e10vq
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2011
OR
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o |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR THE SECURITIES EXCHANGE ACT OF 1934 |
FOR THE TRANSITION PERIOD FROM TO
Commission File number 000-51734
Calumet Specialty Products Partners, L.P.
(Exact Name of Registrant as Specified in Its Charter)
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Delaware
(State or Other Jurisdiction of
Incorporation or Organization)
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37-1516132
(I.R.S. Employer
Identification Number) |
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2780 Waterfront Parkway East Drive, Suite 200
Indianapolis, Indiana
(Address of principal executive officers)
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46214
(Zip code) |
Registrants telephone number including area code (317) 328-5660
Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Registration S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files).
Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange Act. (Check one):
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Large accelerated filer o
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Accelerated filer þ
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Non-accelerated filer o
(Do not check if a smaller reporting company)
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Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Act). Yes o No þ
At November 4, 2011, there were 51,529,778 common units outstanding.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
QUARTERLY REPORT
For the Three and Nine Months Ended September 30, 2011
Table of Contents
2
FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q (this Quarterly Report) includes certain forward-looking
statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the
Securities Act) and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange
Act). These statements can be identified by the use of forward-looking terminology including
may, intend, believe, expect, anticipate, estimate, continue, or other similar words.
The statements regarding (i) estimated capital expenditures as a result of the required audits or
required operational changes included in our settlement with the Louisiana Department of
Environmental Quality (LDEQ) or other environmental and regulatory liabilities, (ii) our
anticipated levels of, use and effectiveness of derivatives to mitigate our exposure to crude oil
price changes and fuel products price changes, (iii) the estimated purchase price, future benefits
and risks and all other discussion with respect to the Superior Acquisition (as defined in this
Quarterly Report) and (iv) our ability to meet our financial commitments, minimum quarterly
distributions to our unitholders, debt service obligations, credit agreement covenants,
contingencies and anticipated capital expenditures, as well as other matters discussed in this
Quarterly Report that are not purely historical data, are forward-looking statements. These forward-looking statements are based on
our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that
these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will
be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our
forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements
involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to
differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual
results to differ materially from those in the forward-looking statements include, but are not limited to:
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our plans, objectives, expectations and intentions with respect to the future operations
of the Superior refinery and associated assets; |
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our ability to meet our expectations with respect to our future financial results after the Superior
Acquisition; |
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our ability to successfully integrate the Superior Business (as defined in this Quarterly Report); |
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the overall demand for specialty hydrocarbon products, fuels and other refined products; |
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our ability to produce specialty products and fuels that meet our customers unique and precise specifications; |
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the impact of fluctuations and rapid increases or decreases in crude oil and crack spread
prices, including the resulting impact on our liquidity; |
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the results of our hedging and other risk management activities; |
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our ability to comply with financial covenants contained in our debt instruments; |
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the availability of, and our ability to consummate, acquisition or combination
opportunities and the impact of any completed acquisitions; |
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labor relations; |
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our access to capital to fund expansions, acquisitions and our working capital needs and
our ability to obtain debt or equity financing on satisfactory terms; |
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successful integration and future performance of acquired assets, businesses or
third-party product supply and processing relationships; |
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environmental liabilities or events that are not covered by an indemnity, insurance or
existing reserves; |
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maintenance of our credit ratings and ability to receive open credit lines from our
suppliers; |
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demand for various grades of crude oil and resulting changes in pricing conditions; |
3
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fluctuations in refinery capacity; |
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the effects of competition; |
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continued creditworthiness of, and performance by, counterparties; |
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the impact of current and future laws, rulings and governmental regulations, including
guidance related to the Dodd-Frank Wall Street Reform and Consumer Protection Act; |
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shortages or cost increases of power supplies, natural gas, materials or labor; |
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hurricane or other weather interference with business operations; |
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fluctuations in the debt and equity markets; |
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accidents or other unscheduled shutdowns; and |
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general economic, market or business conditions. |
For additional information regarding known
material factors that could cause our actual results to differ from our projected results, please see (1) Part I, Item 3 Quantitative
and Qualitative Disclosures About Market Risk and Part II, Item 1A. Risk Factors elsewhere in this report and (2) Part I,
Item 1A. Risk Factors in our Annual Report on Form 10-K for the fiscal year ended December 31, 2011 (2010 Annual Report).
All subsequent written and oral forward-looking statements attributable to us or to persons
acting on our behalf are expressly qualified in their entirety by the foregoing. We undertake no
obligation to publicly release the results of any revisions to any such forward-looking statements
that may be made to reflect events or circumstances after the date of this report or to reflect the
occurrence of unanticipated events.
References in this Quarterly Report to Calumet Specialty Products Partners, L.P., the
Company, we, our, us or like terms refer to Calumet Specialty Products Partners, L.P. and
its subsidiaries. References in this Quarterly Report to our general partner refer to Calumet GP,
LLC, the general partner of the Company.
4
PART I
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Item 1. |
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Financial Statements |
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS
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September 30, 2011 |
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December 31, 2010 |
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(Unaudited) |
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(In thousands, except unit data) |
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ASSETS |
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Current assets: |
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Cash and cash equivalents |
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$ |
66 |
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$ |
37 |
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Accounts receivable: |
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Trade |
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198,888 |
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157,185 |
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Other |
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34,106 |
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776 |
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232,994 |
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157,961 |
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Inventories |
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446,506 |
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147,110 |
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Prepaid expenses and other current assets |
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4,547 |
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1,909 |
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Deposits |
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2,520 |
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2,094 |
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Total current assets |
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686,633 |
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309,111 |
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Property, plant and equipment, net |
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843,111 |
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612,433 |
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Goodwill |
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48,335 |
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48,335 |
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Other intangible assets, net |
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24,423 |
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29,666 |
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Other noncurrent assets, net |
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39,094 |
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17,127 |
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Total assets |
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$ |
1,641,596 |
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$ |
1,016,672 |
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LIABILITIES AND PARTNERS CAPITAL |
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Current liabilities: |
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Accounts payable |
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$ |
232,589 |
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$ |
146,730 |
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Accounts payable related party |
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1,488 |
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27,985 |
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Accrued salaries, wages and benefits |
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11,888 |
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7,559 |
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Taxes payable |
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8,850 |
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7,174 |
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Other current liabilities |
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7,544 |
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16,605 |
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Current portion of long-term debt |
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749 |
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4,844 |
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Derivative liabilities |
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160,861 |
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32,814 |
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Total current liabilities |
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423,969 |
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243,711 |
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Pension and postretirement benefit obligations |
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25,349 |
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9,168 |
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Other long-term liabilities |
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1,062 |
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1,083 |
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Long-term debt, less current portion |
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642,293 |
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364,431 |
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Total liabilities |
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1,092,673 |
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618,393 |
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Commitments and contingencies (Note 5) |
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Partners capital: |
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Limited partners interest (50,779,778 units
and 35,279,778 units issued and outstanding
at September 30, 2011 and December 31, 2010,
respectively) |
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652,229 |
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407,773 |
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General partners interest |
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23,373 |
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18,125 |
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Accumulated other comprehensive loss |
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(126,679 |
) |
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(27,619 |
) |
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Total partners capital |
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548,923 |
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398,279 |
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Total liabilities and partners capital |
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$ |
1,641,596 |
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$ |
1,016,672 |
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See accompanying notes to unaudited condensed consolidated financial statements.
