notes Offering”), which generated net proceeds of $262.6 million. We used the net proceeds from the June 2012 Notes Offering to fund a portion of the Royal Purple Acquisition.
We generated $380.1 million in cash flow from operations during 2012. We generated distributable cash flow (as defined in Part II, Item 6 “Non-GAAP Financial Measures”) of $281.1 million in 2012, an increase of $154.0 million over 2011 and paid distributions of $132.4 million to our unitholders in 2012, an increase of $49.7 million over 2011. We plan to continue focusing our efforts on generating positive cash flows from operations which we expect will be used to (i) improve our liquidity position, (ii) service our debt obligations, (iii) pay quarterly distributions to our unitholders and (iv) provide funding for general partnership purposes.
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. We believe the Missouri Acquisition provides greater diversity to our specialty products segment. 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 for aggregate consideration of approximately $26.8 million, which was financed with borrowings under our revolving credit facility. We believe the TruSouth Acquisition provides greater diversity to our specialty products segment. 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., 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 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 Notes Offering 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 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, 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 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, together with the associated crude oil pipeline, crude oil terminal, other operating and logistics assets and inventories 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 certain post-closing adjustments.
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.
Key Performance Measures
Our sales and net income are principally affected by the price of crude oil, demand for specialty and fuel products, prevailing crack spreads for fuel products, the price of natural gas used as fuel in our operations and our results from derivative instrument activities.
Our primary raw materials are crude oil and other specialty feedstocks and our primary outputs are specialty petroleum products and fuel products. The prices of crude oil, specialty products and fuel products are subject to fluctuations in response to changes in supply, demand, market uncertainties and a variety of additional factors beyond our control. We monitor these risks and enter into derivative instruments designed to mitigate the impact of commodity price fluctuations on our business. The primary purpose of our commodity risk management activities is to economically hedge our cash flow exposure to commodity price risk so that we can meet our cash distribution, debt service and capital expenditure requirements despite fluctuations in crude oil and fuel products prices. We enter into derivative contracts for future periods in quantities that do not exceed our projected purchases of crude oil and natural gas and sales of fuel products. As of December 31, 2012, we have hedged refining margins, or crack spreads, on approximately 17.8 million barrels of fuel products through December 2015 at an average refining margin of $26.74 per barrel with average refining margins ranging from a low of $23.77 per barrel in the first quarter of 2013 to a high of $29.55 per barrel in the fourth quarter of 2013. Please refer to Note 7 under Item 8 “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements” and Item 7A
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Derivative Instruments
We are exposed to price risks due to fluctuations in the price of crude oil, refined products (primarily in our fuel products segment) and natural gas. We use various strategies to reduce our exposure to commodity price risk. We do not attempt to eliminate all of our risk due to the cost of such actions are believed to be too high in relation to the risk posed to our future cash flows, earnings and liquidity. The strategies to reduce our risk utilize both physical forward contracts and financially settled derivative instruments such as swaps, futures and options to attempt to reduce our exposure with respect to:
•
crude oil purchases;
•
refined product sales;
•
natural gas purchases; and
•
fluctuations in the value of crude oil between geographic regions and in between the different types of crude oil such as NYMEX WTI, Light Louisiana Sour (“LLS”) and WCS.
As of December 31, 2012, we have entered into swap contracts on forecasted purchases from 2013 through 2015 for 17,818,500 barrels of NYMEX WTI crude oil and forecasted sales of 1,725,000 barrels of U.S. Gulf Coast conventional gasoline, 12,320,500 barrels of U.S. Gulf Coast ultra-low sulfur diesel and 3,773,000 barrels of U.S. Gulf Coast jet fuel. These derivative instruments, on a combined basis, were entered into to hedge a portion of our gross profit in our fuels products segment. Please read Note 7 - “Derivatives” in the notes to our consolidated financial statements under Item 8
Item 8.
Financial Statements and Supplementary Data
Management’s Report on Internal Control Over Financial Reporting
The management of Calumet Specialty Products Partners, L.P. (the “Company”) is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles. Internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of the financial statements in accordance with U.S. generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.
Management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of Calumet Missouri, LLC, TruSouth Oil, LLC, Royal Purple, LLC and Calumet Montana Refining, LLC, which are included in the Company’s 2012 consolidated financial statements and constituted $599,909,000 of the Company’s total assets as of December 31, 2012 and $266,103,000 of the Company’s sales for the year then ended. Management also did not perform an evaluation of the internal control over financial reporting of Calumet Missouri, LLC, TruSouth Oil, LLC, Royal Purple, LLC and Calumet Montana Refining, LLC.
Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2012, based on criteria for effective internal control over financial reporting described in “Internal Control - Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on this assessment, we have concluded that internal control over financial reporting was effective as of December 31, 2012.
Ernst & Young LLP, an independent registered public accounting firm, has audited the Company’s consolidated financial statements and has issued an attestation report on the effectiveness of internal control over financial reporting which appears on the following page.
/s/ F. William Grube
F. William Grube
Chief Executive Officer, Director and
Vice Chairman of the Board of Calumet GP, LLC
March 1, 2013
/s/ R. Patrick Murray, II
R. Patrick Murray, II
Senior Vice President, Chief Financial Officer and
Secretary of Calumet GP, LLC
March 1, 2013
Report of Independent Registered Public Accounting Firm
The Board of Directors of Calumet GP, LLC
General Partner of Calumet Specialty Products Partners, L.P.
We have audited Calumet Specialty Products Partners, L.P.’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Calumet Specialty Products Partners, L.P.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
As indicated in the accompanying Management’s Report on Internal Control over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of Calumet Missouri, LLC, TruSouth Oil, LLC, Royal Purple, LLC and Calumet Montana Refining, LLC., which are included in the 2012 consolidated financial statements of Calumet Specialty Products Partners, L.P. and constituted $599,909,000 of total assets as of December 31, 2012 and $266,103,000 of sales for the year then ended. Our audit of internal control over financial reporting of Calumet Specialty Products Partners, L.P. also did not include an evaluation of the internal control over financial reporting of Calumet Missouri, LLC, TruSouth Oil, LLC, Royal Purple, LLC and Calumet Montana Refining, LLC.
In our opinion, Calumet Specialty Products Partners, L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Calumet Specialty Products Partners, L.P. as of December 31, 2012 and 2011 and the related statements of operations and comprehensive income (loss), partners’ capital and cash flows for each of the three years in the period ended December 31, 2012 of Calumet Specialty Products Partners, L.P. and our report dated March 1, 2013 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Indianapolis, Indiana
March 1, 2013
Report of Independent Registered Public Accounting Firm
The Board of Directors of Calumet GP, LLC
General Partner of Calumet Specialty Products Partners, L.P.
We have audited the accompanying consolidated balance sheets of Calumet Specialty Products Partners, L.P. as of December 31, 2012 and 2011, and the related consolidated statements of operations and comprehensive income (loss), partners’ capital and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Calumet Specialty Products Partners, L.P. at December 31, 2012 and 2011, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Calumet Specialty Products Partners, L.P.’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2013 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Indianapolis, Indiana
March 1, 2013
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
See accompanying notes to consolidated financial statements.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
See accompanying notes to consolidated financial statements.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
See accompanying notes to consolidated financial statements.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
See accompanying notes to consolidated financial statements.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying notes to consolidated financial statements.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per unit data)
1.
Description of the Business
Calumet Specialty Products Partners, L.P. (the “Company”) is a Delaware limited partnership. The general partner of the Company is Calumet GP, LLC, a Delaware limited liability company. As of December 31, 2012, the Company had 57,529,778 limited partner common units and 1,174,077 general partner equivalent units outstanding. The general partner owns 2% of the Company and all of the incentive distribution rights (as defined in the Company’s partnership agreement), while the remaining 98% is owned by limited partners. The general partner employs all of the Company’s employees and the Company reimburses the general partner for certain of its expenses. The Company is engaged in the production and marketing of crude oil-based specialty products including lubricating oils, white mineral oils, solvents, petrolatums, asphalt, waxes and fuel and fuel related products including gasoline, diesel, jet fuel and heavy fuel oils. The Company owns facilities located in Shreveport, Louisiana (“Shreveport” and “TruSouth”); Superior, Wisconsin (“Superior”); Great Falls, Montana (“Montana”); Princeton, Louisiana (“Princeton”); Cotton Valley, Louisiana (“Cotton Valley”); Karns City, Pennsylvania (“Karns City”); Dickinson, Texas (“Dickinson”); Louisiana, Missouri (“Missouri”) and Porter, Texas (“Royal Purple”) and terminals located in Burnham, Illinois (“Burnham”); Rhinelander, Wisconsin (“Rhinelander”); Crookston, Minnesota (“Crookston”) and Proctor, Minnesota (“Duluth”).
2.
Summary of Significant Accounting Policies
Consolidation
The consolidated financial statements of the Company include the accounts of Calumet Specialty Products Partners, L.P. and its wholly-owned operating subsidiaries, Calumet Lubricants Co., Limited Partnership, Calumet Sales Company Incorporated, Calumet Penreco, LLC, Calumet Shreveport, LLC, Calumet Superior, LLC, Calumet Missouri, LLC, TruSouth Oil, LLC, Calumet Montana Refining, LLC, S&S International Mining Enterprises, Inc., Royal Purple, LLC and Calumet Finance Corp. Calumet Shreveport, LLC’s wholly-owned operating subsidiaries are Calumet Shreveport Fuels, LLC and Calumet Shreveport Lubricants & Waxes, LLC. All intercompany transactions and accounts have been eliminated.
Use of Estimates
The Company’s financial statements are prepared in conformity with U.S. generally accepted accounting principles which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Cash and Cash Equivalents
Cash and cash equivalents includes all highly liquid investments with a maturity of three months or less at the time of purchase.
Inventories
The cost of inventory is recorded using the last-in, first-out (LIFO) method. Costs include crude oil and other feedstocks, labor, processing costs and refining overhead costs. Inventories are valued at the lower of cost or market value. The replacement cost of these inventories, based on current market values, would have been $38,295 and $87,635 higher as of December 31, 2012 and 2011, respectively.
Inventories consist of the following:
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. During the year ended December 31, 2012, the Company recorded $4,206 of losses in cost of sales in the consolidated statements of operations due to the liquidation of higher cost inventory layers. During the years ended December 31, 2011 and 2010 the Company recorded $5,166 and $13,661, respectively, of gains in cost of sales in the consolidated statements of operations due to the liquidation of lower cost inventory layers.
In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years that inventory volumes decline as the result of charging cost of sales with LIFO inventory costs generated in prior periods. In periods of rapidly declining prices, LIFO inventories may have to be written down to market value due to the higher costs assigned to LIFO layers in prior periods. During the years ended December 31, 2012, 2011 and 2010 the Company recorded $8,124, $1,976 and $76 of losses in cost of sales in the consolidated statements of operations due to the lower of cost or market valuation.
Accounts Receivable
The Company performs periodic credit evaluations of customers’ financial condition and generally does not require collateral. Accounts receivable are carried at their face amounts and are generally due within 30 days to 45 days from date of invoice for the specialty products segment and 10 days from date of invoice for the fuel products segment. The Company maintains an allowance for doubtful accounts for estimated losses in the collection of accounts receivable. The Company makes estimates regarding the future ability of its customers to make required payments based on historical experience, the age of the accounts receivable balances, credit quality of the Company’s customers, current economic conditions, expected future trends and other factors that may affect customers’ ability to pay. Individual accounts are written off against the allowance for doubtful accounts after all reasonable collection efforts have been exhausted. The activity in the allowance for doubtful accounts was as follows:
Property, Plant and Equipment
Property, plant and equipment are stated on the basis of cost. Depreciation is calculated generally on composite groups, using the straight-line method over the estimated useful lives of the respective groups. Assets under capital leases are amortized over the lesser of the useful life of the asset or the term of the lease.
Property, plant and equipment, including depreciable lives, consisted of the following:
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
Under the composite depreciation method, the cost of partial retirements of a group is charged to accumulated depreciation. However, when there are dispositions of complete groups or significant portions of groups, the cost and related accumulated depreciation are retired, and any gain or loss is reflected in earnings.
During 2012, 2011 and 2010, the Company incurred $86,327, $49,339 and $30,886, respectively, of interest expense of which $754, $592 and $389, respectively, was capitalized as a component of property, plant and equipment.
The Company has not recorded an asset retirement obligation as of December 31, 2012 or 2011 because such potential obligations cannot be measured since it is not possible to estimate the settlement dates.
During the years ended December 31, 2012, 2011 and 2010, the Company recorded $74,292, $55,536 and $51,365, respectively, of depreciation expense on its property, plant and equipment. Depreciation expense included $1,030, $1,050 and $1,050 for the years ended 2012, 2011 and 2010, respectively, related to the Company’s capital lease assets.
The Company capitalizes the cost of computer software developed or obtained for internal use. Capitalized software is amortized using the straight-line method over three years. As of December 31, 2012 and 2011, the Company has $15,007 and $6,037, respectively, of unamortized capitalized software costs. During the years ended December 31, 2012, 2011 and 2010, the Company recorded $967, $416, and $262, respectively, of amortization expense on capitalized computer software.
Goodwill
Goodwill represents the excess of purchase price over fair value of the net assets acquired in the acquisitions of Penreco on January 3, 2008, Missouri on January 3, 2012, TruSouth on January 6, 2012, Royal Purple on July 3, 2012 and Montana on October 1, 2012. See Note 3 for more information. The Company reviews goodwill for impairment annually on October 1 and whenever events or changes in circumstances indicate its carrying value may not be recoverable in accordance with ASC 350, Intangibles - Goodwill and Other (Topic 350): Testing Goodwill for Impairment (“ASU 2011-08”). In September 2011, the FASB issued ASU 2011-08 (“ASU 2011-08”) which amends the rules for testing goodwill for impairment. Under ASU 2011-08, an entity has the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after assessing the totality of events or circumstances, an entity determines it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then performing the two-step impairment test is unnecessary. The Company early adopted ASU 2011-08 for the October 1, 2011 annual goodwill impairment test.
In assessing the qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, the Company assesses relevant events and circumstances that may impact the fair value and the carrying amount of the reporting unit. The identification of relevant events and circumstances and how these may impact a reporting unit’s fair value or carrying amount involve significant judgment and assumptions. The judgment and assumptions include the identification of macroeconomic conditions, industry and market considerations, cost factors, overall financial performance and Company specific events and making the assessment on whether each relevant factor will impact the impairment test positively or negatively and the magnitude of any such impact.
If the Company’s qualitative assessment concludes that it is probable that an impairment exists or the Company skips the qualitative assessment then the Company needs to perform a quantitative assessment. In the first step of the quantitative assessment, the Company’s assets and liabilities, including existing goodwill and other intangible assets, are assigned to the identified reporting units to determine the carrying value of the reporting units. If the carrying value of a reporting unit is in excess of its fair value, an impairment may exist, and the Company must perform an impairment analysis, in which the implied fair value of the goodwill is compared to its carrying value to determine the impairment charge, if any. Based on the results of the qualitative assessment of the reporting units, the Company believes it is more likely than not that the fair value of the reporting unit is greater than its carrying amount.
The fair value of the reporting units is determined using the income approach. The income approach focuses on the income-producing capability of an asset, measuring the current value of the asset by calculating the present value of its future economic benefits such as cash earnings, cost savings, corporate tax structure and product offerings. Value indications are developed by discounting expected cash flows to their present value at a rate of return that incorporates the risk-free rate for the use of funds, the expected rate of inflation, and risks associated with the reporting unit.
Based on the results of the qualitative assessment of the reporting unit, the Company believes it is more likely than not that the fair value of its reporting units are greater than their carrying amounts. No impairment was recognized in 2012, 2011 or 2010.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
Other Intangible Assets
Other intangible assets consist of tangible assets associated with supplier agreements, tradenames, trade secrets, patents, non-competition agreements, distributor agreements and royalty agreements that were acquired in the acquisition of Penreco on January 3, 2008, the Missouri Acquisition on January 3, 2012, the TruSouth Acquisition on January 6, 2012 and the Royal Purple Acquisition on July 3, 2012. The majority of these assets are being amortized using discounted estimated future cash flows over the term of the related agreements. Intangible assets associated with customer relationships are being amortized using the discounted estimated future cash flows method based upon assumed rates of annual customer attrition. For more information, refer to Note 4.
Impairment of Long-Lived Assets
The Company periodically evaluates the carrying value of long-lived assets to be held and used, including definite-lived intangible assets, when events or circumstances warrant such a review. The carrying value of a long-lived asset to be held and used is considered impaired when the anticipated separately identifiable undiscounted cash flows from such an asset are less than the carrying value of the asset. In such an event, a write-down of the asset would be recorded through a charge to operations, based on the amount by which the carrying value exceeds the fair value of the long-lived asset. Fair value is determined primarily using anticipated cash flows assumed by a market participant discounted at a rate commensurate with the risk involved. Long-lived assets to be disposed of other than by sale are considered held and used until disposal.
During 2012, the Company recorded a write-down related to unutilized fixed assets within its specialty products segment. The non-cash charge of $1,640 was recorded in other operating costs and expenses on the consolidated statements of operations.
Revenue Recognition
The Company recognizes revenue on orders received from its customers when there is persuasive evidence of an arrangement with the customer that is supportive of revenue recognition, the customer has made a fixed commitment to purchase the product for a fixed or determinable sales price, collection is reasonably assured under the Company’s normal billing and credit terms, all of the Company’s obligations related to product have been fulfilled and ownership and all risks of loss have been transferred to the buyer, which is primarily upon shipment to the customer or, in certain cases, upon receipt by the customer in accordance with contractual terms.
Concentrations of Credit Risk
The Company performs periodic credit evaluations of its customers’ financial condition and in some instances requires cash in advance or letters of credit prior to shipment for domestic orders. For international orders, letters of credit are generally required and the Company maintains insurance policies which cover certain export orders. The Company maintains an allowance for doubtful customer accounts for estimated losses resulting from the inability of its customers to make required payments. The allowance for doubtful accounts is developed based on several factors including historical experience, the age of the accounts receivable balances, credit quality of the Company’s customers, current economic conditions, expected future trends and other factors that may affect customers’ ability to pay, which exist as of the balance sheet dates. If the financial condition of the Company’s customers were to deteriorate, resulting in an impairment of their ability to make payments, additional allowances may be required. In addition, from time to time the Company has significant derivative assets with a limited number of counterparties. The evaluation of these counterparties is performed quarterly in connection with the Company’s ASC 820-10, Fair Value Measurements and Disclosures, valuations to determine the impact of the counterparty credit risk on the valuation of its derivative instruments.
Income Taxes
The Company, as a partnership, is generally not liable for federal income taxes on the earnings of Calumet Specialty Products Partners, L.P. and its wholly-owned subsidiaries. However, Calumet Sales Company Incorporated (“Calumet Sales Company”), a wholly-owned subsidiary of the Company, is a corporation and as a result, is liable for income taxes on its earnings. Income taxes on the earnings of the Company, with the exception of Calumet Sales Company, are the responsibility of its partners, with earnings of the Company included in partners’ earnings.
In the event that the Company’s taxable income did not meet certain qualification requirements, the Company would be taxed as a corporation. Interest and penalties related to income taxes, if any, would be recorded in income tax expense.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
Generally, tax returns remain subject to examination by taxing authorities for three years. The Company had no unrecognized tax benefits as of December 31, 2012 and 2011.
Net income for financial statement purposes may differ significantly from taxable income reportable to partners as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under the Company’s partnership agreement. Individual partners have different investment basis depending upon the timing and price of acquisition of their partnership units. Furthermore, each partner’s tax accounting, which is partially dependent upon the partner’s tax position, differs from the accounting followed in the consolidated financial statements. Accordingly, the aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes in the Company is not readily available.
Excise and Sales Taxes
The Company assesses, collects and remits excise taxes associated with the sale of certain of its fuel products. Furthermore, the Company collects and remits sales taxes associated with certain sales of its products to non-exempt customers. Excise taxes and sales taxes assessed and collected from customers are recorded on a net basis within sales in the Company’s consolidated statements of operations.
Derivatives
The Company is exposed to fluctuations in the price of numerous commodities like crude oil, its principal raw material, and natural gas as well as the sales prices of gasoline, diesel and jet fuel. Given the historical volatility of commodity prices, these fluctuations can significantly impact sales, gross profit and net income. Therefore, the Company utilizes derivative instruments primarily to minimize its price risk and volatility of cash flows associated with the purchase of crude oil and natural gas and the sale of fuel products. The Company employs various hedging strategies, and does not hold or issue derivative instruments for trading purposes. For further information, please refer to Note 7.
