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CLMT > SEC Filings for CLMT > Form 10-Q on 9-May-2014All Recent SEC Filings

Show all filings for CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

Form 10-Q for CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.


9-May-2014

Quarterly Report


Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
The historical unaudited condensed consolidated financial statements included in this Quarterly Report reflect all of the assets, liabilities and results of operations of Calumet Specialty Products Partners, L.P. ("Calumet," the "Company," "we," "our," or "us"). The following discussion analyzes the financial condition and results of operations of the Company for the three months ended March 31, 2014 and 2013. Unitholders should read the following discussion and analysis of the financial condition and results of operations of the Company in conjunction with our 2013 Annual Report and the historical unaudited condensed consolidated financial statements and notes of the Company included elsewhere in this Quarterly Report. Overview
We are a leading independent producer of high-quality, specialty hydrocarbon products in North America. We are headquartered in Indianapolis, Indiana and own facilities primarily located in Louisiana, Wisconsin, Montana, Texas, Pennsylvania, New Jersey and Oklahoma. We own and lease additional facilities, primarily related to production and distribution of specialty and fuel products, throughout the United States ("U.S."). Our business is organized into two segments: specialty products and fuel products. In our specialty products segment, we process crude oil and other feedstocks into a wide variety of customized lubricating oils, white mineral oils, solvents, petrolatums and waxes. Our specialty products are sold to domestic and international customers who purchase them primarily as raw material components for basic industrial, consumer and automotive goods. We also blend and market specialty products through our Royal Purple and Bel-Ray brands. In our fuel products segment, we process crude oil into a variety of fuel and fuel-related products, including gasoline, diesel, jet fuel, asphalt and heavy fuel oils, as well as reselling purchased crude oil to third party customers. First Quarter 2014 Update
Financial Results
Our specialty products segment generated a gross profit per barrel of $42.22 during the first quarter 2014, versus $32.49 in the first quarter 2013. The increase in specialty products segment gross profit was due primarily to increased average selling prices per barrel sold as a result of improved product mix and gross profit contribution attributable to acquisitions, partially offset by lower sales volume and higher operating costs.
Our fuel products segment generated a gross profit per barrel of $3.66 (excluding hedging activities) during the first quarter 2014, versus $8.25 (excluding hedging activities) in the first quarter 2013. A significant year-over-year decline in benchmark refined product margins was partially offset by strong seasonal demand for gasoline and diesel at each of our major fuel refineries, which operated at elevated rates during the first quarter 2014. For benchmarking purposes, we compare our per barrel refined fuel products margin to the U.S. Gulf Coast 2/1/1 crack spread ("Gulf Coast crack spread"). The Gulf Coast crack spread represents the approximate gross margin per barrel that results from processing two barrels of crude oil into one barrel of gasoline and one barrel of ultra-low sulfur diesel. The Gulf Coast crack spread is calculated using the first-month futures price of NYMEX WTI crude oil, the price of U.S. Gulf Coast Pipeline 87 Octane Conventional Gasoline and U.S. Gulf Coast Pipeline Ultra-Low Sulfur Diesel ("ULSD").
For the first quarter 2014, the Gulf Coast crack spread averaged approximately $19 per barrel, or approximately 37% less than in the first quarter 2013 of approximately $30 per barrel. The benchmark gasoline and distillate margins both declined on a year-over-year basis during the first quarter 2014, although the diesel crack spread remained elevated when compared to historical levels. The market ULSD crack spread averaged $24 per barrel during the first quarter 2014, compared to $35 per barrel in the prior year period. The market gasoline crack spread averaged $13 per barrel during the first quarter 2014, compared to $25 per barrel in the prior year period.
Our fuel products gross profit per barrel (excluding hedging activities) divided by the Gulf Coast crack spread is referred to as the "capture rate." The capture rate is a means of measuring refinery system gross profit per barrel against the benchmark crack spread. In the first quarter 2014, our capture rate was approximately 20% compared to approximately 27% in the first quarter 2013. There are several factors that impact our refined product margin when compared to the benchmark crack spread including, but not limited to, regional product prices, the delivered price of crude oil and operating expenses. For example, several of our fuel products refineries produce asphalt and other residual products that may carry an average sales price below that of U.S. Gulf Coast Pipeline 87 Octane Conventional Gasoline or U.S. Gulf Coast Pipeline ULSD. Further, many of our fuel products refineries purchase select quantities of crude oil at a discount to NYMEX WTI, which helps support a higher capture rate, relative to the crack spread benchmark. Based on our system-wide crude purchasing behaviors and overall production slate, we believe the U.S. Gulf Coast 2/1/1 crack spread remains a helpful indicator in tracking directional shifts in our refined product margins.