5
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
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For the Three Months Ended |
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For the Nine Months Ended |
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September 30, |
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September 30, |
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2011 |
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2010 |
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2011 |
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2010 |
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(In thousands, except per unit data) |
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Sales |
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$ |
777,780 |
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$ |
595,273 |
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$ |
2,116,790 |
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$ |
1,594,542 |
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Cost of sales |
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681,179 |
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533,167 |
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1,922,760 |
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1,451,141 |
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Gross profit |
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96,601 |
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62,106 |
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194,030 |
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143,401 |
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Operating costs and expenses: |
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Selling, general and administrative |
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14,148 |
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7,403 |
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35,143 |
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22,894 |
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Transportation |
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23,696 |
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23,258 |
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69,462 |
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63,460 |
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Taxes other than income taxes |
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1,683 |
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1,308 |
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4,246 |
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3,431 |
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Insurance recoveries |
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(8,698 |
) |
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Other |
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543 |
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565 |
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1,781 |
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1,373 |
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Operating income |
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56,531 |
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29,572 |
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|
92,096 |
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52,243 |
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Other income (expense): |
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Interest expense |
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(12,577 |
) |
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(7,794 |
) |
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(30,602 |
) |
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(22,505 |
) |
Debt extinguishment costs |
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(15,130 |
) |
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Realized loss on derivative instruments |
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(3,814 |
) |
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(2,288 |
) |
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(5,798 |
) |
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(8,147 |
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Unrealized gain (loss) on derivative instruments |
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(20,335 |
) |
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1,931 |
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(23,876 |
) |
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(13,835 |
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Other |
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45 |
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(121 |
) |
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148 |
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(170 |
) |
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Total other expense |
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(36,681 |
) |
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(8,272 |
) |
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(75,258 |
) |
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(44,657 |
) |
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Net income before income taxes |
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19,850 |
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21,300 |
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16,838 |
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7,586 |
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Income tax expense |
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236 |
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79 |
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|
674 |
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|
339 |
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Net income |
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$ |
19,614 |
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$ |
21,221 |
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$ |
16,164 |
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$ |
7,247 |
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Allocation of net income: |
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Net income |
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$ |
19,614 |
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$ |
21,221 |
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$ |
16,164 |
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$ |
7,247 |
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Less: |
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General partners interest in net income |
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392 |
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|
424 |
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323 |
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|
145 |
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General partners incentive distribution rights |
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40 |
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40 |
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Net income attributable to limited partners |
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$ |
19,182 |
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$ |
20,797 |
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$ |
15,801 |
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$ |
7,102 |
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Weighted average limited partner units outstanding basic |
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41,828 |
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35,337 |
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39,352 |
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|
35,332 |
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Weighted average limited partner units outstanding
diluted |
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41,837 |
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35,352 |
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|
39,368 |
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|
35,351 |
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Limited partners interest basic and diluted net income
per unit |
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$ |
0.46 |
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$ |
0.59 |
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$ |
0.40 |
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$ |
0.20 |
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Cash distributions declared per limited partner unit |
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$ |
0.50 |
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$ |
0.46 |
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$ |
1.47 |
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$ |
1.37 |
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See accompanying notes to unaudited condensed consolidated financial statements.
6
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS CAPITAL
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Accumulated Other |
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Partners Capital |
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Comprehensive |
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General |
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Limited Partners |
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Loss |
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Partner |
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Common |
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Subordinated |
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Total |
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(In thousands) |
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Balance at December 31, 2010 |
|
$ |
(27,619 |
) |
|
$ |
18,125 |
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$ |
390,843 |
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$ |
16,930 |
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$ |
398,279 |
|
Distributions to partners |
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|
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|
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(1,126 |
) |
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|
(49,115 |
) |
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|
(6,141 |
) |
|
|
(56,382 |
) |
Subordinated unit conversion |
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|
|
|
|
|
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|
10,789 |
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(10,789 |
) |
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Comprehensive loss: |
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|
|
|
|
|
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Net income |
|
|
|
|
|
|
363 |
|
|
|
15,801 |
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|
|
|
|
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|
16,164 |
|
Cash flow hedge loss reclassified to net income |
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|
81,294 |
|
|
|
|
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|
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|
|
|
|
|
|
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|
81,294 |
|
Change in fair value of cash flow hedges |
|
|
(180,537 |
) |
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|
|
|
|
|
(180,537 |
) |
Defined benefit pension and retiree health benefit plans |
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|
183 |
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|
|
|
|
|
183 |
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|
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Comprehensive loss |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(82,896 |
) |
Issuances of common units, net |
|
|
|
|
|
|
|
|
|
|
281,870 |
|
|
|
|
|
|
|
281,870 |
|
Contributions from Calumet GP, LLC |
|
|
|
|
|
|
6,011 |
|
|
|
|
|
|
|
|
|
|
|
6,011 |
|
Units repurchased for phantom unit grants |
|
|
|
|
|
|
|
|
|
|
(620 |
) |
|
|
|
|
|
|
(620 |
) |
Issuance of phantom units |
|
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|
|
|
|
|
|
|
|
717 |
|
|
|
|
|
|
|
717 |
|
Amortization of vested phantom units |
|
|
|
|
|
|
|
|
|
|
1,944 |
|
|
|
|
|
|
|
1,944 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at September 30, 2011 |
|
$ |
(126,679 |
) |
|
$ |
23,373 |
|
|
$ |
652,229 |
|
|
$ |
|
|
|
$ |
548,923 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to unaudited condensed consolidated financial statements.
7
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
For the Nine Months Ended |
|
|
|
September 30, |
|
|
|
2011 |
|
|
2010 |
|
|
|
(In thousands) |
|
Operating activities |
|
|
|
|
|
|
|
|
Net income |
|
$ |
16,164 |
|
|
$ |
7,247 |
|
Adjustments to reconcile net income to net cash provided by (used in) operating activities: |
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
43,644 |
|
|
|
44,410 |
|
Amortization of turnaround costs |
|
|
8,288 |
|
|
|
6,639 |
|
Non-cash interest expense |
|
|
2,363 |
|
|
|
2,879 |
|
Non-cash debt extinguishment costs |
|
|
14,401 |
|
|
|
|
|
Provision for doubtful accounts |
|
|
255 |
|
|
|
74 |
|
Unrealized loss on derivative instruments |
|
|
23,876 |
|
|
|
13,835 |
|
Other non-cash activities |
|
|
1,830 |
|
|
|
1,467 |
|
Changes in assets and liabilities: |
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(44,714 |
) |
|
|
(42,004 |
) |
Inventories |
|
|
(109,787 |
) |
|
|
(12,964 |
) |
Prepaid expenses and other current assets |
|
|
(1,926 |
) |
|
|
(1,103 |
) |
Derivative activity |
|
|
4,928 |
|
|
|
849 |
|
Turnaround costs |
|
|
(8,849 |
) |
|
|
(9,041 |
) |
Other assets |
|
|
(197 |
) |
|
|
|
|
Deposits |
|
|
(426 |
) |
|
|
4,767 |
|
Accounts payable |
|
|
54,916 |
|
|
|
68,995 |
|
Accrued salaries, wages and benefits |
|
|
2,917 |
|
|
|
(419 |
) |
Taxes payable |
|
|
1,676 |
|
|
|
769 |
|
Other liabilities |
|
|
(9,082 |
) |
|
|
1,492 |
|
Pension and postretirement benefit obligations |
|
|
(836 |
) |
|
|
(190 |
) |
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities |
|
|
(559 |
) |
|
|
87,702 |
|
Investing activities |
|
|
|
|
|
|
|
|
Additions to property, plant and equipment |
|
|
(30,667 |
) |
|
|
(27,310 |
) |
Proceeds from insurance recoveries equipment |
|
|
1,942 |
|
|
|
|
|
Superior Acquisition, including a $30,574 receivable from seller |
|
|
(441,626 |
) |
|
|
|
|
Proceeds from sale of equipment |
|
|
219 |
|
|
|
201 |
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(470,132 |
) |
|
|
(27,109 |
) |
Financing activities |
|
|
|
|
|
|
|
|
Proceeds from borrowings revolving credit facility |
|
|
1,152,898 |
|
|
|
745,722 |
|
Repayments of borrowings revolving credit facility |
|
|
(1,107,730 |
) |
|
|
(753,749 |
) |
Repayments of borrowings term loan credit facility |
|
|
(367,385 |
) |
|
|
(2,888 |
) |
Payments on capital lease obligations |
|
|
(802 |
) |
|
|
(1,023 |
) |
Proceeds from issuances of common units, net |
|
|
281,870 |
|
|
|
793 |
|
Proceeds from 2019 senior notes offerings |
|
|
586,000 |
|
|
|
|
|
Debt issuance costs |
|
|
(23,140 |
) |
|
|
|
|
Contributions from Calumet GP, LLC |
|
|
6,011 |
|
|
|
18 |
|
Common units repurchased for vested phantom unit grants |
|
|
(620 |
) |
|
|
(248 |
) |
Distributions to partners |
|
|
(56,382 |
) |
|
|
(49,179 |
) |
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
470,720 |
|
|
|
(60,554 |
) |
|
|
|
|
|
|
|
Net increase in cash and cash equivalents |
|
|
29 |
|
|
|
39 |
|
Cash and cash equivalents at beginning of period |
|
|
37 |
|
|
|
49 |
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
66 |
|
|
$ |
88 |
|
|
|
|
|
|
|
|
Supplemental disclosure of cash flow information |
|
|
|
|
|
|
|
|
Interest paid |
|
$ |
13,381 |
|
|
$ |
19,635 |
|
|
|
|
|
|
|
|
Income taxes paid |
|
$ |
548 |
|
|
$ |
138 |
|
|
|
|
|
|
|
|
See accompanying notes to unaudited condensed consolidated financial statements.