Other Noncurrent Assets
Other noncurrent assets include deferred debt issuance costs and turnaround costs. Deferred debt issuance costs were $29,414 and $26,374 as of December 31, 2012 and 2011, respectively, and are being amortized by the effective interest rate method or on a straight-line basis, which approximates the effective interest rate method, over the lives of the related debt instruments. These amounts are net of accumulated amortization of $6,578 and $1,996 at December 31, 2012 and 2011, respectively.
Turnaround costs represent capitalized costs associated with the Company’s periodic major maintenance and repairs and were $14,346 and $12,471 as of December 31, 2012 and 2011, respectively. The Company capitalizes these costs and amortizes the costs on a straight-line basis over the lives of the turnaround assets. These amounts are net of accumulated amortization of $17,813 and $12,538 at December 31, 2012 and 2011, respectively.
Earnings per Unit
The Company calculates earnings per unit under ASC 260-10, Earnings per Share. The Company treats incentive distribution rights (IDRs) as participating securities for the purposes of computing earnings per unit in the period that the general partner becomes contractually obligated to receive IDRs. Also, the undistributed earnings are allocated to the partnership interests based on the allocation of earnings to the Company’s partners’ capital accounts as specified in the Company’s partnership agreement. When distributions exceed earnings, net income is reduced by the actual distributions with the resulting net loss being allocated to capital accounts as specified in the Company’s partnership agreement.
Unit Based Compensation
For unit based compensation awards granted, compensation expense is recognized in the Company’s consolidated financial statements on a straight line basis over the awards’ vesting periods based on their fair values on the dates of grant. The unit based compensation awards vest over a period not exceeding four years. The amount of compensation expense recognized at any date is at least equal to the portion of the grant date value of the award that is vested at that date.
Unit based compensation liability awards are awards that are expected to be settled in cash on their vesting dates, rather than in equity units (“Liability Awards”). Liability Awards are recorded in accrued salaries, wages and benefits based on the vested portion of the fair value of the awards on the balance sheet date. The fair values of Liability Awards are updated at each
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
balance sheet date and changes in the fair values of the vested portions of the awards are recorded as increases or decreases to compensation expense.
Shipping and Handling Costs
The Company complies with ASC 605-45, Revenue Recognition - Principal Agent Considerations. ASC 605-45 requires the classification of shipping and handling costs billed to customers in sales and the classification of shipping and handling costs incurred in cost of sales, or to be disclosed if classified elsewhere. The Company has reflected $107,900, $94,187 and $85,471, respectively, for the years ended December 31, 2012, 2011, and 2010, in transportation expense in the consolidated statements of operations, the majority of which is billed to customers.
Advertising Expenses
The Company expenses advertising costs as incurred which totaled $8,232, $1,699 and $443 in 2012, 2011 and 2010, respectively.
New Accounting Pronouncements
In May 2011, the FASB issued ASU No. 2011-04, Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRS (“ASU 2011-04”). ASU 2011-04 is intended to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and IFRS. The amendments are of two types: (i) those that clarify the FASB’s intent about the application of existing fair value measurement and disclosure requirements and (ii) those that change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. ASU 2011-04 was effective for the first reporting period (including interim periods) beginning after December 15, 2011. The adoption of ASU 2011-04 did not have a material impact on the Company’s consolidated financial statements.
In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income (“ASU 2011-05”), which amended current comprehensive income guidance. This accounting update eliminates the option to present the components of other comprehensive income (loss) as part of the statement of partners’ capital. Instead, the Company must report comprehensive income in either a single continuous statement of comprehensive income (loss) which contains two sections, net income and other comprehensive income (loss), or in two separate but consecutive statements. In December 2011, the FASB issued ASU No. 2011-12, Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 (“ASU 2011-12”), which indefinitely defers the requirement in ASU 2011-05 to present reclassification adjustments out of accumulated other comprehensive income (loss) by component in both the statement in which net income is presented and the statement in which other comprehensive income (loss) is presented. During the deferral period, the existing requirements in U.S. GAAP for the presentation of reclassification adjustments must continue to be followed. Amendments to ASU 2011-05, as superseded by ASU 2011-12, were effective for fiscal years (including interim periods) beginning after December 15, 2011 and are to be applied retrospectively, with early adoption permitted. The Company elected to present the components of comprehensive loss in two separate but consecutive financial statements, namely the consolidated statements of operations and the consolidated statements of comprehensive income (loss).
In December 2011, the FASB issued ASU No. 2011-11, Balance Sheet (Topic 210)-Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”). ASU 2011-11 requires entities to disclose information about offsetting and related arrangements to enable financial statement users to understand the effect of such arrangements on the balance sheet. Entities are required to disclose both gross information and net information about financial instruments and derivative instruments that are either offset in the balance sheet or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset. In January 2013, the FASB issued ASU No. 2013-01, Balance Sheet Topic(210)-Clarifying the Scope of Disclosures About Offsetting Assets and Liabilities (“ASU 2013-01”), which clarifies the scope of the setting disclosures and addresses any unintended consequences. Amendments to ASU 2011-11, as superseded by ASU 2013-01, are effective for the first reporting period (including interim periods) beginning after January 1, 2013 and should be applied retrospectively for any period presented. The Company is in the process of evaluating the impact of the adoption of ASU 2011-11 and ASU 2013-01 on its financial statements.
In July 2012, the FASB issued ASU No. 2012-02, Intangibles (Topic 350)-Testing Indefinite-Lived Intangible Assets for Impairment (“ASU 2012-02”). ASU 2012-02 permits an entity to first assess qualitative factors to determine if it is more likely than not that the fair value of an indefinite-lived intangible asset is more than its carrying amount. If based on its qualitative assessment an entity concludes it is more likely than not that the fair value of an indefinite-lived intangible asset exceeds its
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
carrying amount, quantitative impairment testing is not required. However, if an entity concludes otherwise, quantitative impairment testing is required. ASU 2012-02 is effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012, with early adoption permitted. The adoption of ASU 2012-02 did not have a material impact on the Company’s consolidated financial statements.
In October 2012, the FASB issued ASU No. 2012-04, Technical Corrections and Improvements (“ASU 2012-04”). ASU 2012-04 covers a wide range of topics in the Accounting Standards Codification. These amendments include technical corrections and improvements to the Accounting Standards Codification and conforming amendments related to fair value measurements. ASU 2012-04 is effective for fiscal periods beginning after December 15, 2012. The Company is in the process of evaluating the impact of the adoption of ASU 2012-04 on its financial statements.
In February 2013, the FASB issued ASU No. 2013-02, Comprehensive Income (Topic 220)-Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”). ASU 2013-02 requires entities to report either on the statement of operations or disclose in the footnotes to the consolidated financial statements the effects on earnings from items that are reclassified out of comprehensive income. For amounts that are not required to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures that provide additional details about those amounts. ASU 2013-02 is effective prospectively for the first reporting period after December 15, 2012 with early adoption permitted. The adoption of ASU 2013-02 will not have a material impact on the Company’s consolidated financial statements.
3.
Acquisitions
Superior Acquisition
On September 30, 2011, the Company completed the acquisition of the Superior, Wisconsin refinery and associated operating assets and inventories and related business of Murphy Oil Corporation (“Murphy Oil”) for aggregate consideration of approximately $413,173 (“Superior Acquisition”). The Superior Acquisition was financed by a combination of (i) net proceeds of $193,538 from the Company’s September 2011 public offering of common units (including the general partner’s contribution but excluding the over-allotment option exercised), (ii) net proceeds of $180,296 from the Company’s September 2011 private placement of 9 3/8% senior notes due May 1, 2019 and (iii) borrowings under the Company’s revolving credit facility. The Company acquired the following assets:
•
Murphy Oil’s refinery located in Superior, Wisconsin and associated inventories;
•
a distribution network for fuel and asphalt products operated through various owned and leased terminals located in Wisconsin, Minnesota and Utah and associated inventories and logistics assets located at each of the terminals; and
•
Murphy Oil’s “SPUR” branded gasoline wholesale business and related assets.
The Superior refinery produces gasoline, diesel, asphalt and heavy fuel oils that are primarily marketed in the Upper Midwest region of the U.S. and in Canada. The Superior wholesale marketing business transports products produced at the Superior refinery through several Magellan pipeline terminals in Minnesota, Wisconsin, Iowa, North Dakota and South Dakota and through its leased and owned product terminals. The Superior wholesale business also sells gasoline wholesale to SPUR branded gas stations, which are owned and operated by independent franchisees.
The Company believes the Superior Acquisition provides greater scale, geographic diversity and development potential to its refining business.
As a result of the Superior Acquisition on September 30, 2011, the assets and certain liabilities previously held by Murphy Oil and the results of the operations of these assets have been included in the Company’s consolidated balance sheets and consolidated statements of operations since the date of acquisition. There were no intangible assets or goodwill recorded in connection with the Superior Acquisition. In connection with the Superior Acquisition, the Company incurred acquisition costs during 2011 of approximately $2,717 which are reflected in general and administrative expenses in the consolidated statements of operations.
The allocation of the aggregate purchase price to assets acquired and liabilities assumed is as follows:
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
Missouri Acquisition
On January 3, 2012, the Company completed the acquisition of the aviation and refrigerant lubricants business (a polyolester based synthetic lubricants business) of Hercules Incorporated, a subsidiary of Ashland, Inc., including a manufacturing facility located in Louisiana, Missouri for aggregate consideration of approximately $19,575 (“Missouri Acquisition”). The Missouri Acquisition was financed with borrowings under the Company’s revolving credit facility and cash on hand. The Company believes the Missouri Acquisition provides greater diversity to its specialty products segment. The assets acquired and results of operations have been included in the Company’s consolidated balance sheets and consolidated statements of operations since the date of acquisition. In connection with the Missouri Acquisition, during the year ended December 31, 2012, the Company incurred acquisition costs of approximately $505 which are reflected in general and administrative expenses in the consolidated statements of operations.
The Company recorded $1,478 of goodwill as a result of the Missouri Acquisition, all of which was recorded within the Company’s specialty products segment. Goodwill recognized in the acquisition relates primarily to enhancing the Company’s strategic platform for expansion in its specialty products segment. The allocation of the aggregate purchase price to assets acquired is as follows:
The component of the intangible asset listed in the table above as of January 3, 2012, based upon a third party appraisal, was as follows:
TruSouth Acquisition
On January 6, 2012, the Company completed the acquisition of all of the outstanding membership interests of TruSouth Oil, LLC (“TruSouth”), a specialty petroleum packaging and distribution company located in Shreveport, Louisiana for aggregate consideration of approximately $26,827, net of cash acquired (“TruSouth Acquisition”). The TruSouth Acquisition was financed with borrowings under the Company’s revolving credit facility. Immediately prior to its acquisition by the Company, TruSouth was owned in part by affiliates of the Company’s general partner. The Company believes the TruSouth Acquisition provides greater diversity to its specialty products segment. The assets acquired and liabilities assumed have been included in the Company’s consolidated balance sheets and results of operations have been included in the Company’s consolidated statements of operations since the date of acquisition. In connection with the TruSouth Acquisition, during the year ended December 31, 2012, the Company incurred acquisition costs of $179 which are reflected in general and administrative expenses in the consolidated statements of operations.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
The Company recorded $392 of goodwill as a result of the TruSouth Acquisition, all of which was recorded within the Company’s specialty products segment. Goodwill recognized in the acquisition relates primarily to enhancing the Company’s strategic platform for expansion in its specialty products segment. The allocation of the aggregate purchase price to assets acquired and liabilities assumed is as follows:
The components of intangible assets listed in the table above as of January 6, 2012, based upon a third party appraisal, were as follows:
Royal Purple Acquisition
On July 3, 2012, the Company 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 $331,239, net of cash acquired (“Royal Purple Acquisition”). Royal Purple is a leading independent formulator and marketer of premium industrial and consumer 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 $262,565 from the Company’s June 2012 private placement of 9 5/8% senior notes due August 1, 2020 and cash on hand. The Company believes the Royal Purple Acquisition increases its position in the specialty lubricants market, expands its geographic reach, increases its asset diversity and enhances its specialty products segment. The assets acquired and liabilities assumed and results of operations have been included in the Company’s consolidated balance sheets and consolidated statements of operations since the date of acquisition. In connection with the Royal Purple Acquisition, during the year ended December 31, 2012, the Company incurred acquisition costs of approximately $426 which are reflected in general and administrative expenses in the consolidated statements of operations.
The Company recorded $109,165 of goodwill as a result of the Royal Purple Acquisition, all of which was recorded within the Company’s specialty products segment. Goodwill recognized in the acquisition relates primarily to enhancing the Company’s strategic platform for expansion in its specialty products segment.
The allocation of the aggregate purchase price to assets acquired and liabilities assumed is as follows:
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
The components of intangible assets listed in the table above as of July 3, 2012, based upon a third party appraisal, were as follows:
Montana Acquisition
On October 1, 2012, the Company completed the acquisition from Connacher Oil and Gas Limited (“Connacher”) of all the shares of common stock of Montana Refining Company, Inc. (“Montana”) and an insignificant affiliated company for aggregate consideration of approximately $191,550, net of cash acquired 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 the Company’s revolving credit facility. The Company believes the Montana Acquisition further diversifies its crude oil feedstock slate, operating asset base and geographic presence. The assets acquired and liabilities assumed and results of operations have been included in the Company’s consolidated balance sheets and consolidated statements of operations since the date of acquisition. In connection with the Montana Acquisition, during the year ended December 31, 2012, the Company incurred acquisition costs of approximately $3,267 which are reflected in general and administrative expenses in the consolidated statements of operations.
Immediately after closing the Montana Acquisition, the Company converted Montana Refining Company, Inc. into a Delaware limited liability company, Calumet Montana Refining, LLC. This conversion resulted in the recognition of a current income tax liability, with an expected payment of income taxes in early 2013, of approximately $27,643, which was offset by the derecognition of a deferred tax liability for a comparable amount which was assumed in connection with the acquisition.
The Company recorded $27,643 of goodwill as a result of the Montana Acquisition, all of which was recorded within the Company’s fuel products segment. Goodwill recognized in the acquisition relates primarily to enhancing the Company’s strategic platform for expansion in its fuel products segment.
The Montana Acquisition purchase price allocation has not yet been finalized due to the timing of the closing of the acquisition. The final determination of fair value for certain assets and liabilities will be completed as soon as the information
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
necessary to complete the analysis is obtained. The preliminary allocation of the aggregate purchase price to assets acquired and liabilities assumed is as follows:
Results of Sales and Earnings
The following financial information reflects the results of sales and operating income of the Superior Acquisition that are included in the consolidated statements of operations for the year ended December 31, 2011 and the results of sales and operating income of the Superior, Missouri, TruSouth, Royal Purple and Montana Acquisitions that are included in the consolidated statements of operations for the year ended December 31, 2012:
Pro Forma Financial Information
The following unaudited pro forma financial information reflects the consolidated results of operations of the Company as if the Superior, Royal Purple and Montana Acquisitions had taken place on January 1, 2011.
The Company’s historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the Superior, Royal Purple and Montana Acquisitions. This unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved had the pro forma events taken place on the dates indicated, or the future consolidated results of operations of the combined Company.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
For the year ended December 31, 2012, the unaudited pro forma financial information reflects adjustments to increase interest expense as a result of the issuance of the 2020 Notes (defined below). The unaudited pro forma financial information reflects adjustments to increase amortization expense by $10,864 as a result of recording Royal Purple’s intangible assets.
For the year ended December 31, 2011, the unaudited pro forma financial information reflects adjustments to increase interest expense as a result of the issuance of the 2019 Notes and 2020 Notes (defined below), amending and restating the revolving credit facility, additional borrowings under the revolving credit facility to fund a portion of the Superior and Montana Acquisitions and the repayment of borrowings under the prior term loan from the net proceeds of the 2019 Notes issued in April 2011. The unaudited pro forma financial information also reflects adjustments to increase amortization expense by $20,300 as a result of recording Royal Purple’s intangible assets.
Fair Value Measurements of Acquisitions
The fair value of the property, plant and equipment and intangible assets from acquisitions are based upon the discounted cash flow method that involves inputs that are not observable in the market (Level 3). Goodwill assigned represents the amount of consideration transferred in excess of the fair value assigned to individual assets acquired and liabilities assumed.
4.
Goodwill and Other Intangible Assets
Changes in goodwill balances are as follows:
Other intangible assets consist of the following:
Supplier agreements, tradenames, trade secrets, patents, non-competition agreements, distributor agreements and royalty agreements are being amortized to properly match expense with the discounted estimated future cash flows over the terms of the related agreements. Agreements with terms allowing for the potential extension of such agreements are being amortized based on the initial term only. Customer relationships are being amortized using discounted estimated future cash flows based upon assumed rates of annual customer attrition. For the years ended December 31, 2012, 2011 and 2010, the Company recorded amortization expense of intangible assets of $16,902, $6,991 and $8,810, respectively.
The Company estimates that amortization of intangible assets for the next five years will be as follows:
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
5.
Commitments and Contingencies
Operating Leases
The Company has various operating leases for the use of land, storage tanks, railcars, equipment, precious metals and office facilities that extend through June 2026. Renewal options are available on certain of these leases in which the Company is the lessee. Rent expense for the years ended December 31, 2012, 2011, and 2010 was $26,934, $20,490 and $17,104, respectively.
As of December 31, 2012, the Company had estimated minimum commitments for the payment of rentals under leases which, at inception, had a noncancelable term of more than one year, as follows:
Crude Oil Supply, Other Feedstocks and Finished Products
The Company is currently purchasing a majority of its crude oil under month-to-month evergreen contracts or on a spot basis.
On October 5, 2011, the Company entered into a Crude Oil Purchase Agreement (the “BP Purchase Agreement”) with BP Products North America Inc. (“BP”), pursuant to which BP supplies the Superior refinery with a portion of its daily crude oil requirements, utilizing a market-based pricing mechanism, plus transportation and handling costs. Total crude oil requirements for the Superior refinery are estimated to be between 35,000 and 45,000 bpd. In April 2012, the Company 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. To secure a portion of the Company’s payment obligations under the BP Purchase Agreement, the Company and its affiliates have granted a limited interest capped at $100,000 for physical forwards in the collateral pledged as security under the Collateral Trust Agreement to BP as a “Forward Purchase Secured Hedge Counterparty” under its Collateral Trust Agreement, as such term is defined therein.
Certain other feedstocks are purchased under long-term supply contracts. The Company also purchases finished products from Houston Refining. The Company is required to purchase at least a minimum volume of 3,100 bpd of naphthenic lubricating oils produced at Houston Refining’s refinery in Houston, Texas, and has a right of first refusal to purchase any additional naphthenic lubricating oils produced at the refinery. In addition, Houston Refining is required to process a minimum of approximately 800 bpd of white mineral oil for the Company at Houston Refining’s Houston, Texas refinery. The annual purchase commitment under these agreements is approximately $162,916.
As of December 31, 2012, the estimated minimum purchase commitments under the Company’s crude oil, other feedstock supply and finished product agreements were as follows:
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
In connection with the Company’s acquisition of Penreco on January 3, 2008, the Company entered into a feedstock purchase agreement with Phillips 66 related to the LVT unit at its Lake Charles, Louisiana refinery (the “LVT Feedstock Agreement”). Pursuant to the LVT Feedstock Agreement, Phillips 66 is obligated to supply a minimum quantity (the “Base Volume”) of feedstock for the LVT unit for a term of ten years. Based upon this minimum supply quantity, the Company is obligated to purchase approximately $76,355 of feedstock for the LVT unit in each fiscal year of the term of the contract, expiring January 1, 2018, based on pricing estimates as of December 31, 2012. This amount is not included in the table above.
Labor Matters
The Company has approximately 580 employees covered by various collective bargaining agreements, or approximately 48.7% of its total workforce of approximately 1,190 employees. These agreements have expiration dates of March 31, 2013, April 30, 2013, April 30, 2014, October 31, 2014, January 31, 2015 and June 30, 2017. The Company has approximately 230 employees, or approximately 19.3% of its total workforce, covered by collective bargaining agreements that expire in less than one year and does not expect any work stoppages.