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Liquidity Update
On March 31, 2014, we had availability under our revolving credit facility of $533.6 million, based on a $705.4 million borrowing base, $171.8 million in outstanding standby letters of credit and no outstanding borrowings. In addition, we had $179.6 million of cash on hand as of March 31, 2014. Total cash and availability under our revolving credit facility totaled approximately $713.2 million at the end of the first quarter 2014, versus $593.5 million at the end of the fourth quarter 2013. We believe we will continue to have sufficient cash flow from operations and borrowing capacity to meet our financial commitments, minimum quarterly distributions to unitholders, debt service obligations, contingencies and anticipated capital expenditures. Capital Markets Update
On March 31, 2014, we completed a $900 million private placement of 6.50% senior notes due 2021 which were priced at par. The offering was upsized to $900 million from the original offering size of $850 million. We have used a portion of the net proceeds from the private placement to fund the approximately $236.6 million purchase price of our acquisition of ADF Holdings, Inc., the parent company of Anchor Drilling Fluids USA, Inc., related transaction expenses and the redemption of all $500 million aggregate principal amount of our outstanding 9.375% senior unsecured notes due 2019. Remaining funds will be used for general partnership purposes, including planned capital expenditures at our facilities. On March 10, 2014, we launched a $300 million "at-the-market" ("ATM") equity placement program. An ATM equity placement program provides a means for an issuer to conduct at-the-market equity offerings from time to time under a shelf registration statement. Under the ATM equity placement program, we have the option to sell units into the open market on a ratable basis at the current available market price. During the first quarter 2014, we did not sell any units under the ATM equity distribution program. Recent Acquisition Activity
On March 31, 2014, we completed the acquisition of Anchor Drilling Fluids USA, Inc. for total cash consideration of approximately $236.6 million, net of cash acquired and subject to working capital and certain other adjustments. The Anchor Acquisition was funded with a portion of the proceeds from the March 2014 issuance of $900 million of 6.50% senior unsecured notes. Anchor develops custom formulations and innovative solutions based on unique customer and well specifications. Through its extensive line of drilling and completion fluids, Anchor delivers solutions that reduce drilling and completion time, help to control reservoir formation pressures and maximize oil and gas production, contributing to improved well economics for end-users. This transaction positions us as one of the leading suppliers of drilling fluids to the domestic E&P industry, a sector that continues to enjoy rapid growth due to advances in drilling technology and increased exploration activity in identified and emerging unconventional resource plays. The addition of Anchor to our asset portfolio will also serve to increase our specialty products sales in a business that generates consistent cash flow with limited ongoing capital investment. For the year ended December 31, 2012, Anchor generated EBITDA of approximately $26.3 million. We currently anticipate that Anchor will report a year-over-year increase in EBITDA of approximately 20% for the full-year 2013. Quarterly Cash Distribution
On April 22, 2014, we declared a quarterly cash distribution of $0.685 per unit, or $2.74 per unit on an annualized basis, for the quarter ended March 31, 2014 on all of our outstanding limited partner units. The distribution will be paid on May 15, 2014 to unitholders of record as of the close of business on May 5, 2014. The total amount of cash paid to limited partner unitholders in connection with this quarterly cash distribution will be $52.5 million. Renewable Fuels Standard Update
As set forth under the Renewable Fuels Standard ("RFS"), the Environmental Protection Agency ("EPA") provides annual requirements for the total volume of renewable transportation fuels, including ethanol and advanced biofuels, that are mandated to be blended into the domestic gasoline pool. Under the RFS, domestic producers of gasoline (refiners) are required to establish that they have met their annual Renewable Volume Obligation ("RVO"). RINs are a mechanism by which obligated parties may determine their compliance with the RVO, whereas the obligated party must produce a volume of RINs equal to the number of gallons that it is required to blend under the RVO. In conjunction with our ongoing compliance with the RFS, we will regularly purchase RINs in the open market to cover our anticipated blending obligation. We recognize our outstanding RINs obligation as a balance sheet liability. This liability is marked-to-market on a quarterly basis to reflect the market price of RINs on the last day of each quarter.
For the three months ended March 31, 2014, we incurred RFS compliance costs of $7.9 million compared to $11.8 million in the first quarter 2013. We expect our gross estimated RINs obligation, which includes RINs that are required to be