8
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands)
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
September 30, 2011, the Company had 50,779,778 common units and 1,036,322 general partner units
outstanding. The number of common units outstanding includes 13,066,000 common units that converted
from subordinated units on February 16, 2011. There are no longer any subordinated units
outstanding. Refer to Note 10 for additional information. The general partner owns 2% of the
Company while the remaining 98% is owned by limited partners. The Company is engaged in the
production and marketing of crude oil-based specialty lubricating oils, white mineral oils,
solvents, petrolatums, waxes and fuels. The Company owns facilities located in Shreveport,
Louisiana (Shreveport); Superior, Wisconsin (Superior); Princeton, Louisiana (Princeton);
Cotton Valley, Louisiana (Cotton Valley); Karns City, Pennsylvania (Karns City) and Dickinson,
Texas (Dickinson) and terminals located in Burnham, Illinois (Burnham); Rhinelander, Wisconsin
(Rhinelander); Crookston, Minnesota (Crookston) and Proctor, Minnesota (Duluth).
The unaudited condensed consolidated financial statements of the Company as of September 30,
2011 and for the three and nine months ended September 30, 2011 and 2010 included herein have been
prepared, without audit, pursuant to the rules and regulations of the Securities and Exchange
Commission (SEC). Certain information and disclosures normally included in the consolidated
financial statements prepared in accordance with generally accepted accounting principles (GAAP)
in the United States of America (the U.S.) have been condensed or omitted pursuant to such rules
and regulations, although the Company believes that the following disclosures are adequate to make
the information presented not misleading. These unaudited condensed consolidated financial
statements reflect all adjustments that, in the opinion of management, are necessary to present
fairly the results of operations for the interim periods presented. All adjustments are of a normal
nature, unless otherwise disclosed. The results of operations for the three and nine months ended
September 30, 2011 are not necessarily indicative of the results that may be expected for the year
ending December 31, 2011. These unaudited condensed consolidated financial statements should be
read in conjunction with the Companys 2010 Annual Report. The Company issued these unaudited
condensed consolidated financial statements by filing them with the SEC and has evaluated
subsequent events up to the time of filing. Refer to Note 16 for additional information on these
subsequent events.
2. New Accounting Pronouncements
In January 2010, the FASB issued ASU No. 2010-06, Improving Disclosures About Fair Value
Measurements (ASU 2010-06), which amends ASC No. 820, Fair Value Measurements and Disclosures
to add new requirements for disclosures about transfers into and out of Levels 1 and 2 and separate
disclosures about purchases, sales, issuances and settlements relating to Level 3 measurements. ASU
2010-06 also clarifies existing fair value disclosures about the level of disaggregation and about
inputs and valuation techniques used to measure fair value. ASU 2010-06 is effective for the first
reporting period (including interim periods) beginning after December 15, 2009, except for the
requirement to provide the Level 3 activity of purchases, sales, issuances and settlements on a
gross basis, which is effective for fiscal years (including interim periods) beginning after
December 15, 2010. Effective January 1, 2010, the Company adopted ASU 2010-06 standard relating to
disclosures about transfers in and out of Level 1 and 2 and the inputs and valuation techniques
used to measure fair value. Effective January 1, 2011, the Company adopted ASU 2010-06 standard
relating to the requirement to provide the Level 3 activity of purchases, sales, issuances and
settlements on a gross basis. The adoption of ASU 2010-06 did not have a material impact on the
Companys financial position, results of operations or cash flows.
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 Boards 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 is effective for the first reporting period (including interim periods) beginning after
December 15, 2011. The Company is in process of evaluating the impact of the adoption of ASU
2011-04 on the Companys financial statements.
In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (ASC Topic 220):
Presentation of Comprehensive Income, (ASU 2011-05) which amends current comprehensive income
guidance. This accounting update eliminates the option to present the components of other
comprehensive income as part of the statement of partners capital. Instead, the Company must
report comprehensive
9
income in either a single continuous statement of comprehensive income which
contains two sections, net income and other comprehensive income, or in two separate but
consecutive statements. ASU 2011-05 will be effective for public companies during the interim and
annual periods beginning after December 15, 2011 with early adoption permitted. The adoption of ASU
2011-05 will not have an impact on the Companys consolidated financial position, results of
operations or cash flows as it only requires a change in the format of the current presentation.
In September 2011, the FASB issued ASU No. 2011-09, Intangibles Goodwill and Other (Topic
360): Testing Goodwill for Impairment, (ASU 2011-09). ASU 2011-09 allows companies to have the
option to first assess 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. If after considering the totality
of events and circumstances an entity determines it is not more likely than not that the fair value
of a reporting unit less than its carrying amount, then performing the two-step impairment test is
unnecessary. ASU 2011-09 is effective for annual and interim goodwill impairment tests performed
for fiscal years beginning after December 15, 2011, however, early adoption is permitted, including
for annual and interim goodwill impairment tests performed as of a date before September 15, 2011.
The Company will early adopt the new authoritative guidance in the fourth quarter of 2011 in
connection with its annual impairment test.
3. 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 $411,052 excluding certain
customary post-closing purchase price adjustments (Superior Acquisition). The Superior
Acquisition was financed by a combination of (i) net proceeds of $193,621 from the Companys
September 2011 public offering of common units, (ii) net proceeds of $180,348 from the Companys
September 2011 private placement of 9 3/8% senior notes due May 1, 2019 and (iii) borrowings under
the revolving credit facility. The Company acquired the following (collectively, the Superior
Business):
|
|
|
Murphy Oils refinery located in Superior, Wisconsin and associated inventories; |
|
|
|
|
Superiors wholesale marketing business and related assets, including certain owned
or leased Murphy Oil product terminals located in Superior and Rhinelander, Wisconsin,
Duluth and Crookston and Proctor, Minnesota and Toole, Utah and associated inventories
and logistics assets located at each of the foregoing facilities; and |
|
|
|
|
Murphy Oils SPUR branded gasoline wholesale business and related assets. |
The Superior refinery produces gasoline, diesel, asphalt and specialty petroleum products that
are marketed in the Midwest region of the U.S., including the surrounding border states, and
Canada. 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 and through its own leased and owned product terminals located in Superior and Rhinelander,
Wisconsin, Duluth, Crookston and Proctor, Minnesota and Toole, Utah. 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 the Companys refining business, as the Companys current total refining
throughput capacity has increased by 50% to 135,000 barrels per day.
As a result of the Superior Acquisition on September 30, 2011, the assets and liabilities
previously held by Murphy Oil have been included in the Companys condensed consolidated balance
sheet, while the unaudited condensed consolidated statements of operations for the Company do not
contain the results of the Superior Acquisition, as there were no related sales in the quarter
ended September 30, 2011. In connection with the Superior Acquisition, the Company incurred
acquisition costs during the third quarter of 2011 of approximately $2,072 which are reflected in
selling, general and administrative expenses in the unaudited condensed consolidated statements of
operations.