Contingencies
From time to time, the Company is a party to certain claims and litigation incidental to its business, including claims made by various taxation and regulatory authorities, such as the U.S. Environmental Protection Agency (“EPA”), the Louisiana Department of Environmental Quality (“LDEQ”), the Wisconsin Department of Natural Resources (“WDNR”), the Montana Department of Environmental Quality (“MDEQ”), the Texas Commission on Environmental Quality (“TCEQ”), the Internal Revenue Service, various state and local departments of revenue and the federal Occupational Safety and Health Administration (“OSHA”), as the result of audits or reviews of the Company’s business. In addition, the Company has property, business interruption, general liability and various other insurance policies that may result in certain losses or expenditures being reimbursed to the Company.
Insurance Recoveries
During the second quarter of 2011, the Company reached a final settlement of its insurance claim related to the failure of an environmental operating unit at its Shreveport refinery in 2010, resulting in a gain (insurance recoveries) of $8,698 recorded for the year ended December 31, 2011 in the consolidated statements of operations and used the proceeds to repair the failed unit and for working capital needs. This claim related to both property damage and business interruption. Recoveries of $1,942 related to property damage have been reflected within investing activities (with the remainder in operating activities) in the consolidated statements of cash flows.
Environmental
The Company operates 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 the Company’s operations, such as requiring the acquisition of permits to conduct regulated activities, restricting the manner in which the Company 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 for pollution resulting from its 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.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
In connection with the Montana Acquisition (see Note 3), the Company became a party to an existing 2002 Refinery Initiative consent decree (“Montana Consent Decree”) with the EPA and 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. The Company believes that all such contamination is subject to the indemnification of Montana Refining Company, Inc. by Holly Corporation (“Holly”) for pre-existing conditions. The Company is indemnified by Holly under the asset purchase agreement between Holly and Connacher, which the Company became a party to such indemnification rights through the share purchase agreement between the Company and Connacher. Holly is responsible for existing environmental conditions at the Montana refinery, and previously had been reimbursing Connacher for remedial actions subject to the indemnification.
Also, in connection with the Superior Acquisition, the Company became a party to an existing consent decree (“Superior Consent Decree”) with the EPA and the WDNR that applies, in part, to its Superior refinery. Under the Superior Consent Decree, the Company 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 the WDNR. The Company currently estimates costs of approximately $3,000 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, the Company 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 will result in the Company incurring additional costs, which could be substantial. During 2012 and 2011, the Company incurred approximately $2,379 and $2,270, respectively, of costs related to installing process equipment pursuant to the EPA fuel content regulations.
On June 29, 2012, the EPA issued a Finding of Violation/Notice of Violation to the Superior refinery. This finding is in response to information provided to the EPA by the Company in response to an information request. The EPA alleges that the efficiency of the flares at the Superior refinery is lower than regulatory requirements. The Company is contesting the allegations and attended an informal conference with the EPA held September 12, 2012. The Company does not believe that the resolution of these allegations will have a material adverse effect on the Company’s financial results or operations.
In addition, the Company is 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. The Company is 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 $22,000, for which the Company is required to contribute up to the first $6,600.
On December 23, 2010, the Company entered into a settlement agreement with the LDEQ under LDEQ’s “Small Refinery and Single Site Refinery Initiative,” covering the 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 the Company agreed to complete beneficial environmental programs and implement emissions reduction projects at the Company’s Shreveport, Cotton Valley and Princeton refineries on an agreed-upon schedule. During 2012 and 2011, the Company incurred approximately $4,200 and $4,000, respectively, of expenditures and estimates additional expenditures of approximately $2,000 to $6,000 of capital expenditures and expenditures related to additional personnel and environmental studies over the next three years as a result of the implementation those requirements. These capital investment requirements will be incorporated into the Company’s annual capital expenditures budget, and the Company does not expect any additional
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
capital expenditures as a result of the required audits or required operational changes included in the settlement to have a material adverse effect on the Company’s financial results or operations.
In addition, new laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement or other developments could require the Company 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 New Source Performance Standards (“NSPS”) for petroleum refineries, including standards for emissions of nitrogen oxides from process heaters and work practice standards and monitoring requirements for flares. The Company is currently evaluating the effect that the NSPS rule may have on the Company’s refinery operations.
Voluntary remediation of subsurface contamination is in process at each of the Company’s refinery sites. The remedial projects are being overseen by the appropriate state agencies. Based on current investigative and remedial activities, the Company believes that the groundwater contamination at these refineries can be controlled or remedied without having a material adverse effect on the Company’s financial condition. However, such costs are often unpredictable and, therefore, there can be no assurance that the future costs will not become material. Additionally, the Company incurred approximately $395, $338 and $541 in 2012, 2011 and 2010, respectively, of such capital expenditures at its Cotton Valley refinery.
The Company is 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 the Company’s acquisition of the facility. The indemnity is unlimited in amount and duration, but requires the Company to contribute up to $1,000 of the first $5,000 of indemnified costs for certain of the specified environmental liabilities.
Occupational Health and Safety
The Company is subject to various laws and regulations relating to occupational health and safety, including 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 the Company’s operations and that this information be provided to employees, contractors, state and local government authorities and customers. The Company maintains safety and training programs as part of its ongoing efforts to ensure compliance with applicable laws and regulations. The Company has 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 the Company’s ISO-9001-2008 Standard certification is maintained through surveillance audits by its registrar at regular intervals designed to ensure adherence to the standards. The Company’s 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.
The Company has completed studies to assess the adequacy of its process safety management practices at its Shreveport refinery with respect to certain consensus codes and standards. As of December 31, 2012 and December 31, 2011, the Company incurred approximately $728 and $4,075, respectively, of capital expenditures and expects to incur between $1,000 and $4,000 of capital expenditures in 2013 to address OSHA compliance issues identified in these studies. The Company expects these capital expenditures will enhance its equipment such that the equipment maintains compliance with applicable consensus codes and standards.
Beginning in February 2010, OSHA conducted an inspection of the Shreveport refinery’s process safety management program under OSHA’s National Emphasis Program. On August 19, 2010, OSHA issued a Citation and Notification of Penalty (the “Shreveport Citation”) to the Company as a result of the Shreveport inspection, which included a civil penalty amount of $119 that was paid in January 2011. In the first quarter of 2011, OSHA conducted an inspection of the Cotton Valley refinery’s process safety management program under this OSHA initiative. On March 14, 2011, OSHA issued a Citation and Notification of Penalty (the “Cotton Valley Citation”) to the Company as a result of the Cotton Valley inspection, which included a proposed penalty amount of $208. The Company has contested the Cotton Valley Citation and associated penalties and is 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.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
Standby Letters of Credit
The Company has agreements with various financial institutions for standby letters of credit which have been issued to domestic vendors. As of December 31, 2012 and December 31, 2011, the Company had outstanding standby letters of credit of $222,359 and $230,040, respectively, under its senior secured revolving credit facility (the “revolving credit facility”). Refer to Note 6 for additional information regarding the Company’s revolving credit facility. The maximum amount of letters of credit the Company could issue at December 31, 2012 and December 31, 2011 under its revolving credit facility is subject to borrowing base limitations, with a maximum letter of credit sublimit equal to $680,000, which is the greater of (i) $400,000 and (ii) 80% of revolver commitments in effect ($850,000 at December 31, 2012 and December 31, 2011).
As of December 31, 2012 and December 31, 2011, the Company had availability to issue letters of credit of $355,091 and $340,715, respectively, under its revolving credit facility. As discussed in Note 6, as of December 31, 2012 and December 31, 2011 the outstanding standby letters of credit issued under the revolving credit facility included a $25,000 letter of credit issued to a hedging counterparty to support a portion of its fuel products hedging program.
6.
Long-Term Debt
Long-term debt consisted of the following:
9 5/8% Senior Notes
On June 29, 2012, in connection with the Royal Purple Acquisition, the Company issued and sold $275,000 in aggregate principal amount of 9 5/8% of senior notes due August 1, 2020 (the “2020 Notes”) in a private placement pursuant to Rule 144A under the Securities Act of 1933, as amended (the “Securities Act”), to eligible purchasers at a discounted price of 98.25 percent of par. The 2020 Notes were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. The Company received net proceeds of $262,565, net of discount, underwriters’ fees and expenses, which the Company used to fund a portion of the purchase price of the Royal Purple Acquisition. Refer to Note 3 for additional information regarding the Royal Purple Acquisition.
Interest on the 2020 Notes is paid semiannually in arrears on February 1 and August 1 of each year, beginning on February 1, 2013. The 2020 Notes will mature on August 1, 2020, unless redeemed prior to maturity. The 2020 Notes are jointly and severally guaranteed on a senior unsecured basis by all of the Company’s current operating subsidiaries and certain of the Company’s future operating subsidiaries, with the exception of Calumet Finance Corp. (a wholly owned Delaware corporation that was organized for the sole purpose of being a co-issuer of certain of the Company’s indebtedness, including the 2020 Notes). The operating subsidiaries may not sell or otherwise dispose of all or substantially all of their properties or assets to, or consolidate with or merge into, another company if such a sale would cause a default under the indenture governing the 2020 Notes. Since all Company’s operating subsidiaries guarantee the 2020 Notes, condensed consolidating financial statements of non-guarantors are not required in accordance with Rule 3-10 of Regulation S-X.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
At any time prior to August 1, 2015, the Company may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2020 Notes with the net proceeds of a public or private equity offering at a redemption price of 109.625% of the principal amount, plus any accrued and unpaid interest to the date of redemption, provided that: (1) at least 65% of the aggregate principal amount of 2020 Notes issued remains outstanding immediately after the occurrence of such redemption and (2) the redemption occurs within 120 days of the date of the closing of such public or private equity offering.
On and after August 1, 2016, the Company may on any one or more occasions redeem all or a part of the 2020 Notes at the redemption prices (expressed as percentages of principal amount) set forth below, plus any accrued and unpaid interest to the applicable redemption date on such 2020 Notes, if redeemed during the twelve-month period beginning on August 1 of the years indicated below:
Prior to August 1, 2016, the Company may on any one or more occasions redeem all or part of the 2020 Notes at a redemption price equal to the sum of: (1) the principal amount thereof, plus (2) a make-whole premium (as set forth in the indenture governing the 2020 Notes) at the redemption date, plus any accrued and unpaid interest to the applicable redemption date.
The indenture governing the 2020 Notes contains covenants that, among other things, restrict the Company’s ability and the ability of certain of the Company’s subsidiaries to: (i) sell assets; (ii) pay distributions on, redeem or repurchase the Company’s common units or redeem or repurchase its subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (vii) consolidate, merge or transfer all or substantially all of the Company’s assets; (viii) engage in transactions with affiliates and (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. At any time when the 2020 Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default or Event of Default, each as defined in the indenture governing the 2020 Notes, has occurred and is continuing, many of these covenants will be suspended.
Upon the occurrence of certain change of control events, each holder of the 2020 Notes will have the right to require that the Company repurchase all or a portion of such holder’s 2020 Notes in cash at a purchase price equal to 101% of the principal amount thereof, plus any accrued and unpaid interest to the date of repurchase.
On June 29, 2012, in connection with the issuance and sale of the 2020 Notes, the Company entered into a registration rights agreement with the initial purchasers of the 2020 Notes obligating the Company to use reasonable best efforts to file an exchange registration statement with the SEC, so that holders of the 2020 Notes can offer to exchange the 2020 Notes for registered notes having substantially the same terms as the 2020 Notes and evidencing the same indebtedness as the 2020 Notes. The Company must use reasonable best efforts to cause the exchange offer registration statement to become effective by June 28, 2013 and remain effective until 180 days after the closing of the exchange. Additionally, the Company has agreed to commence the exchange offer promptly after the exchange offer registration statement is declared effective by the SEC and use reasonable best efforts to complete the exchange offer not later than 60 days after such effective date. Under certain circumstances, in lieu of a registered exchange offer, the Company must use reasonable best efforts to file a shelf registration statement for the resale of the 2020 Notes. If the Company fails to satisfy these obligations on a timely basis, the annual interest borne by the 2020 Notes will be increased by up to 1.0% per annum until the exchange offer is completed or the shelf registration statement is declared effective.
9 3/8% Senior Notes
On April 21, 2011, in connection with the restructuring of the majority of its outstanding long-term debt, the Company issued and sold $400,000 in aggregate principal amount of 9 3/8% of senior notes due May 1, 2019 (the “2019 Notes issued in April 2011”) in a private placement pursuant to Rule 144A under the Securities Act to eligible purchasers at par. The 2019 Notes issued in April 2011 were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. The Company received proceeds of $388,999 net of underwriters’ fees and expenses, which the Company used to repay in full borrowings outstanding under its prior term loan, as well as all accrued interest and fees, and for general partnership purposes.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
On September 19, 2011, in connection with the Superior Acquisition, the Company issued and sold $200,000 in aggregate principal amount of 9 3/8% of senior notes due May 1, 2019 (the “2019 Notes issued in September 2011”) in a private placement pursuant to Rule 144A under the Securities Act to eligible purchasers at a discounted price of 93 percent of par. The 2019 Notes issued in September 2011 were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. The Company received proceeds of $180,296 net of discount, underwriters’ fees and expenses, which the Company used to fund a portion of the purchase price of the Superior Acquisition. Because the terms of the 2019 Notes issued in September 2011 are substantially identical to the terms of the 2019 Notes issued in April 2011, in this Annual Report, the Company collectively refers to the 2019 Notes issued in April 2011 and the 2019 Notes issued in September 2011 as the “2019 Notes.”
Interest on the 2019 Notes is paid semiannually in arrears on May 1 and November 1 of each year, beginning on November 1, 2011. The 2019 Notes will mature on May 1, 2019, unless redeemed prior to maturity. The 2019 Notes are jointly and severally guaranteed on a senior unsecured basis by all of the Company’s current operating subsidiaries and certain of the Company’s future operating subsidiaries, with the exception of Calumet Finance Corp. (a wholly owned Delaware corporation that was organized for the sole purpose of being a co-issuer of certain of the Company’s indebtedness, including the 2019 Notes). The operating subsidiaries may not sell or otherwise dispose of all or substantially all of their properties or assets to, or consolidate with or merge into, another company if such a sale would cause a default under the indentures governing the 2019 Notes. Since all Company’s operating subsidiaries guarantee the 2019 Notes, condensed consolidating financial statements of non-guarantors are not required in accordance with Rule 3-10 of Regulation S-X.
At any time prior to May 1, 2014, the Company may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2019 Notes with the net proceeds of a public or private equity offering at a redemption price of 109.375% of the principal amount, plus any accrued and unpaid interest to the date of redemption, provided that: (1) at least 65% of the aggregate principal amount of 2019 Notes issued remains outstanding immediately after the occurrence of such redemption and (2) the redemption occurs within 120 days of the date of the closing of such public or private equity offering.
On and after May 1, 2015, the Company may on any one or more occasions redeem all or a part of the 2019 Notes at the redemption prices (expressed as percentages of principal amount) set forth below, plus any accrued and unpaid interest to the applicable redemption date on such 2019 Notes, if redeemed during the twelve-month period beginning on May 1 of the years indicated below:
Prior to May 1, 2015, the Company may on any one or more occasions redeem all or part of the 2019 Notes at a redemption price equal to the sum of: (1) the principal amount thereof, plus (2) a make-whole premium (as set forth in the indentures governing the 2019 Notes) at the redemption date, plus any accrued and unpaid interest to the applicable redemption date.
The indentures governing the 2019 Notes contain covenants that, among other things, restrict the Company’s ability and the ability of certain of the Company’s subsidiaries to: (i) sell assets; (ii) pay distributions on, redeem or repurchase the Company’s common units or redeem or repurchase its subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (vii) consolidate, merge or transfer all or substantially all of the Company’s assets; (viii) engage in transactions with affiliates and (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. At any time when the 2019 Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default or Event of Default, each as defined in the indentures governing the 2019 Notes, has occurred and is continuing, many of these covenants will be suspended.
Upon the occurrence of certain change of control events, each holder of the 2019 Notes will have the right to require that the Company repurchase all or a portion of such holder’s 2019 Notes in cash at a purchase price equal to 101% of the principal amount thereof, plus any accrued and unpaid interest to the date of repurchase.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
In connection with the issuances and sales of the 2019 Notes, the Company entered into registration rights agreements with the initial purchasers of the 2019 Notes obligating the Company to use reasonable best efforts to file an exchange registration statement with the SEC so that holders of the 2019 Notes could offer to exchange the 2019 Notes for registered notes having substantially the same terms as the 2019 Notes and evidencing the same indebtedness as the 2019 Notes. On December 16, 2011, the Company filed exchange offer registration statements for the 2019 Notes with the SEC, which were declared effective on January 3, 2012. The exchange offers were completed on February 2, 2012, thereby fulfilling all of the requirements of the 2019 Notes registration rights agreements by the specified dates.
Termination of Senior Secured First Lien Credit Facility
The Company’s prior $435,000 senior secured first lien credit facility (the “prior term loan”) included a $385,000 term loan and a $50,000 prefunded letter of credit facility to support crack spread hedging. The Company extinguished this facility on April 21, 2011 in connection with the issuance and sale of the 2019 Notes issued in April 2011, as further discussed below. The prior term loan bore interest at a rate equal to (i) with respect to a LIBOR Loan, the LIBOR Rate (as defined in the senior secured first lien credit agreement) plus 400 basis points and (ii) with respect to a Base Rate Loan, the Base Rate (as defined in the senior secured first lien credit agreement) plus 300 basis points. At December 31, 2010, the term loan bore interest at 4.29%.
On April 21, 2011, the Company used approximately $369,486 of the net proceeds from the issuance and sale of the 2019 Notes issued in April 2011 to repay in full its term loan, as well as accrued interest and fees, and terminated the entire senior secured first lien credit facility, including the term loan and a $50,000 prefunded letter of credit to support crack spread hedging. The Company did not incur any material early termination penalties in connection with its termination of the senior secured first lien credit facility. Further, in the second quarter of 2011 the Company recorded approximately $15,130 of debt extinguishment charges related to the write off of the unamortized debt issuance costs and the unamortized discount associated with the prior term loan.
Amended and Restated Senior Secured Revolving Credit Facility
The Company has an $850,000 senior secured revolving credit facility, which is its primary source of liquidity for cash needs in excess of cash generated from operations. The revolving credit facility matures in June 2016 and currently bears interest at a rate equal to prime plus a basis points margin or LIBOR plus a basis points margin, at the Company’s option. As of December 31, 2012, the margin was 100 basis points for prime and 225 basis points for LIBOR; however, the margin can fluctuate quarterly based on the Company’s average availability for additional borrowings under the revolving credit facility in the preceding calendar quarter as follows:
In addition to paying interest monthly on outstanding borrowings under the revolving credit facility, the Company is required to pay a commitment fee to the lenders under the revolving credit facility with respect to the unutilized commitments thereunder at a rate equal to either 0.375% or 0.50% per annum depending on the average daily available unused borrowing capacity for the preceding month. The Company also pays a customary letter of credit fee, including a fronting fee of 0.125% per annum of the stated amount of each outstanding letter of credit, and customary agency fees.
The borrowing capacity at December 31, 2012 under the revolving credit facility was $577,450. As of December 31, 2012, the Company had no outstanding borrowings under the revolving credit facility, leaving $355,091 available for additional borrowings based on specified availability limitations. Lenders under the revolving credit facility have a first priority lien on the Company’s cash, accounts receivable, inventory and certain other personal property.
The revolving credit facility contains various covenants that limit, among other things, the Company’s ability to: incur indebtedness; grant liens; dispose of certain assets; make certain acquisitions and investments; redeem or prepay other debt or make other restricted payments such as distributions to unitholders; enter into transactions with affiliates and enter into a merger, consolidation or sale of assets. Further, the revolving credit facility contains one springing financial covenant which provides that only if the Company’s 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 credit agreement commitments then in effect and (ii) $46,364, (as
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
increased, upon the effectiveness of the increase in the maximum availability under the revolving credit facility, by the same percentage as the percentage increase in the revolving credit agreement commitments), then the Company 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.
Amendments to Master Derivative Contracts
In connection with the termination of the prior term loan and the amendment of the revolving credit facility, on April 21, 2011, the Company entered into amendments to certain of the Company’s master derivatives contracts (“Amendments”) to provide new credit support arrangements to secure the Company’s payment obligations under these contracts following the termination of the term loan facility and the amendment and restatement of the prior term loan facility. Under the new credit support arrangements, the Company’s payment obligations under all of the Company’s master derivatives contracts for commodity hedging generally are secured by a first priority lien on the Company’s 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 foregoing (including proceeds of hedge arrangements). The Company has also issued to one counterparty a $25,000 standby letter of credit under the revolving credit facility. In the event that such counterparty’s exposure to the Company exceeds $200,000, the Company will be required to post additional collateral support in the form of either cash or letters of credit with the counterparty to enter into additional crack spread hedges. The Company had no additional letters of credit or cash margin posted with any hedging counterparty as of December 31, 2012 and 2011. The Company’s master derivatives contracts and Collateral Trust Agreement (as defined below) continue to impose a number of covenant limitations on the Company’s operating and financing activities, including limitations on liens on collateral, limitations on dispositions of collateral and collateral maintenance and insurance requirements.