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secured through either blending or through the purchase of RINs in the open market, to be in the range of 90 to 95 million RINs for the full-year 2014. Despite a recent decline in RINs prices from record levels during mid-2013, we continue to anticipate that expenses related to RFS compliance have the potential to remain a significant expense, assuming current market prices for RINs. Estimated RINs obligations are subject to fluctuations in fuels production volumes during the full-year 2014.
Organic Growth Projects Update
In June 2013, we introduced a series of high-return organic growth projects requiring a total capital investment estimated at $500 to $550 million between 2013 and the first quarter of 2016.
During 2013, we invested more than $100 million on these projects. During 2014, we estimate that our total capital investment on growth projects will approximate $270 to $300 million. Upon completion, we estimate the incremental Adjusted EBITDA generated from these projects should result in highly attractive rates of return for the Partnership.
In December 2013, we completed two projects at our San Antonio refinery that represent the first two projects completed under the multi-year organic growth campaign. These projects included the completion of a 3,000 bpd crude oil unit expansion, in addition to a fuels blending project designed to allow the refinery to blend and sell 5,000 bpd of finished gasoline. Between 2014 and the first quarter of 2016, we intend to complete three additional organic projects, including the following:
Dakota Prairie (North Dakota) Refinery. Together with our 50/50 joint venture partner, MDU Resources ("MDU"), we are in the process of constructing a 20,000 bpd diesel refinery located in Dickinson, North Dakota to meet growing local demand for diesel. The refinery, which is expected to be completely supplied with cost-advantaged local Bakken crude oil, is expected to commence operations during the fourth quarter 2014. The estimated total cost of the expansion project to the joint venture is approximately $300 million, subject to periodic reviews of project costs.
Missouri Esters Plant Expansion Project. We have initiated a project designed to double esters production capacity at our Missouri esters plant from 35 to 75 million pounds per year. We anticipate this project should reach completion during the second quarter 2015. Esters are a key base stock used in the aviation, refrigerant and automotive lubricants markets. The estimated total cost of the expansion project is approximately $40 million.
Montana Refinery Expansion Project. We have initiated a project designed to double production capacity at our Great Falls, Montana refinery from 10,000 bpd to 20,000 bpd. This project will allow us to capitalize on local access to cost-advantaged Bow River crude oil while producing additional fuels and refined products for delivery into the regional market. The scope of this project calls for the installation of a new 20,000 bpd crude unit and a 25,000 bpd hydrocracker. We estimate that this project will be completed during the first quarter of 2016. The estimated total cost of the expansion project is approximately $400 million.
Hedging Program Update
As part of our overall risk mitigation strategy, we utilize financial derivatives to help curtail exposure to commodity price volatility. We seek to hedge up to 75% of our anticipated fuels production up to four years in advance. The volume of anticipated fuels production covered by financial derivatives in the current year is generally higher than volumes hedged in future years, due to a number of factors, including the degree of market liquidity in futures contracts.


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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 help mitigate the impact of commodity price fluctuations on our business. The primary purpose of our commodity risk management activities is to economically hedge our cash flow exposure to commodity price risk so that we can meet our cash distribution, debt service and capital expenditure requirements despite fluctuations in crude oil and fuel products prices. We enter into derivative contracts for future periods in quantities that do not exceed our projected purchases of crude oil and natural gas and sales of fuel products. Please read Part I, Item 3 "Quantitative and Qualitative Disclosures About Market Risk-Commodity Price Risk." As of March 31, 2014, we had hedged refining margins, or crack spreads, on approximately 17.2 million barrels of fuel products through December 2016 at an average refining margin of $24.27 per barrel with average refining margins ranging from a low of $20.86 per barrel in the third quarter 2014 to a high of $27.27 per barrel in 2016. Please refer to Note 9 - "Derivatives" under Part I, Item 1 "Financial Statements-Notes to Unaudited Condensed Consolidated Financial Statements" and