10
The Superior 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. The preliminary allocation of the aggregate purchase price is as follows:
|
|
|
|
|
|
|
Allocation of |
|
|
|
Purchase Price |
|
Inventories |
|
$ |
189,609 |
|
Prepaid expenses and other current assets |
|
|
713 |
|
Property, plant and equipment |
|
|
238,705 |
|
Accrued salaries, wages and benefits |
|
|
(775 |
) |
Pension and postretirement benefit obligations |
|
|
(17,200 |
) |
|
|
|
|
Total purchase price |
|
$ |
411,052 |
|
|
|
|
|
The following unaudited pro forma financial information reflects the consolidated results of
operations of the Company as if the Superior Acquisition had taken place on January 1, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
Sales |
|
$ |
1,225,692 |
|
|
$ |
944,856 |
|
|
$ |
3,233,347 |
|
|
$ |
2,414,460 |
|
Net income |
|
$ |
70,418 |
|
|
$ |
32,490 |
|
|
$ |
79,556 |
|
|
$ |
2,094 |
|
Limited partners interest net income per unit basic and diluted |
|
$ |
1.38 |
|
|
$ |
0.64 |
|
|
$ |
1.56 |
|
|
$ |
0.04 |
|
The Companys historical financial information was adjusted to give effect to the pro forma
events that were directly attributable to the Superior Acquisition. 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.
The unaudited pro forma financial information reflects interest expense as a result of the issuance of the 2019
Notes, amending and restating the revolving credit facility, additional borrowings under the revolving credit facility
to fund a portion of the Superior Acquisition and the repayment of borrowings under the senior secured first lien term loan from the net proceeds of the 2019 Notes issued in April 2011. Additionally, the unaudited pro forma financial information reflects adjustments to depreciation expense as a result of the addition of fixed assets related to the Superior
Acquisition at their estimated fair value, as well as adjustments to eliminate Superiors income tax expense.
4. Inventories
The cost of inventories is determined 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.
Inventories consist of the following, including estimated inventories of approximately
$189,609 as of September 30, 2011, related to the Superior Acquisition:
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2011 |
|
|
2010 |
|
Raw materials |
|
$ |
120,150 |
|
|
$ |
12,885 |
|
Work in process |
|
|
89,494 |
|
|
|
49,006 |
|
Finished goods |
|
|
236,862 |
|
|
|
85,219 |
|
|
|
|
|
|
|
|
|
|
$ |
446,506 |
|
|
$ |
147,110 |
|
|
|
|
|
|
|
|
The replacement cost of these inventories, based on current market values, would have been
$75,712 and $55,855 higher as of September 30, 2011 and December 31, 2010, respectively. For the
three and nine months ended September 30, 2010, the Company recorded $3,488 and $4,371,
respectively, of gains in cost of sales in the unaudited condensed consolidated statements of
operations due to the liquidation of lower cost inventory layers. No gains from the liquidation
of lower cost inventory layers have been recorded in 2011.
11
5. Commitments and 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 LDEQ,
the U.S. Environmental Protection Agency (EPA), the Internal Revenue Service and the Occupational
Safety and Health Administration (OSHA), as the result of audits or reviews of the Companys
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 nine months ended September
30, 2011 in the unaudited condensed consolidated statements of operations. 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
unaudited condensed 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, regional, state, and local laws and regulations
governing the discharge of materials into the environment or otherwise relating to environmental
protection. These laws and regulations can impair the Companys operations that affect the
environment in many ways, such as requiring the acquisition of permits to conduct regulated
activities, restricting the manner in which the Company may release materials into the environment,
requiring remedial activities or capital expenditures to mitigate pollution from former or current
operations, and imposing substantial liabilities for pollution resulting from its operations.
Certain environmental laws impose joint and several, strict liability for costs required to
remediate and restore sites where petroleum hydrocarbons, wastes, or other materials have been
released or disposed.
The Superior refinery is the subject of a consent decree (the Consent Decree) with the U.S.
Environmental Protection Agency (EPA) and the Wisconsin Department of Natural Resources (WDNR),
which requires, among other things, reductions in air emissions and the reporting of certain
emissions to EPA and WDNR. In connection with the Superior Acquisition, the Company became a party
to this consent decree. Equipment upgrades, other discrete tasks and annual penalties to comply
with the Consent Decree are expected to cost about $4,470, but compliance with other aspects of the
Consent Decree could result in additional, substantial expenditures. Any failure to comply with
the Consent Decree, as well as certain emissions from the facility, will also subject the Company
to stipulated penalties, which could be substantial. The Company may incur substantial costs for
performance of additional environmental and safety-related projects at the Superior refinery
including, but not limited to:
|
|
|
the installation of additional process equipment to comply with EPA fuel content
regulations at a cost to the Company of $2,910; |
|
|
|
|
the purchase of credits to comply with EPA fuel content regulations until such time as
the additional process equipment is installed and brought online; |
|
|
|
|
the monitoring and remediation of historical contamination at costs of about $200 per
year; |
|
|
|
|
the upgrade of treatment equipment or pursuit of other remedies as necessary to comply
with new effluent discharge limits in a Clean Water Act permit renewal that is currently
pending; and |
|
|
|
|
the implementation of various voluntary programs at the Superior refinery, such as
removal of asbestos-containing materials or enhancement of process safety or other
maintenance practices. |
On December 23, 2010, the Company entered into a settlement agreement with the LDEQ regarding
(i) the Companys voluntary participation in the LDEQs Small Refinery and Single Site Refinery
Initiative, and (ii) certain alleged past violations for which the LDEQ had previously initiated
enforcement including (A) May 2001, December 2002 and December 2004 notifications received by the
Cotton Valley refinery from the LDEQ regarding several alleged violations of various air emission
regulations as well as alleged violations for the construction of a multi-tower pad and associated
pump pads without a permit issued by the agency, and (B) an August 2005 notification received by
the Princeton refinery from the LDEQ regarding alleged violations of air emissions regulations.
The LDEQs Small Refinery and Single Site Refinery Initiative is patterned after the EPAs
National Petroleum Refinery Initiative, which is a coordinated, integrated compliance and
enforcement strategy to address federal Clean Air Act compliance issues at the nations largest
petroleum refineries. The agreement, voluntarily entered into by the Company, requires the Company
to make a $1,000 payment to the LDEQ and complete beneficial environmental programs and implement
emissions reduction projects at the Companys Shreveport, Cotton Valley and Princeton refineries.
12
The Company estimates implementation of these requirements will result in approximately $11,000 to
$15,000 of capital expenditures, expenditures related to additional personnel and environmental
studies over the next five years. This agreement also fully settles the aforementioned alleged
environmental and permit violations at the Companys Cotton Valley and Princeton refineries and
stipulates that no further civil penalties over alleged past violations at those refineries will be
pursued by the LDEQ. The required investments are expected to include projects resulting in (i)
nitrogen oxide and sulfur dioxide emission reductions from heaters and boilers and the application
of New Source Performance Standards for sulfur recovery plants and flaring devices, (ii) control of
incidents related to acid gas flaring, tail gas and hydrocarbon flaring, (iii) electrical
reliability improvements to reduce flaring, (iv) flare refurbishment at the Shreveport refinery,
(v) enhancement of the Benzene Waste National Emissions Standards for Hazardous Air Pollutants
programs and the Leak Detection and Repair programs at the Companys three Louisiana refineries and
(vi) Title V audits and targeted audits of certain regulatory compliance programs. During
negotiations with the LDEQ, the Company voluntarily initiated projects for certain of these
requirements prior to the settlement with the LDEQ, and currently anticipates completion of these
projects over the next five years. These capital investment requirements will be incorporated into
the Companys annual capital expenditures budget and the Company does not expect any additional
capital expenditures as a result of the required audits or required operational changes included in
the settlement to have a material adverse effect on the Companys financial results or operations.