Collateral Trust Agreement
In connection with the Amendments, on April 21, 2011, the Company entered into a collateral sharing agreement (the “Collateral Trust Agreement”) with each of its secured hedging counterparties and an administrative agent for the benefit of the secured hedging counterparties, which governs how the secured hedging counterparties will share collateral pledged as security for the payment obligations owed by the Company to the secured hedging counterparties under their respective master derivatives contracts. Subject to certain conditions set forth in the Collateral Trust Agreement, the Company has the ability to add secured hedging counterparties from time to time.
In connection with the closing of the Superior Acquisition, on September 30, 2011, the Company entered into an amendment (the “CTA Amendment”) to the Collateral Trust Agreement with each of its secured hedging counterparties and the administrative agent. The CTA Amendment modified the Collateral Trust Agreement so as to limit to $100,000 the extent to which forward purchase contracts for physical commodities would be covered by, and secured under, the Collateral Trust Agreement. The CTA Amendment also eliminated the credit rating requirement with respect to forward purchase contract counterparties on physical commodities.
Maturities of Long-Term Debt
As of December 31, 2012, maturities of the Company’s long-term debt are as follows:
Capital Lease Obligations
The Company has a capital lease obligation for catalysts used in refining processes which will expire in 2013. In connection with the TruSouth Acquisition, the Company recorded $5,771 of capital leases for a building and equipment that will expire in 2027 and 2018, respectively. Assets recorded under these capital lease obligations are included in property, plant
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
and equipment and consist of $11,071 and $4,201 as of December 31, 2012 and 2011, respectively. As of December 31, 2012 and 2011, the Company had recorded $4,251 and $3,221, respectively, in accumulated depreciation for these capital lease assets.
As of December 31, 2012, the Company had estimated minimum commitments for the payment of total rentals under capital leases as follows:
7.
Derivatives
The Company is exposed to price risks due to fluctuations in the price of crude oil, refined products (primarily in the Company’s fuel products segment) and natural gas. The Company uses various strategies to reduce the exposure to commodity price risk. The Company does not attempt to eliminate all of the Company’s risk due to the cost of such actions are believed to be too high in relation to the risk posed to the Company’s future cash flows, earnings and liquidity. The strategies to reduce the Company’s risk utilize both physical forward contracts and financially settled derivative instruments such as swaps, futures and options to attempt to reduce the Company’s exposure with respect to:
•
crude oil purchases;
•
refined product sales;
•
natural gas purchases; and
•
fluctuations in the value of crude oil between geographic regions and in between the different types of crude oil such as NYMEX WTI, Light Louisiana Sour (“LLS”) and Western Canadian Select (“WCS”).
The Company does not hold or issue derivative instruments for trading purposes.
The Company recognizes all derivative instruments at their fair values (see Note 8) as either current assets or current liabilities on the consolidated balance sheets. Fair value includes any premiums paid or received and unrealized gains and losses. Fair value does not include any amounts receivable from or payable to counterparties, or collateral provided to counterparties. Derivative asset and liability amounts with the same counterparty are netted against each other for financial reporting purposes. The Company’s financial results are subject to the possibility that changes in a derivative’s fair value could result in significant ineffectiveness and potentially no longer qualifying it for hedge accounting. The Company recorded the following derivative assets and liabilities at their fair values as of December 31, 2012 and 2011:
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
(1)
The Company has historically entered into combinations of crude oil options and swaps and natural gas swaps to economically hedge its exposures to price risk related to these commodities in its specialty products segment. The Company has not designated these derivative instruments as cash flow hedges.
(2)
The Company periodically enters into natural gas swaps to economically hedge its exposures to price risk related to these commodities in its specialty products segment. The Company has not designated these derivative instruments as cash flow hedges.
(3)
The Company refinanced a significant majority of its long-term debt in April 2011 and, as a result, all of its interest rate swaps that were designated as cash flow hedges for the interest payments under the previous term loan facility are no longer designated as cash flow hedges.
The Company accounts for certain derivatives hedging purchases of crude oil, sales of gasoline, diesel and jet fuel as cash flow hedges. The derivatives hedging sales and purchases are recorded to sales and cost of sales, respectively, in the consolidated statements of operations upon recording the related hedged transaction in sales or cost of sales. The derivatives designated as hedging payments of interest are recorded in interest expense in the consolidated statements of operations upon payment of interest. The Company assesses, both at inception of the hedge and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. Periodically, the Company may enter into crude oil or fuel product basis swaps to more effectively hedge its crude oil purchases. These derivatives can be combined with a swap contract in order to create a more effective hedge. The Company has entered into crude oil basis swaps for 2013 that do not qualify as cash flow hedges for accounting purposes as they were not entered into simultaneously with a corresponding NYMEX WTI derivative contract.
To the extent a derivative instrument designated as a hedge is determined to be effective as a cash flow hedge of an exposure to changes in the fair value of a future transaction, the change in fair value of the derivative is deferred in accumulated other comprehensive income (loss), a component of partners’ capital in the consolidated balance sheets, until the underlying transaction hedged is recognized in the consolidated statements of operations. Hedge accounting is discontinued when it is determined that a derivative no longer qualifies as an effective hedge or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative instrument no longer qualifies as an effective cash flow hedge, the derivative instrument is subject to the mark-to-market method of accounting prospectively. Changes in the mark-to-market fair value of the derivative instrument are recorded to unrealized gain (loss) on derivative
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
instruments in the consolidated statements of operations. Unrealized gains and losses related to discontinued cash flow hedges that were previously accumulated in accumulated other comprehensive income (loss) will remain in accumulated other comprehensive income (loss) until the underlying transaction is reflected in earnings, unless it is probable that the hedged forecasted transaction will not occur, at which time, associated deferred amounts in accumulated other comprehensive income (loss) are immediately recognized in unrealized gain (loss) on derivative instruments.
Effective January 1, 2012, hedge accounting was discontinued prospectively for certain crude oil derivative instruments when it was determined that they were no longer highly effective in offsetting changes in the cash flows associated with crude oil purchases at the Company’s Superior refinery due to the volatility in crude oil pricing differentials between heavy crude oil and NYMEX WTI. Effective April 1, 2012, hedge accounting was discontinued prospectively for certain gasoline and diesel derivative instruments associated with gasoline and diesel sales at the Company’s Superior refinery. The discontinuance of hedge accounting on these derivative instruments has caused the Company to recognize derivative gains of $40,096 in realized gain (loss) on derivative instruments in the consolidated statements of operations for the year ended December 31, 2012. The discontinuance of hedge accounting on these derivative instruments caused the Company to recognize derivative losses $2,933 in unrealized loss on derivative instruments in the consolidated statements of operations for the year ended December 31, 2012.
The amount reclassified from accumulated other comprehensive income (loss) into earnings, as a result of the discontinuance of hedge accounting for certain jet fuel products derivative instruments because it was no longer probable that the original forecasted transaction would occur by the end of the originally specified time period, has caused the Company to recognize derivative losses of $1,719 in realized gain (loss) on derivative instruments in the consolidated statements of operations for the year ended December 31, 2012.
For derivative instruments not designated as cash flow hedges and the portion of any cash flow hedge that is determined to be ineffective, the change in fair value of the asset or liability for the period is recorded to unrealized gain (loss) on derivative instruments in the consolidated statements of operations. Upon the settlement of a derivative not designated as a cash flow hedge, the gain or loss at settlement is recorded to realized gain (loss) on derivative instruments in the consolidated statements of operations. Ineffectiveness is inherent in the hedging of crude oil and fuel products. Due to the volatility in the markets for crude oil and fuel products, the Company is unable to predict the amount of ineffectiveness each period, which has the potential for the future loss of hedge accounting, determined on a derivative by derivative basis or in the aggregate for a specific commodity. Ineffectiveness has resulted, and the loss of hedge accounting has resulted, in increased volatility in the Company’s financial results. However, even though certain derivative instruments may not qualify for hedge accounting, the Company intends to continue to utilize such instruments as management believes such derivative instruments continue to provide the Company with the opportunity to more effectively stabilize cash flows.
The Company recorded the following amounts in its consolidated balance sheets, consolidated statements of operations, consolidated statements of other comprehensive income (loss) and its consolidated statements of partners’ capital as of, and for the years ended December 31, 2012 and 2011 related to its derivative instruments that were designated as cash flow hedges:
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
The Company recorded the following gains (losses) in its consolidated statements of operations for the years ended December 31, 2012 and 2011 related to its derivative instruments not designated as cash flow hedges:
The cash flow impact of the Company’s derivative activities is classified as a change in derivative activity in the operating activities section in the consolidated statements of cash flows.
The Company is exposed to credit risk in the event of nonperformance by its counterparties on derivative transactions. The Company does not expect nonperformance on any derivative instruments, however, no assurances can be provided. The Company’s credit exposure related to these derivative instruments is represented by the fair value of contracts reported as derivative assets. As of December 31, 2012, the Company had two counterparties, for which the derivatives held were net assets, totaling $3,088.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
To manage credit risk, the Company selects and periodically reviews counterparties based on credit ratings. The Company primarily executes its derivative instruments with large financial institutions that have ratings of at least Baa2 and A- by Moody’s and S&P, respectively. In the event of default, the Company potentially would be subject to losses on derivative instruments with mark-to- market gains. The Company requires collateral from its counterparties when the fair value of the derivatives exceeds agreed upon thresholds in its master derivative contracts with these counterparties. No such collateral was held by the Company as of December 31, 2012 or December 31, 2011. The Company’s contracts with these counterparties allow for netting of derivative instruments executed under each contract. Collateral received from counterparties is reported in other current liabilities, and collateral held by counterparties is reported in deposits on the Company’s consolidated balance sheets and not netted against derivative assets or liabilities. As of December 31, 2012 and 2011, the Company had provided its counterparties with no collateral except for a $25,000 letter of credit provided to one counterparty to support crack spread hedging. For financial reporting purposes, the Company does not offset the collateral provided to a counterparty against the fair value of its obligation to that counterparty. Any outstanding collateral is released to the Company upon settlement of the related derivative instrument liability.
Certain of the Company’s outstanding derivative instruments are subject to credit support agreements with the applicable counterparties which contain provisions setting certain credit thresholds above which the Company may be required to post agreed-upon collateral, such as cash or letters of credit, with the counterparty to the extent that the Company’s mark-to-market net liability, if any, on all outstanding derivatives exceeds the credit threshold amount per such credit support agreement. In certain cases, the Company’s credit threshold is dependent upon the Company’s maintenance of certain corporate credit ratings with Moody’s and S&P. In the event that the Company’s corporate credit rating was lowered below its current level by either Moody’s or S&P, such counterparties would have the right to reduce the applicable threshold to zero and demand full collateralization of the Company’s net liability position on outstanding derivative instruments. As of December 31, 2012 and 2011, there was a net liability of $7,515 and a net asset of $3,561, respectively, associated with the Company’s outstanding derivative instruments subject to such requirements. In addition, certain of the credit support agreements covering the Company’s outstanding derivative instruments also contain a general provision stating that if the Company experiences a material adverse change in its business, in the reasonable discretion of the counterparty, the Company’s credit threshold could be lowered by such counterparty. The Company does not expect that it will experience a material adverse change in its business.
The effective portion of the cash flow hedges classified in accumulated other comprehensive loss was $13,953 as of December 31, 2012. The effective portion of the cash flow hedges classified in accumulated other comprehensive income was $47,094 as of December 31, 2011. Absent a change in the fair market value of the underlying transactions, the following other comprehensive income (loss) at December 31, 2012 will be reclassified to earnings by December 31, 2015 with balances being recognized as follows:
Based on fair values as of December 31, 2012, the Company expects to reclassify $7,755 of net losses on derivative instruments from accumulated other comprehensive loss to earnings during the next twelve months due to actual crude oil purchases and gasoline, diesel and jet fuel sales. However, the amounts actually realized will be dependent on the fair values as of the dates of settlements.
Crude Oil Swap Contracts - Specialty Products Segment
As of December 31, 2012, the Company had purchased a crude oil swap for 200,000 bbls in the second quarter of 2012 related to future crude oil purchases in its specialty products segment, which is not designated as a cash flow hedge. The Company subsequently sold a crude oil derivative swap in the third quarter of 2012, and the net impact of these two derivatives is a net gain of $1,649 that has been recorded to unrealized loss in the consolidated statements of operations for the year ended December 31, 2012. This gain will be realized in January 2013 upon settlement and will be recorded to realized gain (loss) on derivative instruments in the consolidated statements of operations.
At December 31, 2011, the Company did not have any crude oil derivatives related to future crude oil purchases in its specialty products segment.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
Natural Gas Swap Contracts
At December 31, 2012, the Company did not have any natural gas derivatives related to natural gas purchases in its specialty products segment.
At December 31, 2011, the Company had the following natural gas derivatives related to natural gas purchases in its specialty products segment, none of which were designated as cash flow hedges.
Crude Oil Contracts - Fuel Products Segment
Crude Oil Swap Contracts
At December 31, 2012, the Company had the following derivatives related to crude oil purchases in its fuel products segment, all of which are designated as cash flow hedges.
At December 31, 2012, the Company had the following derivatives related to crude oil purchases in its fuel products segment, none of which are designated as cash flow hedges.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
At December 31, 2011, the Company had the following derivatives related to crude oil purchases in its fuel products segment, all of which are designated as cash flow hedges.
Crude Oil Basis Swap Contracts
In April, July and December 2012, the Company entered into crude oil basis swaps to mitigate the risk of future changes in pricing differentials between Canadian heavy crude oil and NYMEX WTI crude oil. At December 31, 2012, the Company had the following derivatives related to crude oil basis swaps in its fuel products segment, none of which are designated as cash flow hedges.
At December 31, 2011, the Company had no derivatives related to crude oil basis swaps in its fuel products segment.
Fuel Products Swap Contracts
Diesel Swap Contracts
At December 31, 2012, the Company had the following derivatives related to diesel and jet fuel sales in its fuel products segment, all of which are designated as cash flow hedges.
At December 31, 2012, the Company had the following derivatives related to diesel and jet fuel sales in its fuel products segment, none of which are designated as cash flow hedges.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
At December 31, 2011, the Company had the following derivatives related to diesel and jet fuel sales in its fuel products segment, all of which are designated as cash flow hedges.
Jet Fuel Swap Contracts
At December 31, 2012, the Company had the following derivatives related to diesel and jet fuel sales in its fuel products segment, all of which are designated as cash flow hedges.
At December 31, 2011, the Company had the following derivatives related to diesel and jet fuel sales in its fuel products segment, all of which are designated as cash flow hedges.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
Gasoline Swap Contracts
At December 31, 2012, the Company had the following derivatives related to gasoline sales in its fuel products segment, all of which are designated as cash flow hedges.
At December 31, 2012, the Company had the following derivatives related to gasoline sales in its fuel products segment, none of which are designated as cash flow hedges.
At December 31, 2011, the Company had the following derivatives related to gasoline sales in its fuel products segment, all of which are designated as cash flow hedges.
Interest Rate Swap Contracts
The Company has no variable rate debt and no interest rate swaps outstanding as of December 31, 2012. For the Company’s fixed rate 2019 and 2020 Notes, changes in interest rates will generally affect the fair value, but not the Company’s interest expense or cash flows.
8.
Fair Value Measurements
The Company uses a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. Observable inputs are from sources independent of the Company. Unobservable inputs reflect the Company’s assumptions about the factors market participants would use in valuing the asset or liability developed based upon the best information available in the circumstances. These tiers include the following:
•
Level 1-inputs include observable unadjusted quoted prices in active markets for identical assets or liabilities
•
Level 2-inputs include other than quoted prices in active markets that are either directly or indirectly observable
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
•
Level 3-inputs include unobservable inputs in which little or no market data exists; therefore requiring an entity to develop its own assumptions
In determining fair value, the Company uses various valuation techniques and prioritizes the use of observable inputs. The availability of observable inputs varies from instrument to instrument and depends on a variety of factors including the type of instrument, whether the instrument is actively traded and other characteristics particular to the instrument. For many financial instruments, pricing inputs are readily observable in the market, the valuation methodology used is widely accepted by market participants and the valuation does not require significant management judgment. For other financial instruments, pricing inputs are less observable in the marketplace and may require management judgment.
Recurring Fair Value Measurements
Derivative Assets and Liabilities
Derivative instruments are reported in the accompanying consolidated financial statements at fair value. The Company’s derivative instruments consist of over-the-counter (“OTC”) contracts, which are not traded on a public exchange. Substantially all of the Company’s derivative instruments are with counterparties that have long-term credit ratings of at least Baa2 and A- by Moody’s and S&P, respectively.
To estimate the fair values of the Company’s derivative instruments, the Company uses the market approach. Under this approach, the fair values of the Company’s derivative instruments for crude oil, crude oil basis, gasoline, diesel, jet fuel, natural gas and interest rate swaps are determined primarily based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. Generally, the Company obtains this data through surveying its counterparties and performing various analytical tests to validate the data. In situations where the Company obtains inputs via quotes from its counterparties, it verifies the reasonableness of these quotes via similar quotes from another counterparty as of each date for which financial statements are prepared. The Company also includes an adjustment for non-performance risk in the recognized measure of fair value of all of the Company’s derivative instruments. The adjustment reflects the full credit default spread (“CDS”) applied to a net exposure by counterparty. When the Company is in a net asset position it uses its counterparty’s CDS, or a peer group’s estimated CDS when a CDS for the counterparty is not available. The Company uses its own peer group’s estimated CDS when it is in a net liability position. As a result of applying the applicable CDS at December 31, 2012, the Company’s asset was reduced by $100 and liability was reduced by approximately $185. As a result of applying the CDS at December 31, 2011, the Company’s asset was reduced by $1,297 and the liability was reduced by approximately $165.
Based on the use of various unobservable inputs, principally non-performance risk and unobservable inputs in forward years for crude oil, crude oil basis, gasoline, jet fuel, diesel, natural gas and interest rate swaps, the Company has categorized these derivative instruments as Level 3. Significant increases (decreases) in any of those unobservable inputs in isolation would result in a significantly lower (higher) fair value measurement. The Company has consistently applied these valuation techniques in all periods presented and believes it has obtained the most accurate information available for the types of derivative instruments it holds. See Note 7 for further information on derivative instruments.
Pension Assets
Pension assets are reported at fair value using quoted market prices in the accompanying consolidated financial statements. The Company’s investments associated with its Pension Plan (as such term is hereinafter defined) primarily consist of (i) cash and cash equivalents, (ii) mutual funds that are publicly traded, (iii) a commingled fund and (iv) a balanced fund. The mutual and balanced funds are publicly traded and market prices are readily available; thus, these investments are categorized as Level 1. The commingled fund is categorized as Level 2 because inputs used in its valuation are not quoted prices in active markets that are indirectly observable and is valued at the net asset value of shares held by the Pension Plan at quarter end. See Note 11 for further information on pension assets.
Liability Awards
The fair values of the Company’s Liability Awards are updated each balance sheet date based on the closing unit price on the balance sheet date. See Note 10 for further information on Liability Awards.
Hierarchy of Recurring Fair Value Measurements
The Company’s recurring assets and liabilities measured at fair value at December 31, 2012 and December 31, 2011 were as follows:
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
The table below sets forth a summary of net changes in fair value of the Company’s Level 3 financial assets and liabilities for the year ended December 31, 2012 and 2011:
All settlements from derivative instruments that are deemed “effective” and were designated as cash flow hedges are included in sales for gasoline, diesel and jet fuel derivatives, cost of sales for crude oil and natural gas derivatives, and interest expense for interest rate derivatives in the consolidated financial statements of operations in the period that the hedged cash flow occurs. Any “ineffectiveness” associated with these derivative instruments are recorded in earnings in realized gain (loss)
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
on derivative instruments in the consolidated statements of operations. All settlements from derivative instruments not designated as cash flow hedges are recorded in realized gain (loss) on derivative instruments in the consolidated statements of operations. See Note 7 for further information on derivative instruments.