Part I, Item 3 "Quantitative and Qualitative Disclosures About Market
Risk-Commodity Price Risk" for detailed information regarding our derivative instruments and our commodity price risk.
Our management uses several financial and operational measurements to analyze our performance. These measurements include the following:
•sales volumes;
•production yields;
•specialty products and fuel products segment gross profit; and
•specialty products and fuel products segment Adjusted EBITDA. Sales volumes. We view the volumes of specialty products and fuel products sold as an important measure of our ability to effectively utilize our operating assets. Our ability to meet the demands of our customers is driven by the volumes of crude oil and feedstocks that we run at our facilities. Higher volumes improve profitability both through the spreading of fixed costs over greater volumes and the additional gross profit achieved on the incremental volumes. Production yields. In order to maximize our gross profit and minimize lower margin by-products, we seek the optimal product mix for each barrel of crude oil we refine, or feedstocks we, or third parties, process, which we refer to as production yield. Specialty products and fuel products segment gross profit. Specialty products and fuel products gross profit are important measures of our ability to maximize the profitability of our specialty products and fuel products segments. We define specialty products and fuel products gross profit as sales less the cost of crude oil and other feedstocks and other production-related expenses, the most significant portion of which includes labor, plant fuel, utilities, contract services, maintenance, depreciation and processing materials. We use specialty products and fuel products gross profit as indicators of our ability to manage our business during periods of crude oil and natural gas price fluctuations, as the prices of our specialty products and fuel products generally do not change immediately with changes in the price of crude oil and natural gas. The increase in selling prices typically lags behind the rising costs of crude oil feedstocks for specialty products. Other than plant fuel, production-related expenses generally remain stable across broad ranges of throughput volumes, but can fluctuate depending on maintenance activities performed during a specific period. Our fuel products segment gross profit may differ from standard U.S. Gulf Coast, Group 3, PADD 4 Billings, Montana or 3/2/1 and 2/1/1 market crack spreads due to many factors, including derivative activities to hedge both our fuel products segment sales and the cost of crude oil reflected in gross profit, our fuel products mix as shown in our production table being different than the ratios used to calculate such market crack spreads, operating costs including fixed costs and actual crude oil costs differing from market indices and our local market pricing differentials for fuel products in the Shreveport, Louisiana, San Antonio, Texas, Superior, Wisconsin and Great Falls, Montana vicinities as compared to U.S. Gulf Coast, Group 3 and PADD 4 Billings, Montana postings.


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Specialty products and fuel products segment Adjusted EBITDA. We believe that specialty products and fuel products segment Adjusted EBITDA measures are useful as they exclude transactions not related to our core cash operating activities and provide metrics to analyze our ability to pay distributions to our unitholders as Adjusted EBITDA is a component in the calculation of distributable cash flow and allows us to meaningfully analyze the trends and performance of our core cash operations as well as make decisions regarding the allocation of resources to segments.
In addition to the foregoing measures, we also monitor our selling and general and administrative expenses.


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Results of Operations for the Three Months Ended March 31, 2014 and 2013 Production Volume. The following table sets forth information about our combined operations. Facility production volume differs from sales volume due to changes in inventories and the sale of purchased fuel product blendstocks such as ethanol and biodiesel and the resale of crude oil in our fuel products segment. The table includes the results of operations at our San Antonio refinery commencing January 2, 2013, Bel-Ray facility commencing December 10, 2013 and United Petroleum assets commencing February 28, 2014.