Before the terms of this settlement agreement are deemed final, they will require the concurrence
of the Louisiana Attorney General, such concurrence anticipated to be granted during the fourth
quarter of 2011.
Voluntary remediation of subsurface contamination is in process at each of the Companys
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 Companys financial condition. However, such costs are often unpredictable and,
therefore, there can be no assurance that the future costs will not become material. The Company
incurred approximately $266 of such capital expenditures at its Cotton Valley refinery during the
first nine months of 2011 and completed such capital expenditures planned for 2011 at its Cotton
Valley refinery. The Company incurred approximately $541 of such capital expenditures at its Cotton
Valley refinery during 2010.
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 Companys 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.
In addition, the Company is indemnified by Murphy Oil for specified environmental liabilities
including: (i) certain obligations arising out of the Consent Decree (including payment of a civil
penalty required under the Consent Decree), (ii) certain liabilities arising in connection with
Murphy Oils 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.
Health, Safety and Maintenance
The Company is subject to various laws and regulations relating to occupational health and
safety, including OSHA and comparable state laws. These laws and the implementing regulations
strictly govern the protection of the health and safety of employees. In addition, OSHAs hazard
communication standard requires that information be maintained about hazardous materials used or
produced in the Companys operations and that this information be provided to employees,
contractors, state and local government authorities and customers. The Company maintains safety,
training and maintenance programs as part of its ongoing efforts to ensure compliance with
applicable laws and regulations. The Companys compliance with applicable health and safety laws
and regulations has required, and continues to require, substantial expenditures. 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 Companys 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 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. The Company expects to incur between
$5,000 and $8,000 of capital expenditures in total
13
during 2011, 2012 and 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. The Company believes that its operations are in substantial compliance with OSHA and
similar state laws.
Beginning in February 2010, OSHA conducted an inspection of the Shreveport refinerys process
safety management program under OSHAs National Emphasis Program, which is targeting all U.S.
refineries for review. On August 19, 2010, OSHA issued a Citation and Notification of Penalty (the
Shreveport Citation) to the Company as a result of the Shreveport inspection, which included a
proposed civil penalty amount of $173. The Company contested the Shreveport Citation and associated
penalty amount and agreed to a final penalty amount of $119 that was paid in January 2011.
Similarly, OSHA conducted an inspection of the Cotton Valley refinerys process safety management
program under OSHAs National Emphasis Program in the first quarter of 2011. 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.
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 September 30, 2011 and December 31, 2010, the
Company had outstanding standby letters of credit of $207,960 and $90,725, respectively, under its
senior secured revolving credit facility, which was amended and restated on June 24, 2011 (the
revolving credit facility). Refer to Note 6 for additional information. The maximum amount of
letters of credit the Company can issue at September 30, 2011 is subject to borrowing base
restrictions, 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 ($850,000 at September 30, 2011) then in effect. At December 31, 2010, the maximum amount of letters of credit the Company could issue was
subject to borrowing base restrictions, with a letter of credit sublimit of $300,000.
As of September 30, 2011 and December 31, 2010, the Company had availability to issue letters
of credit of $271,490 and $145,454, respectively, under its revolving credit facility. As discussed
in Note 6, as of September 30, 2011 the outstanding standby letters of credit issued under the
revolving credit facility included a $25,000 letter of credit to support a portion of its fuel
products hedging program.
6. Long-Term Debt
Long-term debt consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2011 |
|
|
2010 |
|
Borrowings under senior secured first lien term loan with third-party lenders, extinguished in 2011 |
|
$ |
|
|
|
$ |
367,385 |
|
Borrowings under senior secured revolving credit agreement with third-party lenders, amended and
restated in June 2011 |
|
|
|
|
|
|
10,832 |
|
Borrowings under amended and restated senior secured revolving credit agreement with third-party
lenders, interest at prime plus 1.25% (4.50% at September 30, 2011), interest payments monthly,
borrowings due June 2016 |
|
|
56,000 |
|
|
|
|
|
Borrowings under 2019 Notes, interest at a fixed rate of 9.375% at September 30, 2011, interest
payments semiannually, borrowings due May 2019, effective interest rate of 9.74% for the three months
ended September 30, 2011 |
|
|
600,000 |
|
|
|
|
|
Capital lease obligations, at various interest rates, interest and principal payments quarterly through
November 2013 |
|
|
1,042 |
|
|
|
1,781 |
|
Less unamortized discount on senior secured first lien term loan with third-party lenders, extinguished
in 2011 |
|
|
|
|
|
|
(10,723 |
) |
Less unamortized discount on 2019 Notes issued in September 2011 |
|
|
(14,000 |
) |
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt |
|
|
643,042 |
|
|
|
369,275 |
|
Less current portion of long-term debt |
|
|
749 |
|
|
|
4,844 |
|
|
|
|
|
|
|
|
|
|
$ |
642,293 |
|
|
$ |
364,431 |
|
|
|
|
|
|
|
|
14
During the three months ended June 30, 2011, the Company restructured the majority of its
outstanding long-term debt. The Company issued and sold $400,000 in aggregate principal amount 9
3/8% senior notes due May 1, 2019 (the 2019 Notes issued in April 2011), amended its then current
senior secured revolving credit agreement to allow for the issuance of the 2019 Notes, and used the
majority of the proceeds from the 2019 Notes to repay borrowings under, and subsequently
extinguish, the senior secured first lien term loan. The Company also amended certain of its master
derivative contracts and entered into a collateral sharing agreement with its hedging
counterparties. Further, the Company amended and restated its revolving credit agreement to
increase the credit facility from $375,000 to $550,000, as well as amend covenants and contractual
terms. Each of these activities is discussed in further detail in the following paragraphs.
During the three months ended September 30, 2011, in connection with the Superior Acquisition,
the Company issued and sold $200,000 in aggregate principal amount 9 3/8% senior notes due May 1,
2019 (the 2019 Notes issued in September 2011 and, together with the 2019 Notes issued in April
2011, the 2019 Notes), amended the collateral sharing agreement with its hedging counterparties
to limit the extent to which forward purchase contracts for physical commodities would be covered
by, and secured under, such agreement and increased the revolving credit facility from $550,000 to
$850,000, subject to borrowing base limitations. A portion of the purchase price of the Superior
Acquisition was financed with the issuance and sale of the 2019 Notes issued in September 2011
together with borrowings under the Companys revolving credit facility. Each of these activities
is discussed in further detail in the following paragraphs.
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 aggregate principal amount of 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
$389,037 net of underwriters fees and expenses, which the Company used to repay in full borrowings
outstanding under its existing senior secured first lien term loan facility, as well as all accrued
interest and fees, and for general partnership purposes.
On September 19, 2011, in connection with the Superior Acquisition, the Company issued and
sold $200,000 in aggregate principal amount of 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
$180,348 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 Quarterly 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 will be 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 guaranteed on a senior unsecured basis by all of the
Companys operating subsidiaries and certain of the Companys future operating subsidiaries.
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:
|
|
|
|
|
Year |
|
Percentage |
|
2015 |
|
|
104.688 |
% |
2016 |
|
|
102.344 |
% |
2017 and at any time thereafter |
|
|
100.000 |
% |
15
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 Companys ability and the ability of certain of the Companys subsidiaries to: (i) sell assets;
(ii) pay distributions on, redeem or repurchase the Companys 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 Companys restricted subsidiaries to the Company; (vii)
consolidate, merge or transfer all or substantially all of the Companys 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 either of Moodys Investors Service, Inc. or Standard & Poors 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 holders 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.
In connection with the 2019 Notes offering on April 21, 2011, the Companys then current
senior secured revolving credit facility was amended on April 15, 2011, to among other things, (i)
permit the issuance of the 2019 Notes issued in April 2011; (ii) upon consummation of the issuance
of the 2019 Notes issued in April 2011 and the termination of the senior secured first lien credit
facility, release the revolving credit facility lenders second priority lien on the collateral
securing the senior secured first lien credit facility and (iii) change the interest rate pricing
on the revolving credit facility.