Nonrecurring Fair Value Measurements
Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances, such as when there is evidence of impairment. Assets and liabilities acquired in business combinations are recorded at their fair value as of the date of acquisition. Refer to Note 3 for the fair values of assets acquired and liabilities assumed in connection with the Superior, Missouri, TruSouth, Royal Purple and Montana Acquisitions.
The Company reviews for goodwill impairment annually on October 1 and whenever events or changes in circumstances indicate its carrying value may not be recoverable. The fair value of the reporting units is determined using the income approach. The income approach focuses on the income-producing capability of an asset, measuring the current value of the asset by calculating the present value of its future economic benefits such as cash earnings, cost savings, corporate tax structure and product offerings. Value indications are developed by discounting expected cash flows to their present value at a rate of return that incorporates the risk-free rate for the use of funds, the expected rate of inflation and risks associated with the reporting unit. These assets would generally be classified within Level 3, in the event that the Company were required to measure and record such assets at fair value within its consolidated financial statements. See Note 4 for further information on goodwill.
The Company periodically evaluates the carrying value of long-lived assets to be held and used, including definite-lived and indefinite-lived intangible assets and property plant and equipment, when events or circumstances warrant such a review. Fair value is determined primarily using anticipated cash flows assumed by a market participant discounted at a rate commensurate with the risk involved and these assets would generally be classified within Level 3, in the event that the Company were required to measure and record such assets at fair value within its consolidated financial statements. See Note 4 for further information on long-lived assets.
Estimated Fair Value of Financial Instruments
Cash
The carrying values of cash are considered to be representative of their respective fair values.
Debt
The estimated fair value of long-term debt at December 31, 2012 consists primarily of the 2019 Notes and 2020 Notes. The estimated fair value of long-term debt at December 31, 2011 consists primarily of the 2019 Notes. The fair values of the Company’s 2019 Notes were based upon using quoted market prices in an active market and are classified as Level 1. The fair values of the Company’s 2020 Notes were based upon directly observable inputs and are classified as Level 2. The carrying value of borrowings, if any, under the Company’s revolving credit facility approximates its fair value as determined by discounted cash flows and is classified as Level 3. Capital lease obligations approximate their fair values as determined by discounted cash flows and are classified as Level 3. See Note 6 for further information on long-term debt.
The Company’s carrying and estimated fair value of the Company’s financial instruments, carried at adjusted historical cost, at December 31, 2012 and December 31, 2011 were as follows:
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
9.
Partners’ Capital
In February 2011, the Company satisfied the last of the earnings and distributions tests contained in its 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.
On February 24, 2011, the Company completed a public offering of its common units in which it sold 4,500,000 common units to the underwriters of the offering at a price to the public of $21.45 per common unit. The proceeds received by the Company from this offering (net of underwriting discounts, commissions and expenses but before its general partner’s capital contribution) were $92,290 and were used to repay borrowings under its revolving credit facility. Underwriting discounts totaled $3,915. The Company’s general partner contributed $1,970 to retain its 2% general partner interest.
On September 8, 2011, the Company completed a public offering of its common units in which it sold 11,000,000 common units to the underwriters of the offering at a price to the public of $18.00 per common unit. The proceeds received by the Company from this offering (net of underwriting discounts, commissions and expenses but before its general partner’s capital contribution) were $189,497 and were used to fund a portion of the purchase price of the Superior Acquisition. Underwriting discounts totaled $7,866. The Company’s general partner contributed $4,041 to retain its 2% general partner interest. See Note 3 for further information on the Superior Acquisition.
On October 13, 2011, the underwriters of the Company’s September 8, 2011 public offering elected to exercise a portion of their overallotment option. As a result, the Company sold an additional 750,000 common units to the underwriters at a price to the public of $18.00 per unit. The proceeds received by the Company from this offering (net of underwriting discounts, commissions and expenses but before its general partner’s capital contribution) were $12,915 and were used to repay borrowings under its revolving credit facility. Underwriting discounts totaled $540. The Company’s general partner contributed $275 to retain its 2% general partner interest.
On May 8, 2012, the Company completed a public offering of its common units in which it sold 6,000,000 common units to the underwriters of the offering at a price to the public of $25.50 per common unit. The proceeds received by the Company from this offering (net of underwriting discounts, commissions and expenses but before its general partner’s capital contribution) were $146,558 and were used to repay borrowings under its revolving credit facility. Underwriting discounts totaled $6,180. The Company’s general partner contributed $3,122 to maintain its 2% general partner interest.
Of the 57,529,778 common units outstanding at December 31, 2012, 39,397,092 common units were held by the public, with the remaining 18,132,686 common units held by the Company’s affiliates.
Significant information regarding rights of the limited partners includes the following:
•
Rights to receive distributions of available cash within 45 days after the end of each quarter, to the extent the Company has sufficient cash from operations after the establishment of cash reserves.
•
Limited partners have limited voting rights on matters affecting the Company’s business. The general partner may consider only the interests and factors that it desires, and has no duty or obligation to give any consideration of any interests of, the Company’s limited partners. Limited partners have no right to elect the board of directors of the Company’s general partner.
•
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. Any holder, other than the general partner or the general partner’s affiliates, that owns 20% or more of any class of units outstanding, cannot vote on any matter.
•
The Company may issue an unlimited number of limited partner interests without the approval of the limited partners.
•
Limited partners may be required to sell their units to the general partner if at any time the general partner owns more than 80% of the issued and outstanding common units.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
The Company’s general partner is entitled to incentive distributions if the amount it distributes to unitholders with respect to any quarter exceeds specified target levels shown below:
The Company’s ability to make distributions is limited by its debt instruments. The revolving credit facility generally permits the Company to make cash distributions to unitholders as long as immediately after giving effect to such a cash distribution the Company has availability under the revolving credit facility at least equal to the greater of (i) 15% 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 facility commitments then in effect and (ii) $45,000. The indentures governing the 2019 Notes and 2020 Notes provide that if the Company’s fixed charge coverage ratio (as defined in the indentures) for the most recently ended four full fiscal quarters is not less than 1.75 to 1.0, the Company will be permitted to pay distributions to its unitholders in an amount equal to available cash from operating surplus (each as defined in the Company’s partnership agreement) with respect to its preceding fiscal quarter, subject to certain customary adjustments described in the indentures. If the Company’s fixed charge coverage ratio is less than 1.75 to 1.0, the Company will be able to pay distributions to its unitholders up to an amount equal to (i) a $70,000 basket for the 2019 Notes and (ii) a $120,000 for the 2020 Notes, subject to certain customary adjustments described in the indentures.
The Company’s distribution policy is as defined in its partnership agreement. For the years ended December 31, 2012, 2011 and 2010, the Company made distributions of $132,400, $82,743 and $65,739, respectively, to its partners. For the years ended December 31, 2012, 2011 and 2010, the general partner was allocated $5,433, $322 and $0, respectively, in incentive distribution rights.
10.
Unit-Based Compensation
The Company’s general partner originally adopted a Long-Term Incentive Plan (the “Plan”) on January 24, 2006, which was amended and restated effective January 22, 2009, for its employees, consultants and directors and its affiliates who perform services for the Company. The Plan provides for the grant of restricted units, phantom units, unit options and substitute awards and, with respect to unit options and phantom units, the grant of distribution equivalent rights (“DERs”). Subject to adjustment for certain events, an aggregate of 783,960 common units may be delivered pursuant to awards under the Plan. Units withheld to satisfy the Company’s general partner’s tax withholding obligations are available for delivery pursuant to other awards. The Plan is administered by the compensation committee of the Company’s general partner’s board of directors.
Non-employee directors of the Company’s general partner have been granted phantom units under the terms of the Plan as part of their director compensation package related to fiscal years 2010, 2011 and 2012. These phantom units have a four year service period with one-quarter of the phantom units vesting annually on each December 31 of the vesting period. Although ownership of common units related to the vesting of such phantom units does not transfer to the recipients until the phantom units vest, the recipients have DERs on these phantom units from the date of grant.
For the years ended December 31, 2012 and 2011, named executive officers and certain employees were awarded phantom units under the terms of the Plan, as part of the Company’s achievement of specified levels of financial performance in the fiscal year. These phantom units are subject to time-vesting requirements whereby 25% of the units vest during the performance period, and the remainder will vest ratably over the next three years on each December 31. Although ownership of common units related to the vesting of such phantom units does not transfer to the recipients until the phantom units vest, the recipients have DERs on these phantom units from the date of grant.
The Company uses the market price of its common units on the grant date to calculate the fair value and related compensation cost of the phantom units. The Company amortizes this compensation cost to partners’ capital and general and administrative expense in the consolidated statements of operations using the straight-line method over the service period, as it expects these units to fully vest.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
Liability Awards are awards that are expected to be settled in cash on their vesting dates, rather than in equity units. Phantom unit Liability Awards are recorded in accrued salaries, wages and benefits in the consolidated balance sheets based on the vested portion of the fair value of the awards on the balance sheet date. The fair value of Liability Awards are updated at each balance sheet date and changes in the fair values of the vested portions of the awards are recorded as increases or decreases to compensation expense within general and administrative expense in the consolidated statements of operations.
A summary of the Company’s nonvested phantom units as of December 31, 2012, and the changes during the years ended December 31, 2012, 2011 and 2010, are presented below:
For the years ended December 31, 2012, 2011 and 2010, compensation expense of $4,583, $3,027 and $784, respectively, was recognized in the consolidated statements of operations related to vested phantom unit grants, including $2,239 attributable to Liability Awards for the year ended December 31, 2012. As of December 31, 2012 and 2011, there was a total of $23,044 and $11,124, respectively of unrecognized compensation costs related to nonvested phantom unit grants, including $16,139 attributable to Liability Awards for the year ended December 31, 2012. These costs are expected to be recognized over a weighted-average period of approximately three years. The total fair value of phantom units vested during the years ended December 31, 2012 and 2011, was $6,083 and $3,727, respectively.
11.
Employee Benefit Plans
The Company has two domestic defined contribution plans administered by its general partner for (i) all full-time employees that are eligible to participate in the plan (“Calumet 401k Plan”) and (ii) all Montana union employees that are eligible to participate in the plan (“Montana 401k Plan”). Participants in the Calumet 401k Plan are allowed to contribute 0% to 70% of their pre-tax earnings to the plan, subject to government imposed limitations. The Company matches 100% of each 1% of eligible compensation contribution by the participant up to 4% and 50% of each additional 1% eligible compensation contribution up to 6%, for a maximum contribution by the Company of 5% of eligible compensation contributions per participant. Participants in the Montana 401k Plan are allowed to contribute pre-tax earnings to the plan, subject to government imposed limitations. The Company matches 100% of each 1% contribution by the participant up to 6% for a maximum contribution. The Company’s matching contributions expenses were $3,224, $2,343 and $1,948 for 2012, 2011 and 2010, respectively. The plans also include a profit-sharing component for eligible employees. Contributions under the profit-sharing component are determined by the board of directors of the Company’s general partner and are discretionary. The Company’s profit sharing contribution expenses were $2,511, $1,448 and $1,331 for 2012, 2011 and 2010, respectively.
The Company has domestic noncontributory defined benefit plans for those salaried employees as well as those employees represented by either the United Steelworkers (“USW”) or the International Union of Operating Engineers (“IUOE”); who (i) were formerly employees of Penreco and became employees of the Company as a result of the acquisition of Penreco on January 3, 2008 (“Penreco Pension Plan”), (ii) were formerly employees of Murphy Oil Corporation and who became employees of the Company as a result of the Superior Acquisition on September 30, 2011 (the “Superior Pension Plan” and together with the Penreco Pension Plan, the “Pension Plan”) or (iii) were former employees of Montana Refining
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
Company, Inc. and who became employees of the Company as a result of the Montana Acquisition on October 1, 2012 (the “Montana Pension Plan” and together with the Penreco Pension Plan and the Superior Pension Plan, the “Pension Plan”).
Under the Penreco Pension Plan and Superior Pension Plan benefits are based primarily on years of service for USW and IUOE represented employees and the employee’s final 60 months’ average compensation for salaried employees. Under the Montana Pension plan benefits are based primarily on years of service and the employees’ 36 months’ highest average compensation for salaried employees. The funding policy is consistent with funding requirements of applicable laws and regulations. The assets of these plans consist of equity securities, foreign equity securities, fixed income, a balanced fund, a commingled fund and cash and cash equivalents.
The Company also has domestic contributory defined benefit post retirement medical plans and contributory life insurance plans for (i) those salaried employees, as well as those employees represented by either the International Brotherhood of Teamsters (“IBT”), USW or IUOE, who were formerly employees of Penreco and who became employees of the Company as a result of the acquisition of Penreco on January 3, 2008 (“Penreco Other Plan”) or (ii) employees represented by the IUOE, who were formerly employees of Murphy Oil Corporation and who became employees of the Company as a result of the Superior Acquisition on September 30, 2011 (“Superior Other Plan”) and together with the Penreco Other Plan, the “Other Plan.”
In 2009, the Company amended the Penreco Pension Plan, which curtailed Penreco employees from accumulating additional benefits subsequent to December 31, 2009.
Effective July 1, 2012, the Company amended the Superior Pension Plan and Superior Other Plan, which curtailed Superior employees from accumulating additional benefits subsequent to December 31, 2012. For the year ended December 31, 2012, the Company recorded a $218 curtailment gain related to the Superior Pension Plan and a $6,983 curtailment gain related to the Superior Other Plan, all of which is recorded in general and administrative expense in the consolidated statements of operations. All information presented below has been adjusted for this curtailment.
Effective October 1, 2012, the date of the Montana Acquisition, the Company amended the Montana Pension Plan, which curtailed only the Montana salaried employees from accumulating additional benefits subsequent to October 31, 2012. All information presented below has been adjusted for these curtailments.
During 2012, the Company made contributions of $3,076 to its Pension Plan and $29 to its Other Plan. The Company expects to make contributions in 2013 of approximately $4,402 to its Pension Plan and $59 to its Other Plan.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
The change in the benefit obligations, change in the plan assets, funded status and amounts recognized in the consolidated balance sheets were as follows:
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
The accumulated benefit obligation for the Pension Plan was $63,429 and $52,543 as of December 31, 2012 and 2011, respectively. The accumulated benefit obligation for the Pension Plan was more than plan assets by $21,863 and $16,501 as of December 31, 2012 and 2011, respectively. Selected information for the Company’s Pension Plan with an accumulated benefit obligation in excess of plan assets were as follows:
The components of net periodic pension cost and other post retirement benefits cost 2012, 2011 and 2010 were as follows:
The components of changes recognized in other comprehensive income for the Pension Plan and Other Plan for 2012, 2011 and 2010 were as follows:
The portion relating to the Pension Plan and Other Plan classified in accumulated other comprehensive loss is $11,526 and $8,567 as of December 31, 2012 and 2011, respectively. In 2013, the estimated amount that will be amortized from accumulated other comprehensive income includes a loss of $817 for the Pension Plan. Also in 2013, the estimated amounts
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
that will be amortized from accumulated other comprehensive income include a gain of $8 and prior service credit of $35 for the Other Plan.
All pension and other post retirement plans have a December 31 measurement date. The significant weighted average assumptions used to determine the benefit obligations for the years ended December 31, 2012 and 2011 were as follows:
(1)
For measurement purposes, an annual rate of increase in the per capita cost of covered health care benefits was assumed for 2012. The rate was assumed to decrease by 0.20% per year for an ultimate rate of 4.50% in 2029 for the Penreco Other Plan and remain at that level thereafter.
(2)
For measurement purposes, an annual rate of increase in the per capita cost of covered health care benefits was assumed for 2011. The rate was assumed to decrease by 0.20% per year for an ultimate rate of 4.50% in 2029 for the Superior Other Plan and remain at that level thereafter. Effective July 1, 2012, the Company amended the Superior Other Plan, which curtailed Superior employees from accumulating additional benefits subsequent to December 31, 2012.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
The significant weighted average assumptions used to determine the net periodic benefit cost for the years ended December 31, 2012 and 2011 were as follows:
(1)
The Company considered the historical returns and the future expectation for returns for each asset class, as well as the target asset allocation of the Pension Plan portfolio, to develop the expected long-term rate of return on plan assets.
(2)
For measurement purposes, an annual rate of increase in the per capita cost of covered health care benefits was assumed for 2012. The rate was assumed to decrease by 0.20% per year for an ultimate rate of 4.50% for 2029 for the Penreco Other Plan and Superior Other Plan and remain at that level thereafter.
An increase or decrease by one percentage point in the assumed healthcare cost trend rates would have the following effect on the post retirement benefit obligation and service and interest cost components of benefit costs for the Other Plan as of December 31, 2012:
Investment Policy
The Company’s Pension Plan investment policy is set with specific consideration of returns and risk requirements in relationship to the respective liabilities. Given the long term nature of the Company’s liabilities, the Pension Plan has the flexibility to manage a moderate level of risk. At the investment policy level, there are no specifically prohibited investments. However, within individual investment manager mandates, restrictions and limitations are contractually set to align with the Company’s investment objectives, ensure risk control, and limit concentrations.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
The Company manages the portfolio to minimize any concentration of risk by allocating funds within asset categories. In addition, within a category the Company uses different managers with various management objectives to eliminate any significant concentration of risk. Management believes there are no significant concentrations of risks associated with the investment assets.
The Pension Plan’s asset allocation strategy is currently comprised of the following:
Trust assets will be invested in accordance with prudent expert standards as mandated by the Employee Retirement Income Security Act (“ERISA”). In the event market environments create asset exposures outside of the policy guidelines, reallocations will be made in an orderly manner to rebalance the investments and maximize the effectiveness of the Pension Plan asset allocation strategy. The Company’s investment consultant will assist in the continual assessment of assets and the potential reallocation of certain investments and will evaluate the selection of investment managers for the Pension Plan based on such factors as organizational stability, depth of resources, experience, investment strategy and process, performance expectations and fees.
The Company’s Pension Plan asset allocations, as of December 31, 2012 and 2011 by asset category, are as follows:
(1)
The Superior Pension Plan assets are included in cash and cash equivalents and such assets will be invested in 2013 based upon the current investment policy.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
The Company’s investments associated with its Pension Plan primarily consist of (i) cash and cash equivalents, (ii) mutual funds that are publicly traded, (iii) a commingled fund and (iv) a balanced fund. The mutual and balanced funds are publicly traded and market prices of the mutual funds are readily available, thus these investments are categorized as Level 1. The commingled fund is categorized as Level 2 because inputs used in its valuation are not quoted prices in active markets that are indirectly observable and is valued at the net asset value of the shares held by the Pension Plan at year end. See Note 8 for the definition of Levels 1, 2 and 3. The Company’s Pension Plan assets measured at fair value at December 31, 2012 and 2011 were as follows:
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid in the years indicated as of December 31, 2012:
12.
Earnings per Unit
The following table sets forth the computation of basic and diluted earnings per limited partner unit for the years ended December 31, 2012, 2011 and 2010:
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
13.
Transactions with Related Parties
During the years ended December 31, 2012, 2011 and 2010, the Company had product sales to related parties owned by a limited partner of $9,309, $16,500 and $4,727, respectively. Trade accounts and other receivables from related parties at December 31, 2012 and 2011 were $139 and $1,818, respectively. The Company also had purchases from related parties owned by a limited partner, excluding crude purchases related to the Legacy Resources Co., L.P. (“Legacy Resources”) and director’s and officers’ liability insurance premiums discussed below, during the years ended December 31, 2012, 2011 and 2010 of $7,181, $1,768 and $1,480, respectively. Accounts payable to related parties, excluding accounts payable related to the Legacy Resources agreements discussed below, at December 31, 2012 and 2011 were $2,230 and $1,393, respectively.
Legacy Resources is owned in part by one of the Company’s limited partners, an affiliate of the Company’s general partner, the Company’s chief executive officer and vice chairman of the board of the Company’s general partner, F. William Grube, and the Company’s president and chief operating officer, Jennifer G. Straumins.
From May 2008 to May 2011, the Company purchased all of its crude oil requirements for its Princeton refinery on a just in time basis utilizing a market-based pricing mechanism from Legacy Resources (the “Legacy Princeton Agreement”). In addition, in January 2009, the Company entered into an agreement with Legacy Resources to begin purchasing certain of its crude oil requirements for its Shreveport refinery utilizing a market-based pricing mechanism from Legacy Resources (the “Master Crude Oil Purchase and Sale Agreement”). In September 2009, the Company entered into a crude oil supply agreement with Legacy Resources (the “Legacy Shreveport Agreement”). Under the Legacy Shreveport Agreement, Legacy Resources supplied the Company’s Shreveport refinery with a portion of its crude oil requirements on a just in time basis utilizing a market-based pricing mechanism.