                                                   Three Months Ended March 31,
                                                   2014           2013     % Change
                                                       (In bpd)
Total sales volume (1)                          117,478         111,789       5.1  %
Total feedstock runs (2)                        118,359         110,465       7.1  %
Facility production: (3)
Specialty products:
Lubricating oils                                 10,617          12,127     (12.5 )%
Solvents                                          8,595           8,561       0.4  %
Waxes                                             1,321           1,234       7.1  %
Packaged and synthetic specialty products (4)     1,554           1,950     (20.3 )%
Other                                             2,507           3,077     (18.5 )%
Total                                            24,594          26,949      (8.7 )%
Fuel products:
Gasoline                                         32,987          29,881      10.4  %
Diesel                                           26,795          23,843      12.4  %
Jet fuel                                          4,428           4,794      (7.6 )%
Asphalt, heavy fuels and other                   22,368          22,518      (0.7 )%
Total                                            86,578          81,036       6.8  %
Total facility production (3)                   111,172         107,985       3.0  %


_____________


(1) Total sales volume includes sales from the production at our facilities and certain third-party facilities pursuant to supply and/or processing agreements, sales of inventories and the resale of crude oil to third party customers. Total sales volume includes the sale of purchased fuel product blendstocks, such as ethanol and biodiesel, as components of finished fuel products in our fuel products segment sales.

The increase in total sales volume for the three months ended March 31, 2014 compared to the same period in 2013 is due primarily to increased fuel products sales volume, partially offset by decreased sales of lubricating oils.
(2) Total feedstock runs represent the barrels per day of crude oil and other feedstocks processed at our facilities and at certain third-party facilities pursuant to supply and/or processing agreements.

The increase in total feedstock runs for the three months ended March 31, 2014 compared to the same period in 2013 is due primarily to decreased feedstock runs at the Superior refinery in 2013 as a result of preparation for the April 2013 turnaround and incremental feedstock runs in 2014 as a result of the San Antonio crude oil unit expansion completed in December 2013.
(3) Total facility production represents the barrels per day of specialty products and fuel products yielded from processing crude oil and other feedstocks at our facilities and at certain third-party facilities pursuant to supply and/or processing agreements. The difference between total facility production and total feedstock runs is primarily a result of the time lag between the input of feedstocks and production of finished products and volume loss.

The increase in total facility production for the three months ended March 31, 2014 compared to the same period in 2013 is due primarily to the operational items discussed above in footnote 2 of this table.
(4) Represents production of packaged and synthetic specialty products at our Royal Purple, Bel-Ray, Calumet Packaging and Missouri facilities.


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The following table reflects our consolidated results of operations and includes the non-GAAP financial measures EBITDA, Adjusted EBITDA and Distributable Cash Flow. For a reconciliation of EBITDA, Adjusted EBITDA and Distributable Cash Flow to net income (loss) and net cash provided by (used in) operating activities, our most directly comparable financial performance and liquidity measures calculated and presented in accordance with GAAP, please read

"-Non-GAAP Financial Measures."
                                                   Three Months Ended March 31,
                                                     2014                 2013
                                                           (In millions)
Sales                                          $      1,341.0       $      1,318.6
Cost of sales                                         1,216.2              1,184.2
Gross profit                                            124.8                134.4
Operating costs and expenses:
Selling                                                  19.0                 15.9
General and administrative                               25.9                 25.1
Transportation                                           40.4                 35.4
Taxes other than income taxes                             2.1                  3.0
Other                                                     2.1                  0.6
Operating income                                         35.3                 54.4
Other income (expense):
Interest expense                                        (26.2 )              (24.8 )
Debt extinguishment costs                               (89.6 )                  -
Realized gain (loss) on derivative instruments            6.6                 (8.6 )
Unrealized gain on derivative instruments                24.6                 24.5
Other                                                    (0.3 )                0.7
Total other expense                                     (84.9 )               (8.2 )
Net income (loss) before income taxes                   (49.6 )               46.2
Income tax expense                                        0.2                  0.2
Net income (loss)                              $        (49.8 )     $         46.0
EBITDA                                         $         96.4       $        100.3
Adjusted EBITDA                                $         82.7       $         80.0
Distributable Cash Flow                        $         49.4       $         26.4

Non-GAAP Financial Measures
We include in this Quarterly Report the non-GAAP financial measures EBITDA, Adjusted EBITDA and Distributable Cash Flow, and provide reconciliations of EBITDA, Adjusted EBITDA and Distributable Cash Flow to net income (loss) and net cash provided by (used in) operating activities, our most directly comparable financial performance and liquidity measures calculated and presented in accordance with GAAP.
EBITDA, Adjusted EBITDA and Distributable Cash Flow are used as supplemental financial measures by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:
•the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; . . .

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