Registration Rights Agreements
On April 21, 2011 and September 19, 2011, 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 can 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. The Company must use reasonable best efforts to
cause the exchange offer registration statement to become effective by April 20, 2012 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 2019 Notes. If the Company fails to satisfy these obligations on a timely basis, the
annual interest borne by the 2019 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.
Senior Secured First Lien Credit Facility
The Companys $435,000 senior secured first lien credit facility (the term loan facility)
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, as further discussed above. The 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%. Please refer to Amendments to Master
Derivative Contracts below for information on termination of the $50,000 prefunded letter of
credit to support crack spread hedging.
Lenders under the term loan facility generally had a first priority lien on the Companys
fixed assets and a second priority lien on its cash, accounts receivable, inventory and certain
other personal property. The term loan facility required quarterly principal payments of $963
through September 30, 2014, with the remaining balance due at maturity on January 3, 2015.
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
16
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 extinguishment charges related to the write off of the
unamortized debt issuance costs and the unamortized discount associated with the term loan.
Amendments to Master Derivative Contracts
In connection with the termination of the term loan facility and the amendment of the senior
secured revolving credit facility, on April 21, 2011, the Company entered into amendments to
certain of the Companys master derivatives contracts (Amendments) to provide new credit support
arrangements to secure the Companys payment obligations under these contracts following the
termination of the term loan facility and the amendment and restatement of the senior secured
revolving credit facility. Under the new credit support arrangements, the Companys payment
obligations under all of the Companys master derivatives contracts for commodity hedging generally
are secured by a first priority lien on the Companys 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 also issued to one counterparty a $25,000 standby letter of credit
under the revolving credit facility to replace a prefunded $50,000 letter of credit previously
issued under the senior secured first lien credit facility. In the event that such counterpartys
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 party as of September 30, 2011. The Companys master derivatives contracts
and Collateral Trust Agreement continue to impose a number of covenant limitations on the Companys
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 thereto.
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.
Amended and Restated Senior Secured Revolving Credit Facility
On June 24, 2011, the Company entered into an amended and restated senior secured revolving
credit facility (the revolving credit facility), which increased the maximum availability of
credit under the revolving credit facility from $375,000 to $550,000, subject to borrowing base
limitations, and included a $300,000 incremental uncommitted expansion option. On September 30,
2011, in conjunction with the Superior Acquisition, the Company fully exercised the $300,000
expansion option to increase the maximum availability of credit under the revolving credit facility
from $550,000 to $850,000, subject to borrowing base limitations. The revolving credit facility,
which is the Companys primary source of liquidity for cash needs in excess of cash generated from
operations, 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 Companys option. As of September 30,
2011, the margin was 125 basis points for prime and 250 basis points for LIBOR; however, the margin
fluctuates quarterly based on the Companys average availability for additional borrowings under
the revolving credit agreement in the preceding calendar quarter as follows:
|
|
|
|
|
|
|
|
|
Quarterly Average |
|
Margin on Base Rate |
|
Margin on LIBOR |
Availability Percentage |
|
Revolving Loans |
|
Revolving Loans |
≥ 66%
|
|
|
1.00 |
% |
|
|
2.25 |
% |
≥ 33% and < 66%
|
|
|
1.25 |
% |
|
|
2.50 |
% |
< 33%
|
|
|
1.50 |
% |
|
|
2.75 |
% |
17
The borrowing capacity at September 30, 2011 under the revolving credit facility was $535,450.
As of September 30, 2011, the Company had outstanding borrowings under the revolving credit
facility of $56,000, leaving $271,490 available for additional borrowings based on collateral and
specified availability limitations. The lenders under the revolving credit facility have a first
priority lien on the Companys cash, accounts receivable, inventory and certain other personal
property.
The revolving credit facility contains various covenants that limit, among other things, the
Companys 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 Companys 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 credit agreement) (without giving effect to the LC Reserve (as defined in the credit
agreement)) and (b) the credit agreement commitments then in effect and (ii) $46,364, (as 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 credit agreement) of at least 1.0 to 1.0.
As of September 30, 2011, maturities of the Companys long-term debt are as follows:
|
|
|
|
|
Year |
|
Maturity |
|
2011 |
|
$ |
255 |
|
2012 |
|
|
551 |
|
2013 |
|
|
236 |
|
2014 |
|
|
|
|
2015 |
|
|
|
|
Thereafter |
|
|
656,000 |
|
|
|
|
|
Total |
|
$ |
657,042 |
|
|
|
|
|
|
|
|
|
|
18
7. Derivatives
The Company utilizes derivative instruments to minimize its price risk and volatility of cash
flows associated with the purchase of crude oil and natural gas, the sale of fuel products and
interest payments. The Company employs various hedging strategies, which are further discussed
below. The Company does not hold or issue derivative instruments for trading purposes.
The Company recognizes all derivative instruments at their fair values (see Note 9) as either
assets or liabilities on the condensed 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 Companys financial results are subject to the possibility that changes in
the derivatives fair value could result in significant ineffectiveness and potentially no longer
qualify for hedge accounting. The Company recorded the following derivative assets and liabilities
at their fair values as of September 30, 2011 and December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Assets |
|
|
Derivative Liabilities |
|
|
|
September 30, 2011 |
|
|
December 31, 2010 |
|
|
September 30, 2011 |
|
|
December 31, 2010 |
|
Derivative instruments designated as hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel products segment: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil swaps |
|
$ |
|
|
|
$ |
|
|
|
$ |
(87,573 |
) |
|
$ |
134,916 |
|
Gasoline swaps |
|
|
|
|
|
|
|
|
|
|
(2,150 |
) |
|
|
(14,149 |
) |
Diesel swaps |
|
|
|
|
|
|
|
|
|
|
(14,131 |
) |
|
|
(53,744 |
) |
Jet fuel swaps |
|
|
|
|
|
|
|
|
|
|
(55,322 |
) |
|
|
(96,556 |
) |
Interest rate swaps: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,681 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative instruments designated as hedges |
|
|
|
|
|
|
|
|
|
|
(159,176 |
) |
|
|
(32,214 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments not designated as hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel products segment: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jet fuel crack spread collars (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20 |
|
Specialty products segment: (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas swaps |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil swaps |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
662 |
|
Interest rate swaps: (3) |
|
|
|
|
|
|
|
|
|
|
(1,685 |
) |
|
|
(1,282 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative instruments not designated as hedges |
|
|
|
|
|
|
|
|
|
|
(1,685 |
) |
|
|
(600 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative instruments |
|
$ |
|
|
|
$ |
|
|
|
$ |
(160,861 |
) |
|
$ |
(32,814 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The Company entered into jet fuel crack spread collars, which do not qualify for hedge
accounting, to economically hedge its exposure to changes in the jet fuel crack spread. |
|
(2) |
|
The Company enters 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. |
|
(3) |
|
The Company refinanced 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 debt agreement are no longer designated as cash flow hedges. |
To the extent a derivative instrument 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 loss, a component of partners capital in
the condensed consolidated balance sheets, until the underlying transaction hedged is recognized in
the unaudited condensed consolidated statements of operations. The Company accounts for certain
derivatives hedging purchases of crude oil and natural gas, sales of gasoline, diesel and jet fuel
and the payment of interest as cash flow hedges. The derivatives hedging sales and purchases are
recorded to sales and cost of sales, respectively, in the unaudited condensed 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
unaudited condensed 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.
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 unaudited
condensed consolidated statements of operations. Upon the settlement of a derivative not designated
as a cash flow hedge, the gain or loss at
19
settlement is recorded to realized gain (loss) on
derivative instruments in the unaudited condensed 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 would result, in increased
volatility in the Companys financial results. However, even though derivatives may not qualify
for hedge accounting, the Company intends to continue to hold the instruments as management
believes such derivative instruments continue to provide the Company with the opportunity to more
effectively stabilize fuel products margins.