On May 31, 2011, the Company terminated the Legacy Princeton Agreement and the Legacy Shreveport Agreement and did not incur any material early termination penalties in connection with their termination. With the termination of these agreements, the Company has one remaining crude oil supply agreement with Legacy Resources, the Master Crude Oil Purchase and Sale Agreement. No crude oil is currently being purchased by the Company under this agreement. During the years ended December 31, 2012 and 2011 and 2010, the Company had crude oil purchases of $1,120, $229,793 and $591,777, respectively, from Legacy Resources. Accounts payable to Legacy Resources at December 31, 2012 and 2011 were $96 and $574, respectively.
Nicholas J. Rutigliano, a member of the board of directors of the Company’s general partner, founded and is the president of Tobias Insurance Group, Inc. (“Tobias”), a commercial insurance brokerage business that has historically placed the Company’s directors’ and officers’ liability insurance. The total premiums paid to Tobias by the Company for the years ended December 31, 2012, 2011 and 2010 were $510, $566 and $638, respectively. With the exception of its directors’ and officers’ liability insurance which were placed with this commercial insurance brokerage company, the Company placed its insurance requirements with third parties during the years ended December 31, 2012, 2011 and 2010.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
14.
Segments and Related Information
a. Segment Reporting
The Company has two reportable segments: specialty products and fuel products. The specialty products segment produces a variety of lubricating oils, solvents, waxes, synthetic lubricants, asphalt and other by-products. These products are sold to customers who purchase these products primarily as raw material components for basic automotive, industrial and consumer goods. The specialty products segment also blends and markets through the Company’s brand Royal Purple. The fuel products segment produces a variety of fuel and fuel-related products including gasoline, diesel, jet fuel and heavy fuel oils. The Company sells the majority of the fuel products it produces to markets located in Arkansas, Canada, Idaho, Iowa, Louisiana, Michigan, Minnesota, Montana, North Dakota, South Dakota, Texas and Wisconsin. The Company also has the ability to ship additional fuel products to the Midwest region and the northern states bordering Canada through the TEPPCO and Magellan pipelines should the need arise. The assets and results of the operations from such assets acquired as a result of the Superior and Montana Acquisitions have been included since the date of acquisition, September 30, 2011 and October 1, 2012, respectively. The assets and results of operations from such assets acquired as a result of the Missouri, TruSouth and Royal Purple Acquisitions have been included in the specialty products segment since their dates of acquisition, January 3, 2012, January 6, 2012 and July 3, 2012, respectively.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
The accounting policies of the segments are the same as those described in the summary of significant accounting policies in Note 2. The Company evaluates segment performance based on income from operations. The Company accounts for intersegment sales and transfers at cost plus a specified mark-up. Reportable segment information is as follows:
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
b. Geographic Information
International sales accounted for less than 10% of consolidated sales in each of the three years ended December 31, 2012, 2011 and 2010. All of the Company’s long-lived assets are domestically located.
c. Product Information
The Company offers specialty products primarily in six general categories consisting of lubricating oils, solvents, waxes, packaged and synthetic specialty products, fuels and asphalt and other by-products. Fuel products primarily consist of gasoline, diesel, jet fuel and heavy fuel oils and other. The following table sets forth the major product category sales:
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
d. Major Customers
During the years ended December 31, 2012, 2011 and 2010, the Company had no customer that represented 10% or greater of consolidated sales.
15.
Quarterly Financial Data (Unaudited)
(1)
The sum of the four quarters may not equal the total year due to rounding.
16.
Subsequent Events
On January 2, 2013, The Company completed the acquisition of NuStar Energy L.P.’s San Antonio, Texas refinery, together with related assets and the assumption of certain liabilities and obligations (the “San Antonio Acquisition”). The refinery has total crude oil throughput capacity of 14,500 bpd and primarily produces jet fuel, diesel, other fuel products and specialty solvents. Total consideration for the San Antonio Acquisition was approximately $115,694, including approximately $15,000 for inventories acquired at closing, subject to certain post-closing adjustments. The San Antonio Acquisition was funded with borrowings under the Company’s revolving credit facility with the balance through cash on hand. The San Antonio Acquisition purchase price allocation has not yet been finalized due to the timing of the closing of the acquisition. The final determination of fair value for certain assets and liabilities will be completed as soon as the information necessary to complete the analysis is obtained.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands, except per unit data)
On January 8, 2013, the Company completed a public offering of its common units in which it sold 5,750,000 common units, including the overallotment option of 750,000 common units, to the underwriters of the offering at a price to the public of $31.81 per common unit. The proceeds received by the Company from this offering (net of underwriting discounts, commissions and expenses but before its general partner’s capital contribution) were $175,248 and were used to repay borrowings under its revolving credit facility and for general partnership purposes. Underwriting discounts totaled $7,360. The Company’s general partner contributed $3,733 to maintain its 2% general partner interest.
On January 14, 2013, the Company declared a quarterly cash distribution of $0.65 per unit on all outstanding common units, or approximately $44,540 (including the general partner’s incentive distribution rights) in aggregate, for the quarter ended December 31, 2012. The distribution was paid on February 14, 2013 to unitholders of record as of the close of business on February 4, 2013. This quarterly distribution of $0.65 per unit equates to $2.60 per unit, or approximately $178,160 (including the general partner’s incentive distribution rights) in aggregate on an annualized basis.
On February 7, 2013, the Company entered into a joint venture agreement with MDU Resources Group, Inc. (“MDU”) to develop, build and operate a diesel refinery in southwestern North Dakota. The joint venture will be called Dakota Prairie Refining, LLC. Funding for the project will occur over the course of the construction period, with the majority of the direct funding by the Company expected in 2014. The joint venture will allocate profits on a 50%/50% basis to the Company and MDU. The joint venture will be governed by a board of managers comprised of representatives from both the Company and MDU. MDU will provide a portion of the crude oil supply to the refinery, as well as natural gas and electricity utility services. The Company will provide refinery operations, crude oil procurement and refined product marketing expertise to the joint venture.
The fair value of the Company’s derivatives decreased by approximately $24,000 subsequent to December 31, 2012 to a net liability of approximately $69,000. The fair value of the Company’s long-term debt, excluding capital leases, has increased by approximately $20,000 subsequent to December 31, 2012.
Item 9.
Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A.
Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2012 at the reasonable assurance level. See Management’s Report on Internal Control Over Financial Reporting included in Item 8 “Financial Statements and Supplementary Data.”
Changes in Internal Control over Financial Reporting
There have been no changes to our internal controls over financial reporting during the fourth quarter of fiscal year 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
On January 3, 2012, January 6, 2012, July 3, 2012, October 1, 2012 and January 2, 2013, we completed the Missouri, TruSouth, Royal Purple, Montana and San Antonio Acquisitions, respectively, which include certain existing information systems and internal controls over financial reporting that previously existed. In conducting our evaluation of effectiveness of our internal control over financial reporting, we have elected to exclude the Missouri, TruSouth, Royal Purple, Montana and San Antonio Acquisitions from our evaluation, as permitted under existing SEC rules. We are currently in the process of evaluating and integrating the Missouri, TruSouth, Royal Purple, Montana and San Antonio Acquisitions’ historical internal controls over financial reporting with ours. We expect to complete the integration of Missouri, TruSouth, Royal Purple and Montana in fiscal year 2013 and the integration of San Antonio in fiscal year 2014.
On January 1, 2013, the Company implemented an enterprise resource planning (“ERP”) system on a company-wide basis, which is expected to improve the efficiency of certain financial and related transaction processes. The implementation of a company-wide ERP system will affect the processes that constitute our internal control over financial reporting and will require testing for effectiveness.
See Management’s Report on Internal Control Over Financial Reporting included in Item 8 “Financial Statements and Supplemental Data.”
Item 9B.
Item 9B.
Other Information
None.
PART III
Item 10.
Item 10.
Directors, Executive Officers of Our General Partner and Corporate Governance
Management of Calumet Specialty Products Partners, L.P. and Director Independence
Our general partner, Calumet GP, LLC, manages our operations and activities. Unitholders are limited partners and are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operations. Our general partner owes a fiduciary duty to our unitholders, as limited by the various provisions of our partnership agreement modifying and restricting the fiduciary duties that might otherwise be owed by our general partner to our unitholders.
The directors of our general partner oversee our operations. The owners of our general partner have appointed seven members to our general partner’s board of directors. The directors of our general partner are generally elected by a majority vote of the owners of our general partner on an annual basis. However, as long as our chief executive officer and vice chairman of our general partner, F. William Grube, or trusts established for the benefit of his family members, continue to own at least 30% of the membership interests in our general partner, Mr. Grube (or in certain specified instances, his designee or transferee) has the right to serve as a director of our general partner. The directors of our general partner hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified.
Pursuant to Section 4360 of the NASDAQ Stock Market, LLC Marketplace Rules (“NASDAQ Rules”), a listed limited partnership like us is not required to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating/governance committee. However, three of our general partner’s seven directors are “independent” as that term is defined in the NASDAQ Rules and Rule 10A-3 of the Exchange Act. In determining the independence of each director, our general partner has adopted standards that incorporate the NASDAQ Rules and Exchange Act standards. Our general partner’s independent directors as determined in accordance with those standards are: James S. Carter, Robert E. Funk and George C. Morris III.
The officers of our general partner manage the day-to-day affairs of our business. Officers serve at the discretion of the board of directors.
Directors and Executive Officers
The following table shows information regarding the directors and executive officers of Calumet GP, LLC as of March 1, 2013.
Each director’s biographical information set forth below includes the particular experience and qualifications that led the board of directors to conclude that the director is qualified to serve in such capacity.
Fred M. Fehsenfeld, Jr. has served as the chairman of the board of our general partner since September 2005. Mr. Fehsenfeld also served as the vice chairman of the board of our Predecessor from 1990 until our initial public offering. Mr. Fehsenfeld has worked for The Heritage Group in various capacities since 1977 and has served as its managing trustee since 1980. Mr. Fehsenfeld received his B.S. in Mechanical Engineering from Duke University and his M.S. in Management from the Massachusetts Institute of Technology Sloan School.
As co-founder of our Predecessor, Mr. Fehsenfeld has an extensive knowledge base regarding the Company’s operations and has participated in all major strategic decision making for the Company and our Predecessor since their inception. In his role as managing trustee of The Heritage Group, Mr. Fehsenfeld serves in lead executive roles, including the role of chairman and chief executive officer, for a multitude of different companies within The Heritage Group, providing breadth of experience in leadership and management across a wide variety of industries, including energy. Since 2008, Mr. Fehsenfeld has served as chairman of the board of directors of Heritage-Crystal Clean, Inc., a publicly-traded environmental services company which is owned in part by The Heritage Group.
F. William Grube has served as the chief executive officer and vice chairman of the board of our general partner since January 2011. From September 2005 through December 2010, Mr. Grube served as chief executive officer, president and director of our general partner. Mr. Grube has also served as president and chief executive officer of our Predecessor from 1990 until our initial public offering. From 1973 to 1989, Mr. Grube served as executive vice president of Rock Island Refining Corporation. Mr. Grube received his B.S. in Chemical Engineering from Rose-Hulman Institute of Technology and his M.B.A. from Harvard University. Mr. Grube is the father of Jennifer G. Straumins, president and chief operating officer of our general partner.
As co-founder of our Predecessor and through his role as the chief executive officer since inception, Mr. Grube possesses unique experience relative to the management of the Company on a day-to-day basis over a significant time period and across all functional areas of the Company. Mr. Grube has significant technical expertise in refining developed over the course of his career, with both the Company and our Predecessor, as well as another refining company which specialized in the production of fuel products.
Jennifer G. Straumins has served as president and chief operating officer of our general partner since January 2011. From December 2009 through December 2010, Ms. Straumins served as executive vice president and chief operating officer of our general partner. From February 2007 through December 2009, Ms. Straumins served as senior vice president of our general partner. From January 2006 through February 2007, Ms. Straumins served as vice president - investor relations of our general partner. Ms. Straumins served in various capacities in financial planning and economics for our Predecessor from 2002 until our initial public offering. Prior to joining our Predecessor, Ms. Straumins held financial planning positions with Great Lakes Chemical Company and Exxon Chemical Company. Ms. Straumins received a B.E. in Chemical Engineering from Vanderbilt University and her M.B.A. from the University of Kansas. Ms. Straumins is the daughter of F. William Grube, the chief executive officer and vice chairman of the board of our general partner.
R. Patrick Murray, II has served as senior vice president, chief financial officer and secretary of our general partner since January 2013. From September 2005 through December 2012, Mr. Murray served as vice president, chief financial officer and secretary of our general partner. Mr. Murray served as the vice president and chief financial officer of our Predecessor from 1999 until our initial public offering and served as its controller from 1998 to 1999. From 1993 to 1998, Mr. Murray was a senior auditor with Arthur Andersen LLP. Mr. Murray received his B.B.A. in Accountancy from the University of Notre Dame.
Timothy R. Barnhart has served as senior vice president - operations of our general partner since January 2013. From December 2009 to December 2012, Mr. Barnhart served as vice president - operations of our general partner. Mr. Barnhart served as the plant manager of our Karns City facility from January 2008 to December 2009. Prior to joining Calumet in 2008 upon our acquisition of Penreco, Mr. Barnhart held various engineering, supervisory and management positions at Penreco and Pennzoil Products Company since 1981. Mr. Barnhart received his B.S. in Engineering from Grove City College.
James S. Carter has served as a member of the board of directors of our general partner since January 2006. Mr. Carter served as U.S. regional director of Exxon Mobil Fuels Company, the fuels subsidiary of Exxon Mobil Corporation, from 1999 until his retirement in 2003. Mr. Carter received his B.S. in Mechanical Engineering from Clemson University and his M.B.A. in Finance and Accounting from Tulane University.
Mr. Carter brings extensive marketing and managerial experience with one of the largest integrated energy companies in the world. He possesses a broad background in petroleum products marketing, with specific experience in the marketing of fuel products.
William S. Fehsenfeld has served as a member of the board of directors of our general partner since January 2006. Mr. Fehsenfeld is chairman of the board and has served as an officer of Schuler Books, Inc., the independent bookstore company he founded with his wife, since 1982. He has also served as a trustee of The Heritage Group from 2003 to the present. Mr. Fehsenfeld received his B.G.S. from the University of Michigan and his M.B.A. from Grand Valley State University. He is also a first cousin of the chairman of the board of our general partner, Fred M. Fehsenfeld, Jr.
In his role as a trustee of The Heritage Group, which held the controlling interest in our Predecessor, Mr. Fehsenfeld has extensive knowledge of the Company and its operations over time and has been involved in strategic decision making for the
Company during his tenure. His role as a trustee of The Heritage Group provides significant breadth of oversight experience of a multitude of companies across various industry sectors, including energy. As a founder and owner of a successful independent bookselling business, Mr. Fehsenfeld also brings executive management and entrepreneurial skills to the board of directors.
Robert E. Funk has served as a member of the board of directors of our general partner since January 2006. Mr. Funk previously served as vice president-corporate planning and economics of CITGO Petroleum Corporation, a refiner and marketer of transportation fuels, lubricants, petrochemicals, refined waxes, asphalt and other industrial products, from 1997 until his retirement in December 2004. Mr. Funk previously served CITGO or its predecessor, Cities Services Company, as general manager-facilities planning from 1988 to 1997, general manager-lubricants operations from 1983 to 1988 and manager-refinery east, Lake Charles refinery from 1982 to 1983. Mr. Funk received his B.S. in Chemical Engineering from the University of Kansas.
Mr. Funk has extensive refining industry experience including planning, operations and managerial roles for a large multinational refining company. His broad background of experience provides helpful insight to the Company in its implementation of strategic initiatives and its refinery operations in general.
George C. Morris III has served as a member of the board of directors of our general partner since May 2009. Mr. Morris has served as president of Morris Energy Advisors, Inc. since March 2009 and most recently served as a managing director at Merrill Lynch & Co. from December 2006 until his retirement in March 2009. Mr. Morris served as a managing director of investment banking at Petrie Parkman & Co. until its acquisition by Merrill Lynch in December 2006 and also served as a managing director of investment banking at Simmons & Company International and as a director of investment banking at First Boston Corporation. Mr. Morris holds B.B.A. and M.B.A. degrees from the University of Texas and a J.D. from Southern Methodist University. Mr. Morris is also a member of the board of directors of Arch Coal, Inc., a public company which produces thermal and metallurgical coal from surface and underground mines.
Mr. Morris’ long tenure in the investment banking industry with a focus on the energy sector provides unique breadth of experience to the board of directors in areas of finance and capital markets. In his role as a financial advisor to the Company prior to joining the board of directors, Mr. Morris gained significant insight into the Company’s operations and strategy.
Nicholas J. Rutigliano has served as a member of the board of directors of our general partner since January 2006. Mr. Rutigliano served as president of Tobias Insurance Group, Inc., a commercial insurance brokerage business he founded, since 1973 to 2012 prior to it being acquired by Assured Partners, LLC. Mr. Rutigliano now serves as president of Assured Partners of Indiana, LLC. He has also served as a trustee of The Heritage Group from 1980 to the present and as a trustee of the University of Evansville. Mr. Rutigliano received his B.S. in Business from the University of Evansville. He is also the brother-in-law of the chairman of the board of our general partner, Fred M. Fehsenfeld, Jr.
In his role as a trustee of The Heritage Group, which held the controlling interest in our Predecessor, Mr. Rutigliano has extensive knowledge of the Company and its operations over time and has been involved in strategic decision making for the Company from the inception of the Company’s Predecessor. His role as a trustee of The Heritage Group provides significant breadth of oversight experience of a multitude of companies across various industry sectors, including energy. As the founder and chief executive officer of a successful commercial insurance brokerage business, Mr. Rutigliano brings unique risk management, executive management and entrepreneurial skills to the board of directors.
Board of Directors Committees
Conflicts Committee
Two members of the board of directors of our general partner serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest. The conflicts committee determines if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be owners, officers or employees of our general partner or directors, officers, or employees of its affiliates, and must meet the independence and experience standards established by NASDAQ and the Exchange Act to serve on an audit committee of a board of directors, and certain other requirements. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders. The two independent board members who serve on the conflicts committee are Messrs. James S. Carter and Robert E. Funk. Mr. Carter serves as the chairman of the conflicts committee.
Compensation Committee
The board of directors of our general partner also has a compensation committee which, among other responsibilities, has overall responsibility for evaluating and either approving or recommending to the board of directors the director, chief
executive officer and senior executive compensation plans, policies and programs of the Company. NASDAQ does not require a limited partnership like us to have a compensation committee comprised entirely of independent directors. Accordingly, Messrs. Fred M. Fehsenfeld, Jr. and F. William Grube serve as members of our compensation committee. Mr. Fehsenfeld serves as the chairman of the compensation committee.
The board of directors has adopted a written charter for the compensation committee which defines the scope of the committee’s authority. The committee may form and delegate some or all of its authority to subcommittees comprised of committee members when it deems appropriate. The committee is responsible for reviewing and recommending to the board of directors for its approval the annual salary and other compensation components for the chief executive officer. The committee reviews and makes recommendations to the board of directors for its approval any of the Company’s equity compensation-based plans, including the Long-Term Incentive Plan, or any cash bonus or incentive compensation plans or programs. Also, the committee reviews and approves all annual salary and other compensation arrangements and components for the senior executives of the Company. Further, the compensation committee periodically reviews and makes a recommendation to the board of directors for changes in the compensation of all directors. The committee has the authority to retain and terminate any compensation consultant to assist it in the evaluation of director and senior executive compensation and to obtain independent advice and assistance from internal and external legal, accounting and other advisors.
See Item 11
Item 11.