The Company recorded the following amounts in its condensed consolidated balance sheets,
unaudited condensed consolidated statements of operations and its unaudited condensed consolidated
statements of partners capital as of, and for the three months ended, September 30, 2011 and 2010
related to its derivative instruments that were designated as cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of (Gain) |
|
|
|
|
|
|
Amount of Gain (Loss) |
|
|
Loss Reclassified |
|
|
|
|
|
|
Recognized in |
|
|
from Accumulated |
|
|
|
|
|
|
Accumulated Other |
|
|
Other Comprehensive |
|
|
Amount of Loss |
|
|
|
Comprehensive Income (Loss) |
|
|
Income (Loss) into |
|
|
Recognized in Net |
|
|
|
on Derivatives |
|
|
Net Income |
|
|
Income on Derivatives |
|
|
|
(Effective Portion) |
|
|
(Effective Portion) |
|
|
(Ineffective Portion) |
|
|
|
Three Months Ended |
|
|
Location of |
|
|
Three Months Ended |
|
|
|
|
|
|
Three Months Ended |
|
|
|
September 30, |
|
|
(Gain) |
|
|
September 30, |
|
|
Location of |
|
|
September 30, |
|
Type of Derivative |
|
2011 |
|
|
2010 |
|
|
Loss |
|
|
2011 |
|
|
2010 |
|
|
Loss |
|
|
2011 |
|
|
2010 |
|
Fuel products segment: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil swaps |
|
$ |
(171,581 |
) |
|
$ |
59,678 |
|
|
Cost of sales |
|
$ |
(26,775 |
) |
|
$ |
(16,163 |
) |
|
Unrealized/ Realized |
|
$ |
(22,072 |
) |
|
$ |
(221 |
) |
Gasoline swaps |
|
|
5,883 |
|
|
|
(7,342 |
) |
|
Sales |
|
|
4,493 |
|
|
|
3,836 |
|
|
Unrealized/ Realized |
|
|
(19 |
) |
|
|
(9 |
) |
Diesel swaps |
|
|
46,413 |
|
|
|
(28,924 |
) |
|
Sales |
|
|
18,887 |
|
|
|
7,736 |
|
|
Unrealized/ Realized |
|
|
(252 |
) |
|
|
(404 |
) |
Jet fuel swaps |
|
|
81,523 |
|
|
|
(31,444 |
) |
|
Sales |
|
|
37,745 |
|
|
|
|
|
|
Unrealized/ Realized |
|
|
(1,793 |
) |
|
|
(50 |
) |
Specialty products
segment: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil collars |
|
|
|
|
|
|
|
|
|
Cost of sales |
|
|
|
|
|
|
|
|
|
Unrealized/ Realized |
|
|
|
|
|
|
|
|
Crude oil swaps |
|
|
|
|
|
|
|
|
|
Cost of sales |
|
|
|
|
|
|
|
|
|
Unrealized/ Realized |
|
|
|
|
|
|
|
|
Natural gas swaps |
|
|
|
|
|
|
|
|
|
Cost of sales |
|
|
|
|
|
|
|
|
|
Unrealized/ Realized |
|
|
|
|
|
|
|
|
Interest rate swaps: |
|
|
|
|
|
|
(1,124 |
) |
|
Interest expense |
|
|
|
|
|
|
639 |
|
|
Unrealized/ Realized |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(37,762 |
) |
|
$ |
(9,156 |
) |
|
|
|
|
|
$ |
34,350 |
|
|
$ |
(3,952 |
) |
|
|
|
|
|
$ |
(24,136 |
) |
|
$ |
(684 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Company recorded the following gains (losses) in its unaudited condensed consolidated
statements of operations and its unaudited condensed consolidated statements of partners capital
for the three months ended September 30, 2011 and 2010 related to its derivative instruments not
designated as cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Gain (Loss) |
|
|
Amount of Gain (Loss) |
|
|
|
Recognized in |
|
|
Recognized |
|
|
|
Realized Loss on |
|
|
in Unrealized Gain (Loss) on |
|
|
|
Derivatives |
|
|
Derivatives |
|
|
|
Three Months Ended |
|
|
Three Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
Type of Derivative |
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
Fuel products segment: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil swaps |
|
$ |
|
|
|
$ |
(1,939 |
) |
|
$ |
|
|
|
$ |
1,357 |
|
Gasoline swaps |
|
|
|
|
|
|
3,071 |
|
|
|
|
|
|
|
(2,284 |
) |
Diesel swaps |
|
|
|
|
|
|
(326 |
) |
|
|
|
|
|
|
326 |
|
Jet fuel swaps |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jet fuel collars |
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
|
(33 |
) |
Specialty products segment: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil collars |
|
|
|
|
|
|
(1,396 |
) |
|
|
|
|
|
|
1,759 |
|
Crude oil swaps |
|
|
|
|
|
|
(56 |
) |
|
|
|
|
|
|
275 |
|
Natural gas swaps |
|
|
|
|
|
|
(136 |
) |
|
|
|
|
|
|
(187 |
) |
Interest rate swaps: |
|
|
(655 |
) |
|
|
(205 |
) |
|
|
643 |
|
|
|
101 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(655 |
) |
|
$ |
(987 |
) |
|
$ |
642 |
|
|
$ |
1,314 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20
The Company recorded the following amounts in its condensed consolidated balance sheets,
unaudited condensed consolidated statements of operations and its unaudited condensed consolidated
statements of partners capital as of, and for the nine months ended, September 30, 2011 and 2010
related to its derivative instruments that were designated as cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of (Gain) |
|
|
|
|
|
|
Amount of Gain (Loss) |
|
|
Loss Reclassified |
|
|
|
|
|
|
Recognized in |
|
|
from Accumulated |
|
|
|
|
|
|
Accumulated Other |
|
|
Other Comprehensive |
|
|
Amount of Gain (Loss) |
|
|
|
Comprehensive Loss |
|
|
Loss into |
|
|
Recognized in Net |
|
|
|
on Derivatives |
|
|
Net Income |
|
|
Income on Derivatives |
|
|
|
(Effective Portion) |
|
|
(Effective Portion) |
|
|
(Ineffective Portion) |
|
|
|
Nine Months Ended |
|
|
Location of |
|
|
Nine Months Ended |
|
|
|
|
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
(Gain) |
|
|
September 30, |
|
|
Location of Gain |
|
|
September 30, |
|
Type of Derivative |
|
2011 |
|
|
2010 |
|
|
Loss |
|
|
2011 |
|
|
2010 |
|
|
(Loss) |
|
|
2011 |
|
|
2010 |
|
Fuel products segment: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil swaps |
|
$ |
(110,393 |
) |
|
$ |
(19,677 |
) |
|
Cost of sales |
|
$ |
(85,209 |
) |
|
$ |
(51,849 |
) |
|
Unrealized/ Realized |
|
$ |
(22,569 |
) |
|
$ |
(10,194 |
) |
Gasoline swaps |
|
|
(11,853 |
) |
|
|
12,307 |
|
|
Sales |
|
|
23,308 |
|
|
|
14,894 |
|
|
Unrealized/ Realized |
|
|
(1,358 |
) |
|
|
(4,560 |
) |
Diesel swaps |
|
|
(22,379 |
) |
|
|
3,633 |
|
|
Sales |
|
|
62,074 |
|
|
|
23,546 |
|
|
Unrealized/ Realized |
|
|
(790 |
) |
|
|
(1,628 |
) |
Jet fuel swaps |
|
|
(37,891 |
) |
|
|
(13,821 |
) |
|
Sales |
|
|
80,419 |
|
|
|
|
|
|
Unrealized/ Realized |
|
|
(3,397 |
) |
|
|
116 |
|
Specialty products segment: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil collars |
|
|
|
|
|
|
|
|
|
Cost of sales |
|
|
|
|
|
|
|
|
|
Unrealized/ Realized |
|
|
|
|
|
|
|
|
Crude oil swaps |
|
|
|
|
|
|
|
|
|
Cost of sales |
|
|
|
|
|
|
|
|
|
Unrealized/ Realized |
|
|
|
|
|
|
|
|
Natural gas swaps |
|
|
|
|
|
|
|
|
|
Cost of sales |
|
|
|
|
|
|
|
|
|
Unrealized/ Realized |
|
|
|
|
|
|
|
|
Interest rate swaps: |
|
|
1,979 |
|
|
|
(2,522 |
) |
|
Interest expense |
|
|
702 |
|
|
|
1,936 |
|
|
Unrealized/ Realized |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(180,537 |
) |
|
$ |
(20,080 |
) |
|
|
|
|
|
$ |
81,294 |
|
|
$ |
(11,473 |
) |
|
|
|
|
|
$ |
(28,114 |
) |
|
$ |
(16,266 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Company recorded the following gains (losses) in its unaudited condensed consolidated
statements of operations and its unaudited condensed consolidated statements of partners capital
for the nine months ended September 30, 2011 and 2010 related to its derivative instruments not
designated as cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Gain (Loss) |
|
|
Amount of Gain (Loss) |
|
|
|
Recognized in |
|
|
Recognized |
|
|
|
Realized Loss on |
|
|
in Unrealized Loss |
|
|
|
Derivatives |
|
|