Executive and Director Compensation
Compensation Discussion and Analysis
Fiscal Year 2012 Financial Performance
In 2012, our named executive officers (listed below) were instrumental in our ability to deliver strong financial results and to grow the company, while making strategic acquisitions that we believe will foster our long-term growth. Under the guidance of our senior executive team, we reported record revenue of $4,657.3 million, a 48.6% increase over the prior year. Other year-over-year financial accomplishments include:
•
Net income increased 378.1% to $205.7 million
•
Increased Adjusted EBITDA 91.7% to $404.6 million
•
Increase Distributable Cash Flow 121.1% to $281.1 million
•
Distributed $132.4 million of cash to unitholders, an increase of 60.0% over 2011
Overview
For purposes of this Compensation Discussion and Analysis and the compensation tables that follow, the names and positions of our named executive officers for the 2012 year were:
•
F. William Grube - Chief Executive Officer and Vice Chairman of the Board
•
Jennifer G. Straumins - President and Chief Operating Officer
•
R. Patrick Murray, II - Vice President and Chief Financial Officer
•
Timothy R. Barnhart - Vice President - Operations
•
William A. Anderson - former Vice President - Sales and Marketing (effective October 5, 2012, our new Vice President - Marketing and New Products)
The compensation committee of the board of directors of our general partner oversees our compensation programs. Our general partner maintains compensation and benefits programs designed to allow us to attract, motivate and retain the best possible employees to manage us, including executive compensation programs designed to reward the achievement of both short-term and long-term goals necessary to promote growth and generate positive unitholder returns. Our general partner’s executive compensation programs are based on a pay-for-performance philosophy, including measurement of our performance against a specified financial target, namely distributable cash flow. Our executive compensation programs include both long-term and short-term compensation elements which, together with base salary and employee benefits, constitute a total compensation package intended to be competitive with similar companies.
Under their collective authority, the compensation committee and the board of directors maintain the right to develop and modify compensation programs and policies as they deem appropriate. Factors they may consider in making decisions to materially increase or decrease compensation include our overall financial performance, our growth over time, our changes in complexity as well as individual executive job scope complexity, individual executive job performance and changes in competitive compensation practices in our defined labor markets. In determining any forms of compensation other than the base salary for the senior executives, or in the case of the chief executive officer the recommendation to the board of directors of the forms of compensation for the chief executive officer, the compensation committee considers our financial performance and relative unitholder return, the value of similar incentive awards to senior executives at comparable companies and the awards given to senior executives in past years.
Financial Performance Metric Used in Compensation Programs
Our primary business objective is to generate cash flows to make distributions to our unitholders. As a result, our distributable cash flow is the primary measurement of performance taken into account in setting policies and making compensation decisions, as we believe this represents the most comprehensive measurement of our ability to generate cash flows. Both short-term and long-term forms of executive compensation are specifically structured on our achievement relative to annual distributable cash flow goals and, as such, determination of related awards, as well as their grant or payment, occurs subsequent to the end of each fiscal year upon final determination of distributable cash flow. We believe that including this financial objective as the primary performance measurement to determine compensation awards for all of our executive officers recognizes the integrated and collaborative effort required by the full executive team to maximize performance. Distributable
cash flow is a non-GAAP measure that we define, consistent with the terms of our revolving credit agreement and senior notes indentures, as our Adjusted EBITDA less replacement capital expenditures, cash interest expense, turnaround costs and income tax expense. Please refer to Part II, Item 6 “Selected Financial Data - Non-GAAP Financial Measures” for our definition of Adjusted EBITDA.
Peer Group and Compensation Targets
To evaluate all areas of executive compensation, the compensation committee seeks the additional input of outside compensation consultants and available comparative information to validate that the compensation programs established for our executives are consistent with the philosophy of compensating our executives at ranges that approximate within 25% of the median of market for companies of similar size to us. In 2011, the compensation committee retained Buck Consultants, LLC (“Buck Consultants”) as an independent consultant to review our general partner’s executive compensation programs. Buck Consultants reported directly to the compensation committee and did not provide any additional services to our general partner. The scope of this engagement included the following:
•
review of a peer group of publicly-traded master limited partnerships for executive compensation comparisons;
•
analysis of market pay levels and trends for our named executive officers, other officers and key employees from peer companies including base salary, annual incentives and long-term incentives; and
•
assessment of Calumet’s executive pay levels relative to overall market levels.
The following master limited partnerships and corporation were included by Buck Consultants in the peer group for the compensation review: Atlas Pipeline Partners, L.P., Boardwalk Pipeline Partners, LP, Buckeye Partners, L.P., Copano Energy, L.L.C., Crosstex Energy, L.P., DCP Midstream Partners, LP, Energy Transfer Partners, L.P., Genesis Energy, L.P., Inergy, L.P., Kinder Morgan Energy Partners, L.P., Magellan Midstream Partners, L.P., MarkWest Energy Partners, L.P., NuStar Energy L.P., ONEOK Partners, L.P., PVR Partners, L.P., Regency Energy Partners LP, Suburban Propane Partners, L.P., Sunoco Logistics Partners L.P., Syntroleum Corporation, Targa Resources Partners LP and Williams Partners, L.P. Peer group companies were validated and selected based on their comparability of EBITDA (a non-GAAP measurement), sales and market capitalization, but also included additional master limited partnerships larger than us in terms of such selection criteria to compare our compensation against a broader peer group given our growth in such selection criteria. Market data compiled from public disclosures of the peer group companies were used in the review to compare our compensation of the key executive group against the market. Buck Consultants provided a presentation of its findings to the compensation committee in October 2011 that assisted us in making the compensation decisions described below for the 2012 year.
The compensation committee used the findings of the Buck Consultants executive compensation review to validate the total competitiveness of compensation for our key executives, including each named executive officer. Specifically, the Buck Consultants review indicated that aggregate target total direct compensation of our key executives, which includes all the major elements of our executive compensation program, including base salary, short-term incentives and long-term compensation, was below the median of market by approximately 25%, driven primarily by long-term compensation as total cash compensation, which includes aggregate base salaries and aggregate short-term incentives for the key executives, assuming the target levels of such incentives are achieved, fall above the median of the expanded peer group by less than 5%. Long-term incentives for the key executives fall below the 25th percentile of the peer group by approximately 25%, which the compensation committee deemed appropriate given our smaller size relative to certain master limited partnerships included in the expanded peer group, with an expectation by the compensation committee that with future achievement of strategic goals and further growth in financial performance, such long-term incentive opportunities should migrate toward the median level of the expanded peer group. Our compensation committee requested that Buck Consultants provide us with a similar presentation in October 2012 to the report that we received in the 2011 year, which we used to assist us in making our compensation decisions for the 2013 year. As of this filing, we have not made any material changes to our compensation program for the 2013 year.
Review of Named Executive Officer Performance
The compensation committee reviews, on an annual basis, each compensation element for a named executive officer. In each case, the compensation committee takes into account the scope of responsibilities and experience and balances these against competitive salary levels. The compensation committee has the opportunity to meet with the named executive officers at various times during the year, which allows the compensation committee to form its own assessment of each individual’s performance.
Objectives of Compensation Programs
Our executive compensation programs are designed with the following primary objectives:
•
reward strong individual performance that drives our positive financial results;
•
make incentive compensation a significant portion of an executive’s total compensation, designed to balance short-term and long-term performance;
•
align the interests of our executives with those of our unitholders; and
•
attract, develop and retain executives with a compensation structure that is competitive with other publicly-traded partnerships of similar size.
Elements of Executive Compensation
The compensation committee believes the total compensation and benefits program for our named executive officers should consist of the following:
•
base salary;
•
annual incentive plan which includes short-term cash awards and also includes an optional deferred compensation element;
•
long-term incentive compensation, including unit-based awards;
•
retirement, health and welfare benefits; and
•
perquisites.
These elements are designed to constitute an integrated executive compensation structure meant to incentivize a high level of individual executive officer performance in line with our financial and operating goals.
Base Salary
Design. Salaries provide executives with a base level of monthly income as consideration for fulfillment of certain roles and responsibilities. The salary program assists us in achieving our objective of attracting and retaining the services of quality individuals who are essential for the growth and profitability of Calumet. Generally, changes in the base salary levels for our named executive officers are determined on an annual basis by the compensation committee of the board of directors and are effective at the beginning of the following fiscal year. In the case of Mr. Grube, his initial base salary was established under his employment agreement, which provides that the amount of his annual salary increase must be at least equal to the average of the percentage increases of all salaried employees of Calumet’s general partner.
Results. Mr. Grube’s salary increase for 2012 was 3.7%, which was equivalent to the average of the percentage increases of all salaried employees for 2012. With respect to our other executive officers, the compensation committee determined to increase the base salaries for our other executive officers by 3.2%, based on the same formula.
Compensation Changes for 2013. Mr. Grube’s salary increase for 2013 was 3.7%, based on the same formula described above. With respect to our other named executive officers, the compensation committee approved increased salaries as part of its annual salary review process. Effective January 1, 2013, the base salaries for Ms. Straumins, Mr. Murray and Mr. Barnhart are $350,000, $320,000 and $300,000, respectively. Due to Mr. Anderson’s change in duties at the end of the 2012 year, we do not expect him to be a named executive officer for the 2013 year. The levels of increases in the base salaries for these executives were based on increased job complexity due to the growth of our business. In addition, in the case of each of Mr. Murray and Mr. Barnhart, the increases take into account their increased job responsibilities resulting from their respective promotions to senior vice president and chief financial officer and senior vice president - operations effective January 1, 2013. The compensation committee also considered the increases to base salary to be appropriate based on comparisons against our peer group of publicly traded partnerships in an effort to ensure that base salaries were closer to the market median of our peer group.
Short-Term Cash Awards
Design. Under the Cash Incentive Compensation Plan (the “Cash Incentive Plan”), short-term cash awards are designed to aid us in retaining and motivating executives to assist us in meeting our financial performance objectives on an annual basis. Short-term cash awards are granted to named executive officers and certain other management employees based on our achievement of performance targets on our distributable cash flow, thereby establishing a direct link between executive compensation and our financial performance.
The compensation committee establishes minimum, target and stretch incentive opportunities for each executive officer and other key employees expressed as a percentage of base salary. The amount that is paid out is based on our achievement of a minimum, target or stretch level of distributable cash flow for the fiscal year. At the recommendation of the compensation
committee, the board of directors approves distributable cash flow targets for each fiscal year based on budgets prepared by management. When making the annual determination of the minimum goal, target goal and stretch goal levels of distributable cash flow, the compensation committee and the board of directors consider the specific circumstances facing us during the relevant year. Generally, the compensation committee seeks to set the minimum goal, target goal and stretch goal levels such that the relative challenge of achieving each level is consistent from year to year. The expectation that management will achieve the minimum goal level is very high, while meaningful additional effort would be required to achieve the target goal and considerable additional effort would be required to achieve the stretch goal.
Generally, no awards are paid under the Cash Incentive Plan unless we achieve at least the minimum distributable cash flow goal. If the minimum, target or stretch level distributable cash flow goal is achieved, participants in the plan will receive their minimum, target or stretch cash award opportunity, respectively. If our distributable cash flow is between specified goal levels, participants are eligible to receive a prorated percentage of their cash award opportunity based on where the actual distributable cash flow amount falls between the levels.
Results. For fiscal year 2012, the minimum distributable cash flow goal was $123.0 million, the target goal was $138.5 million and the stretch goal was $169.3 million. For the reasons described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations - 2012 Update,” we exceeded our stretch goal with 2012 distributable cash flow of $281.1 million.
The following table summarizes the levels of cash award opportunity for each named executive officer and the actual percentage earned by them in 2012:
(1)
Mr. Grube’s employment agreement guarantees him a potential award that is at least 150% of the amount of the next highest potential award by any other executive officer of our general partner, which would be the maximum potential award for Ms. Straumins of $595,000.
The compensation committee determined these percentages of base salary at levels, when combined with both base salary and potential long-term, unit-based awards, to develop a total direct compensation structure for the named executive officers which is intended to be within 25% of the median of our peer group, while placing significant emphasis on the achievement of our distributable cash flow goals.
For 2012, the target goal for distributable cash flow was set at the budgeted amount, a level that the board of directors believed reflected the reasonable expectations management had for our financial performance during the fiscal year and likely to be achieved given actual distributable cash flow achieved for the 2011 fiscal year. The board of directors set the stretch cash flow goal at 22% above the budgeted amount, a level which they believed would be attained only with higher levels of performance relative to the reasonable expectations management had for our financial performance and therefore not likely to be achieved. The minimum goal was set at approximately 11% below the budgeted amount. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations - 2012 Update,” for a discussion of the factors that impacted our results, including our higher gross profit per barrel sold of fuel products and higher sales volume of both specialty products and fuel products, the primary drivers that enabled us to exceed our distributable cash flow targets. The following table reflects our historical minimum, target and stretch distributable cash flow goals:
(1)
As adjusted. When assessing our 2010 performance with respect to our distributable cash flow targets, the compensation committee determined it was appropriate to include an interim payment of certain insurance proceeds. Such amounts were excluded from distributable cash flow for 2011.
(2)
For 2011, we adjusted the calculation of Distributable Cash Flow to reflect calculations contained in our debt instruments. For additional information please read Part II, Item 6 “Selected Financial Data - Non-GAAP Financial Measures” for our definition of Distributable Cash Flow. For 2011 and 2010 Distributable Cash Flow calculations, please refer to our 2011 and 2010 Annual Reports.
Compensation Changes for 2013. Upon the recommendation of the compensation committee, the board of directors has approved new distributable cash flow targets for the 2013 fiscal year based on budgets prepared by management. We do not disclose our confidential 2013 targets, which, if disclosed, would put us at a competitive disadvantage. However, we believe that the targets that are set for the 2013 year will be more difficult to achieve than the targets set for the 2012 year and there is no guarantee that our named executive officers will receive an award related to the 2013 year.
For further description of this compensation program, please see “Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table - Description of Cash Incentive Plan.”
Executive Deferred Compensation Plan
Design. The compensation committee allows for the participation of the executive officers in the Calumet Specialty Products Partners, L.P. Executive Deferred Compensation Plan (the “Deferred Compensation Plan”) to encourage the officers to save for retirement and to assist us in retaining our officers. The Deferred Compensation Plan is intended to promote retention by giving employees an opportunity to save in a tax-efficient manner. The terms governing the retirement benefit under this plan for the executive officers are the same as those available for other eligible employees in the U.S. Pursuant to the Deferred Compensation Plan, a select group of management, including the named executive officers, and all of the non-employee directors are eligible to participate by making an annual irrevocable election to defer, in the case of management, all or a portion of their annual cash incentive award under the Cash Incentive Plan, and, in the case of non-management directors, all or none of their annual cash retainer. The deferred amounts are credited to participants’ accounts in the form of phantom units, with each such phantom unit representing a notional unit that entitles the holder to receive either an actual common unit or the cash value of a common unit (determined by using the fair market value of a common unit at the time a determination is needed). The phantom units credited to each participant’s account also receive distribution equivalent rights (“DERs”), which are credited to the participant’s account in the form of additional phantom units. In our sole discretion, we may make matching contributions of phantom units or purely discretionary contributions of phantom units, in amounts and at times as the compensation committee recommends and the board of directors approves.
Results. On February 29, 2012, we made discretionary matching contributions of phantom units to the accounts of those participants in the Deferred Compensation Plan, including certain of the named executive officers, who elected to defer all or a portion of their annual cash incentive award related to the 2011 fiscal year. These contributions, which were subject to continued service vesting requirements, were made as a reward for prior service and future efforts toward our success and growth, as well as an incentive for continued participation through elective deferrals into the Deferred Compensation Plan allowing participants to save in a tax-efficient manner knowing that we, in our discretion, may make such matching contributions. Please see Nonqualified Deferred Compensation” for a more detailed disclosure of the value of contributions into this plan, as well as the DERs associated with such contributions.
Long-Term, Unit-Based Awards
Design. Long-term unit-based awards may consist of phantom units, restricted units, unit options, substitution awards and DERs. These awards are granted to employees, consultants and directors of our general partner under the provisions of our Long-Term Incentive Plan, as amended, (the “Plan”) originally adopted on January 24, 2006 and administered by the compensation committee. These awards aid Calumet in retaining and motivating executives to assist us in meeting our financial performance objectives.
In fiscal year 2012, the annual unit award opportunity to named executive officers consisted of the contingent right to receive phantom units. Under the Plan, phantom units are granted only upon our achievement of specified levels of distributable cash flow. When granted, phantom units are subject to further time-based vesting criteria specified in the grant. Upon satisfaction of the time-based vesting criteria specified in the grant, phantom units convert into common units (or cash equivalent). Accordingly, these awards established a direct link between executive compensation and our financial performance. This component of executive compensation, when coupled with an extended ratable vesting period as compared to cash awards, further aligns the interests of executives with our unitholders in the longer-term and reinforces unit ownership levels among executives.
Results. The following table provides the annual unit award opportunity for each named executive officer. Our general objective when determining the size of the phantom unit awards is to provide our named executive officers with long-term incentive opportunities targeted at approximately the 25th percentile of peer practices for long-term equity based awards for similarly situated executive officers. The following table reflects the number of phantom units that would be awarded to our named executive officers depending on whether we achieved the distributable cash flow minimum, target and stretch goals discussed above in “Short-Term Cash Awards” as well as the actual number of phantom units earned in 2012, which will be awarded in the first quarter of 2013:
Phantom units granted are subject to a time-vesting requirement, whereby 25% of the units vest immediately at grant and the remainder vest ratably over three years on each December 31. These phantom units also receive DERs, which are paid in the form of cash.
For further description of this compensation program, please see “Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table - Description of Long-Term Incentive Plan.”
Health and Welfare Benefits
We offer a variety of health and welfare benefits to all eligible employees of our general partner. These benefits are consistent with the types of benefits provided by our peer group and provided so as to ensure that we are able to maintain a competitive position in terms of attracting and retaining executive officers and other employees. In addition, the health and welfare programs are intended to protect employees against catastrophic loss and encourage a healthy lifestyle. The named executive officers generally are eligible for the same benefit programs on the same basis as the rest of our employees. Our health and welfare programs include medical, pharmacy, dental, life insurance and accidental death and dismemberment. In addition, certain employees are eligible for long-term disability coverage. Coverage under long-term disability offers benefits specific to the named executive officers. We provide the named executive officers with a compensation allowance, which is grossed up for the payment of taxes to allow them to purchase long-term disability coverage on an after-tax basis at no net cost to them. As structured, these long-term disability benefits will pay 60% of monthly earnings, as defined by the policy, up to a maximum of $6,000 per month during a period of continuing disability up to normal retirement age, as defined by the policy. Executive officers and other key employees are also eligible to obtain executive physical examinations which are paid for by Calumet. Decisions made with respect to this compensation element do not significantly factor into or affect decisions made with respect to other compensation elements.
Retirement Benefits
We provide the Calumet GP, LLC Retirement Savings Plan (the “401(k) Plan”) to assist our eligible officers and employees in providing for their retirement. Named executive officers participate in the same retirement savings plan as other eligible employees subject to ERISA limits. We match 100% of each 1% of eligible compensation contribution by the participant up to 4% and 50% of each additional 1% of eligible compensation contribution up to 6%, for a maximum contribution by us of 5% of eligible compensation contributions per participant. These contributions are provided as a reward for prior contributions and future efforts toward our success and growth.
The retirement savings plan also includes a discretionary profit-sharing component. Determination of annual contributions is subjectively made by the compensation committee based on our overall profitability. The board of directors approved a discretionary profit sharing contribution to the 401(k) plan for all eligible participants equivalent to 2.5% of their eligible compensation for the 2012 fiscal year. The value our contributions to the retirement savings plan for named executive officers is included in the Summary Compensation Table. Decisions made with respect to this compensation element do not significantly factor into or affect decisions made with respect to other compensation elements.
Although we have not historically maintained a traditional pension plan for our employees, we continued to maintain the Penreco Pension Plan after our acquisition of Penreco in 2008 for the employees that were participating in the plan at that time. Only one of our named executive officers, Mr. Barnhart, was and is a participant in the Penreco Pension Plan. While the plan
was frozen in 2009, Mr. Barnhart still holds an account in that plan. Please see the “Pension Benefits” section below for additional details.
Perquisites
We provide executive officers with perquisites and other personal benefits that we believe are reasonable and consistent with our overall compensation programs and philosophy. These benefits are provided in order to enable us to attract and retain these executives. Decisions made with respect to this compensation element do not significantly factor into or affect decisions made with respect to other compensation elements.
All named executive officers are provided with all, or certain of, the following benefits as a supplement to their other compensation:
•
Use of Company Vehicles: In order to assist them in conducting our daily affairs, we provide each named executive officer with a company vehicle that may be used for personal use as well as business use. Personal use of a company vehicle is treated as taxable compensation to the named executive officer.
•
Executive Physical Program: Generally on an annual basis, we pay for a complete and professional personal physical exam for each named executive officer appropriate for his or her age to improve their health and productivity.
•
Club Memberships: We pay club membership fees for a certain named executive officer. Although such club memberships may be used for personal purposes in addition to business entertainment purposes, each named executive officer having such a membership is responsible for the reimbursement to us or direct payment for any incremental costs above the base membership fees associated with his or her personal use of such membership.
•
Spousal Travel: On an occasional basis, we pay expenses related to travel of the spouses of our named executive officers in order to accompany the named executive officer to business-related events.
•
Long-Term Disability Insurance: We provide compensation to allow each named executive officer to purchase long-term disability insurance on an after-tax basis at no net cost to them.
•
Use of Company Aircraft: On an occasional basis, our named executive officers may be eligible to use a leased aircraft for personal use and the incremental cost to us is treated as and reflected in the tables below as compensation to the applicable officer for purposes of these disclosures. The items that we use to determine the incremental cost to us of these flights include the variable costs for personal use of aircraft that were charged to us by the vendor that operates the leased aircraft for contracted hourly costs, fuel charges, and taxes.
The compensation committee periodically reviews the perquisite program to determine if adjustments are appropriate and did not make any material changes to the program during the 2012 year.
Other Compensation Related Matters
Tax Implications of Executive Compensation
Because we are not an entity taxable as a corporation, many of the tax issues associated with executive compensation that face publicly traded corporations do not directly affect us. Internal Revenue Code Section 409A (“Section 409A”) provides that amounts deferred under nonqualified deferred compensation plans are includible in a participant’s income when vested, unless certain requirements are met. If these requirements are not met, participants are also subject to an additional income tax and interest. All of our awards under our Long-Term Incentive Plan, severance arrangements and other nonqualified deferred compensation plans presently meet these requirements. As a result, employees will be taxed when the deferred compensation is actually paid to them. We will be entitled to a tax deduction at that time.
Executive Ownership of Units
While we have not adopted any security ownership requirements or policies for our executives, our executive compensation programs foster the enhancement of executives’ equity ownership through long-term, unit-based awards under Calumet’s Long-Term Incentive Plan. Further, in 2006 several executives purchased a significant number of our common units as participants in a directed unit program in conjunction with our initial public offering. For a listing of security ownership by our named executive officers, refer to Item 12
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
The following table sets forth the beneficial ownership of our units as of February 28, 2013 held by:
•
each person who beneficially owns 5% or more of our outstanding units;
•
each director of our general partner;
•
each named executive officer of our general partner; and
•
all directors, and executive officers of our general partner as a group.
The amounts and percentages of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed a beneficial owner of the same securities and a person may be deemed a beneficial owner of securities as to which he has no economic interest.
Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable. The address for the beneficial owners listed below, other than The Heritage Group and Calumet, Incorporated, is 2780 Waterfront Parkway East Drive, Suite 200, Indianapolis, Indiana 46214.
(1)
Thirty grantor trusts indirectly own all of the outstanding general partner interests in The Heritage Group, an Indiana general partnership. The direct or indirect beneficiaries of the grantor trusts are members of the Fehsenfeld family.
Each of the grantor trusts has five trustees, Fred M. Fehsenfeld, Jr., James C. Fehsenfeld, Nicholas J. Rutigliano, William S. Fehsenfeld and Amy M. Schumacher, each of whom exercises equivalent voting rights with respect to each such trust. Each of Fred M. Fehsenfeld, Jr., Nicholas J. Rutigliano and William S. Fehsenfeld, who are directors of our general partner, disclaims beneficial ownership of all of the common units owned by The Heritage Group, and none of these units are shown as being beneficially owned by such directors in the table above. The address for The Heritage Group is 5400 W. 86th St., Indianapolis, Indiana 46268. Of these common units, 367,197 are owned by The Heritage Group Investment Company, LLC (“Investment LLC”). Investment LLC is under common ownership with The Heritage Group. The Heritage Group, although not the owner of the common units, serves as the Manager of Investment LLC, and in that capacity has sole voting and investment power over the common units. The Heritage Group disclaims beneficial ownership of the common units owned by Investment LLC except to the extent of its pecuniary interest therein.
(2)
The common units of Calumet, Incorporated are indirectly owned 45.8% by The Heritage Group and 5.1% by Fred M. Fehsenfeld, Jr. personally. Fred M. Fehsenfeld, Jr. is also a director of Calumet, Incorporated. Accordingly, 885,294 of the common units owned by Calumet, Incorporated are also shown as being beneficially owned by The Heritage Group in the table above, and 97,971 of the common units owned by Calumet, Incorporated are also shown as being beneficially owned by Fred M. Fehsenfeld, Jr. in the table above. The Heritage Group and Fred M. Fehsenfeld, Jr. disclaims beneficial ownership of all of the common units owned by Calumet, Incorporated in excess of their respective pecuniary interests in such units. The address of Calumet, Incorporated is 5400 W. 86th St., Indianapolis, Indiana 46268.
(3)
Includes 775,000 common units that are owned by AEG Associates II, LLC, an Indiana domestic limited liability company (“AEG II”). F. William Grube has sole voting and investment power over the common units. AEG II is co-owned by F. William Grube, William F. Grube, Jennifer G. Straumins, one grantor retained annuity trust for which Jennifer G. Straumins serves as sole trustee, and one grantor retained annuity trust for which Janet K. Grube, the spouse of F. William Grube, serves as sole trustee. F. William Grube disclaims beneficial ownership of the common units owned by AEG II except to the extent of his pecuniary interest therein.
(4)
Includes common units that are owned by a grantor retained annuity trusts for which Janet K. Grube, the spouse of F. William Grube, serves as sole trustee. Janet K. Grube and her two children are the beneficiaries of such trusts. F. William Grube disclaims beneficial ownership of the common units owned by the trust.
(5)
Includes common units that are owned by the spouse of F. William Grube, for which he disclaims beneficial ownership.
(6)
Includes common units that are owned by the children of Jennifer G. Straumins, of which she disclaims beneficial ownership.
(7)
Includes common units that are owned by the spouse and certain children of Fred M. Fehsenfeld, Jr., for which he disclaims beneficial ownership.
(8)
Does not include a total of 1,979,804 common units owned by two trusts, the direct or indirect beneficiaries of which are members of the Fred M. Fehsenfeld, Jr. family. Each of the trusts has five trustees, Fred M. Fehsenfeld, Jr., James C. Fehsenfeld, Nicholas J. Rutigliano, William S. Fehsenfeld and Amy M. Schumacher, each of whom exercises equivalent voting rights with respect to each such trust. Each of Fred M. Fehsenfeld, Jr., Nicholas J. Rutigliano and William S. Fehsenfeld, who are directors of our general partner, disclaims beneficial ownership of all of the common units owned by the trusts, and none of these units are shown as being beneficially owned by such directors in the table above.
(9)
Includes common units that are owned by the spouse of George C. Morris III, of which he disclaims beneficial ownership.
(10)
Includes common units that are owned by the spouse of William S. Fehsenfeld, of which he disclaims beneficial ownership.
(11)
Includes common units that are owned by the spouse of Nicholas J. Rutigliano, of which he disclaims beneficial ownership.
Equity Compensation Plan Information
The following table summarizes information about our equity compensation plans as of December 31, 2012:
(1)
The Long-Term Incentive Plan contemplates the issuance or delivery of up to 783,960 common units to satisfy awards under the plan. The number of units presented in column (a) assumes that all outstanding grants may be satisfied by the issuance of new units or the purchase of existing units on the open market upon vesting. In fact, some portion of the phantom units may be settled in cash and some portion will be withheld for taxes. Any units not issued upon vesting will become “available for future issuance” under Column (c). For more information on our Long-Term Incentive Plan, which did not require approval by our limited partners, refer to Item 11 “Executive and Director Compensation - Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table - Description of Long-Term Incentive Plan.”
Item 13.
Item 13.
Certain Relationships and Related Transactions and Director Independence
Distributions and Payments to Our General Partner and its Affiliates
Owners of our general partner and their affiliates own 18,132,686 common units representing a 28.7% limited partner interest in us. In addition, our general partner owns a 2% general partner interest in us and all of the incentive distribution rights. Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, generally our general partner is entitled, without duplication, to 15% of amounts we distribute in excess of $0.495 ($1.98 annualized) per unit, 25% of the amounts we distribute in excess of $0.563 ($2.25 annualized) per unit and 50% of amounts we distribute in excess of $0.675 ($2.70 annualized) per unit. Please refer to Part II, Item 5 “Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities - Market Information” for a summary of cash distribution levels of the Company during the year ended December 31, 2012 and for additional information related to incentive distribution rights.
Our general partner does not receive any management fee or other compensation for its management of our partnership; however, our general partner and its affiliates are reimbursed for all expenses incurred on our behalf. These expenses include the cost of employee, officer and director compensation and benefits properly allocable to us and all other expenses necessary or appropriate to the conduct of our business and allocable to us. The partnership agreement provides that our general partner determines the expenses that are allocable to us. There is no limit on the amount of expenses for which our general partner and its affiliates may be reimbursed.
Omnibus Agreement
We entered into an omnibus agreement, dated January 31, 2006, with The Heritage Group and certain of its affiliates pursuant to which The Heritage Group and its controlled affiliates agreed not to engage in, whether by acquisition or otherwise, the business of refining or marketing specialty lubricating oils, solvents and wax products as well as gasoline, diesel and jet fuel products in the continental United States (“restricted business”) for so long as The Heritage Group controls us. This restriction does not apply to:
•
any business owned or operated by The Heritage Group or any of its affiliates as of January 31, 2006;
•
the refining and marketing of asphalt and asphalt-related products and related product development activities;
•
the refining and marketing of other products that do not produce “qualifying income” as defined in the Internal Revenue Code;
•
the purchase and ownership of up to 9.9% of any class of securities of any entity engaged in any restricted business;
•
any restricted business acquired or constructed that The Heritage Group or any of its affiliates acquires or constructs that has a fair market value or construction cost, as applicable, of less than $5.0 million;
•
any restricted business acquired or constructed that has a fair market value or construction cost, as applicable, of $5.0 million or more if we have been offered the opportunity to purchase it for fair market value or construction cost and we decline to do so with the concurrence of the conflicts committee of the board of directors of our general partner; and
•
any business conducted by The Heritage Group with the approval of the conflicts committee of the board of directors of our general partner.
Insurance Brokerage
Nicholas J. Rutigliano, a member of the board of directors of our general partner, founded and is the president of Tobias Insurance Group, Inc., a commercial insurance brokerage business, that has historically placed a portion of our insurance underwriting and surety/performance bond requirements, including our general liability, automobile liability, excess liability, workers’ compensation as well as directors’ and officers’ liability and issuance of surety/performance bonds. The total premiums and fees paid by us through Mr. Rutigliano’s firm for 2012 were approximately $0.5 million and were related to our directors’ and officers’ liability insurance. We believe these premiums are comparable to the premiums we would pay for such insurance from a non-affiliated third party and we have assessed our other insurance brokerage options to confirm this belief. We have transitioned the majority of the aforementioned insurance underwriting requirements to a non-affiliated third party commercial insurance broker.
Crude Oil Purchases
Since May 2008, we purchased a portion of our crude oil supplies from Legacy Resources Co., L.P. (“Legacy Resources”), an exploration and production company owned in part by The Heritage Group, our chief executive officer and vice chairman of the board of our general partner, F. William Grube, and Jennifer G. Straumins, our president and chief operating officer. Mr. Grube and Ms. Straumins serve as members of the board of directors of Legacy Resources. The total purchases made by us from Legacy Resources in 2012 were approximately $1.1 million, which represented purchases based upon standard, index-based market rates.
From May 2008 to May 2011 we purchased all of our crude oil requirements for our Princeton refinery on a just in time basis utilizing a market-based pricing mechanism from Legacy Resources. Based on historical usage, the estimated volume of crude oil sold by Legacy Resources and purchased by us for the Princeton refinery is approximately 7,000 barrels per day. This agreement was terminated in May 2011.
On January 26, 2009, we entered into a Master Crude Oil Supply Agreement with Legacy Resources (the “Master Crude Oil Supply Agreement”). Under this agreement, Legacy Resources may supply our Shreveport refinery with a portion of its crude oil requirements that are received via common carrier pipeline. Pricing for the crude oil purchased under each confirmation will be mutually agreed to by the parties and set forth in such confirmation and will include a market-based premium as determined and agreed to by the parties. The agreement was effective as of January 26, 2009 and will continue to be in effect until terminated by either party by written notice. Based on historical usage, the estimated volume of crude oil to be sold by Legacy Resources and purchased by us under this Agreement is up to 15,000 barrels per day. This agreement is active but is not currently in use.
From September 2009 to May 2011, we purchased crude oil under a Crude Oil Supply Agreement (the “Shreveport Crude Oil Supply Agreement”) with Legacy Resources. Under the Agreement, Legacy Resources supplies our Shreveport refinery with a portion of its crude oil requirements on a just in time basis utilizing a market-based pricing mechanism. Based on historical usage, the estimated volume of crude oil to be sold by Legacy Resources and purchased by us under this Agreement is up to 20,000 barrels per day. This agreement was terminated in May 2011.
With the termination of the agreements, we have one remaining crude oil supply agreement with Legacy Resources, the Master Crude Oil Purchase and Sale Agreement, that was entered into on January 26, 2009. No crude oil is currently being purchased by the Company under this agreement.
Because Legacy Resources is owned in part by one of our limited partners, an affiliate of our general partner, our chief executive officer and vice chairman of the board of directors of our general partner, F. William Grube, and our president and
chief operating officer, Jennifer G. Straumins, the terms of the aforementioned agreements were reviewed by the conflicts committee of the board of directors of our general partner, which consists entirely of independent directors. The conflicts committee approved the agreements after determining that the terms of the agreements are fair and reasonable to us.
Specialty Product Sales and Related Purchases
During 2012, we made ordinary course sales of certain specialty products to Johann Haltermann, Ltd. (“Haltermann”), a specialty chemical company owned in part by The Heritage Group and certain Grube family trusts for which Janet K. Grube is sole trustee. The total sales made by us to Haltermann in 2012 were approximately $1.8 million. As of December 31, 2012 there was an immaterial balance due us from Haltermann related to these products sales. We anticipate that we will continue to sell products to Haltermann in the future. We believe that the product sales prices and credit terms offered to Haltermann are comparable to prices and terms offered to non-affiliated third party customers.
During 2012, we made ordinary course sales of certain specialty products to Heritage-Crystal Clean Inc. (“Crystal Clean”), a cleaning and waste removal company owned in part by The Heritage Group and Fred M. Fehsenfeld, Jr. as an individual. The total sales made by us to Crystal Clean in 2012 were approximately $0.3 million. As of December 31, 2012, there was no balance due us from Crystal Clean related to these products sales. We anticipate that we will continue to sell products to Crystal Clean in the future. The total purchases made by us from Crystal Clean in 2012 for cleaning and waste removal services were approximately $6.4 million. As of December 31, 2012, there was a $0.2 million balance due from us to Crystal Clean related to these purchases. We believe that the product sales prices and credit terms offered to Crystal Clean are comparable to prices and terms offered to non-affiliated third party customers.
During 2012, we made payments to Asphalt Materials, Inc., an affiliate of The Heritage Group (“Asphalt Materials”), for expenses related to the business use of The Heritage Group’s company plane by our senior executive officers and for environmental consulting services provided to us by Asphalt Materials. The aggregate payments for these services made by us to Asphalt Materials in 2012 were approximately $0.6 million. As of December 31, 2012, there were approximately $0.5 million due from us to Asphalt Materials related to these services. We believe that the costs of the services provided to us by Asphalt Materials are comparable to costs charged by non-affiliated third-party suppliers of similar services. During 2012, we made ordinary course sales of certain specialty products to Asphalt Materials of $7.2 million. As of December 31, 2012, there was no balance due us from Asphalt Materials related to these products sales. We also reimburse Asphalt Materials for ordinary course purchases made by us under a procurement card program administered by Asphalt Materials. As of December 31, 2012, there was approximately $1.6 million payable by us to Asphalt Materials related to the reimbursement of these ordinary course purchases. We expect that we will continue to utilize each of these services from Asphalt Materials in the future.
TruSouth Acquisition
On January 6, 2012, we completed the acquisition of all of the outstanding membership interests of TruSouth for aggregate consideration of approximately $26.8 million. Immediately prior to its acquisition, TruSouth was owned in part by Fred M. Fehsenfeld, Jr.; the spouse of F. William Grube; and other members of the Fehsenfeld and Grube families, who also own our general partner. The terms of the agreement were reviewed by the conflicts committee of the board of directors of our general partner, which consists entirely of independent directors. The conflicts committee approved the agreement after determining that the terms of the agreement were fair and reasonable to us.
Procedures for Review and Approval of Related Person Transactions
Effective February 9, 2007, to further formalize the process by which related person transactions are analyzed and approved or disapproved, the board of directors of our general partner has adopted the Calumet Specialty Products Partners, L.P. Related Person Transactions Policy (the “Policy”) to be followed in connection with all related person transactions (as defined by the Policy) involving the Company and its subsidiaries. The Policy was adopted to provide guidelines and procedures for the application of the partnership agreement to related person transactions and to further supplement the conflicts resolutions policies already set forth therein.
The Policy defines a “related person transaction” to mean any transaction since the beginning of the Company’s last fiscal year (or any currently proposed transaction) in which: (i) the Company or any of its subsidiaries was or is to be a participant; (ii) the amount involved exceeds $120,000 (including any series of similar transactions exceeding such amount on an annual basis); and (iii) any related person (as defined in the Policy) has or will have a direct or indirect material interest. Under the terms of the policy, our general partner’s chief executive officer (“CEO”) has the authority to approve a related person transaction (considering any and all factors as the CEO determines in his sole discretion to be relevant, reasonable or appropriate under the circumstances) so long as it is:
(a) in the normal course of the Company’s business;
(b) not one in which the CEO or any of his immediate family members has a direct or indirect material interest; and
(c) on terms no less favorable to the Company than those generally being provided to or available from unrelated third parties or fair to the Company, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Company).
The CEO does not have the authority to approve the issuances of equity or grants of awards under the Company’s Long-Term Incentive Plan, except as provided in that plan. Pursuant to the Policy, any other related person transaction must be approved by the conflicts committee acting in accordance with the terms and provisions of its charter.
A copy of the Policy is available on our website at www.calumetspecialty.com and will be provided to unitholders without charge upon their written request to: Investor Relations, Calumet Specialty Products Partners, L.P., 2780 Waterfront Parkway E. Drive, Suite 200, Indianapolis, IN 46214.
Please see Item 10 “Directors, Executive Officers of Our General Partner and Corporate Governance” for a discussion of director independence matters.
Item 14.
Item 14.
Principal Accounting Fees and Services
The following table details the aggregate fees billed for professional services rendered by our independent auditor during 2012 and 2011.
“Audit fees” above include those related to our annual audit, audit of our general partner and quarterly review procedures.
“Audit-related fees” primarily relate to various securities offerings in 2012 and purchase price allocation procedures related to acquisitions.
“Tax fees” are related to due diligence and domestic compliance matters.
“All other fees” primarily consist of those associated with insurance claim consulting services and due diligence related to acquisitions.
Pre-Approval Policy
The audit committee of our general partner’s board of directors has adopted an audit committee charter, which is available on our website at www.calumetspecialty.com. The charter requires the audit committee to pre-approve all audit and non-audit services to be provided by our independent registered public accounting firm. The audit committee does not delegate its pre-approval responsibilities to management or to an individual member of the audit committee. Services for the audit, tax and all other fee categories above were pre-approved by the audit committee.
PART IV
Item 15.
Item 15.
Exhibits
(a)(1) Consolidated Financial Statements
The consolidated financial statements of Calumet Specialty Products Partners, L.P. are included in Part II, Item 8 “Financial Statements and Supplementary Data.”
(a)(2) Financial Statement Schedules
All schedules are omitted because they are not applicable, or the required information is shown in the consolidated financial statements or notes thereto.
(a)(3) Exhibits
The following documents are filed as exhibits to this Annual Report:
*
Identifies management contract and compensatory plan arrangements.
**
Filed herewith.
***
XBRL (Extensible Business Reporting Language) information is furnished and not filed or a part of the registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
CALUMET SPECIALTY PRODUCTS
PARTNERS, L.P.
By:
CALUMET GP, LLC
its general partner
By:
/s/ F. William Grube
F. William Grube
Chief Executive Officer
Date: March 1, 2013
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Index to Exhibits
*
Identifies management contract and compensatory plan arrangements.
**
Filed herewith.
***
XBRL (Extensible Business Reporting Language) information is furnished and not filed or a part of the registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.