on Derivatives |
|
|
|
Nine Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
Type of Derivative |
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
Fuel products segment: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil swaps |
|
$ |
|
|
|
$ |
(6,329 |
) |
|
$ |
|
|
|
$ |
8,295 |
|
Gasoline swaps |
|
|
|
|
|
|
10,174 |
|
|
|
|
|
|
|
(11,487 |
) |
Diesel swaps |
|
|
|
|
|
|
(976 |
) |
|
|
|
|
|
|
976 |
|
Jet fuel swaps |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jet fuel collars |
|
|
(562 |
) |
|
|
|
|
|
|
542 |
|
|
|
(321 |
) |
Specialty products segment: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil collars |
|
|
|
|
|
|
(4,355 |
) |
|
|
|
|
|
|
491 |
|
Crude oil swaps |
|
|
932 |
|
|
|
(1,718 |
) |
|
|
(662 |
) |
|
|
28 |
|
Natural gas swaps |
|
|
|
|
|
|
(171 |
) |
|
|
|
|
|
|
(263 |
) |
Interest rate swaps: |
|
|
(1,407 |
) |
|
|
(611 |
) |
|
|
(403 |
) |
|
|
551 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(1,037 |
) |
|
$ |
(3,986 |
) |
|
$ |
(523 |
) |
|
$ |
(1,730 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
The cash flow impact of the Companys derivative activities is classified as a change in
derivative activity in the operating activities section in the unaudited condensed consolidated
statements of cash flows.
The Company is exposed to credit risk in the event of nonperformance by its counterparties on
these derivative transactions. The Company does not expect nonperformance on any derivative
instruments, however, no assurances can be provided. The Companys credit exposure related to these
derivative instruments is represented by the fair value of contracts reported as derivative assets.
To manage credit risk, the Company selects and periodically reviews counterparties based on credit
ratings. The Company executes all of its derivative instruments with large financial institutions
that have ratings of at least Baa1 and A by Moodys and S&P, respectively. In the event of default,
the Company would potentially 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 contracts with these counterparties. No such
collateral was held by the Company as of September 30, 2011 or December 31, 2010. The Companys
contracts with these counterparties allow for netting of derivative instrument positions 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 Companys
condensed consolidated balance sheets and not netted against derivative assets or liabilities. As
of September 30, 2011, the Company had provided its counterparties with no collateral above the
21
$25,000 letter of credit provided to one counterparty to support crack spread hedging. As of
December 31, 2010, the Company had provided its counterparties with no cash collateral or letters
of credit above the $50,000 prefunded letter of credit then in effect and 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 Companys 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 Companys 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 Companys credit threshold is dependent upon the
Companys maintenance of certain corporate credit ratings with Moodys and S&P. In the event that
the Companys corporate credit rating was lowered below its current level by either Moodys or S&P,
such counterparties would have the right to reduce the applicable threshold to zero and demand full
collateralization of the Companys net liability position on outstanding derivative instruments. As
of September 30, 2011 and December 31, 2010, there was a net liability of $1,892 and $388,
respectively, associated with the Companys outstanding derivative instruments subject to such
requirements. In addition, the majority of the credit support agreements covering the Companys
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 Companys 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 hedges classified in accumulated other comprehensive loss is
$122,009 as of September 30, 2011, and absent a change in the fair market value of the underlying
transactions, will be reclassified to earnings by December 31, 2014 with balances being recognized
as follows:
|
|
|
|
|
|
|
Accumulated Other |
|
|
|
Comprehensive |
|
Year |
|
Loss |
|
2011 |
|
$ |
(20,955 |
) |
2012 |
|
|
(92,780 |
) |
2013 |
|
|
(7,415 |
) |
2014 |
|
|
(859 |
) |
|
|
|
|
Total |
|
$ |
(122,009 |
) |
|
|
|
|
Based on fair values as of September 30, 2011, the Company expects to reclassify $97,292 of
net losses on derivative instruments from accumulated other comprehensive loss to earnings during
the next twelve months due to actual crude oil purchases and gasoline, diesel and jet fuel sales.
However, the amounts actually realized will be dependent on the fair values as of the date of
settlements.
Crude Oil Swap and Collar Contracts Specialty Products Segment
The Company is exposed to fluctuations in the price of crude oil, its principal raw material.
The Company utilizes combinations of options and swaps to manage crude oil price risk and
volatility of cash flows in its specialty products segment. These derivatives may be designated as
cash flow hedges of the future purchase of crude oil if they meet the hedge criteria. The Companys
general policy is to enter into crude oil derivative contracts that mitigate the Companys exposure
to price risk associated with crude oil purchases related to specialty products production (for up
to 70% of expected purchases). While the Companys policy generally requires that these positions
be short term in nature and expire within three to nine months from execution, the Company may
execute derivative contracts for up to two years forward, if a change in the risks supports
lengthening the Companys position. As of September 30, 2011, the Company did not have any crude
oil derivatives related to future crude oil purchases in its specialty products segment.
22
At December 31, 2010, the Company had the following crude oil derivatives related to crude oil
purchases in its specialty products segment, none of which were designated as cash flow hedges.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
|
Barrels |
|
|
|
|
|
|
Swap |
|
Crude Oil Swap Contracts by Expiration Dates |
|
Purchased |
|
|
BPD |
|
|
($/Bbl) |
|
February 2011 |
|
|
33,600 |
|
|
|
1,200 |
|
|
$ |
83.10 |
|
March 2011 |
|
|
37,200 |
|
|
|
1,200 |
|
|
|
83.55 |
|
|
|
|
|
|
|
|
|
|
|
|
Totals |
|
|
70,800 |
|
|
|
|
|
|
|
|
|
Average price |
|
|
|
|
|
|
|
|
|
$ |
83.34 |
|
Crude Oil Swap Contracts Fuel Products Segment
The Company is exposed to fluctuations in the price of crude oil, its principal raw material.
The Company utilizes swap contracts to manage crude oil price risk and volatility of cash flows in
its fuel products segment. The Companys policy is generally to enter into crude oil swap contracts
for a period no greater than five years forward and for no more than 75% of crude oil purchases
used in fuels production. At September 30, 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
|
Barrels |
|
|
|
|
|
|
Swap |
|
Crude Oil Swap Contracts by Expiration Dates |
|
Purchased |
|
|
BPD |
|
|
($/Bbl) |
|
Fourth Quarter 2011 |
|
|
1,334,000 |
|
|
|
14,500 |
|
|
$ |
77.71 |
|
Calendar Year 2012 |
|
|
5,626,000 |
|
|
|
15,372 |
|
|
|
87.43 |
|
Calendar Year 2013 |
|
|
3,690,000 |
|
|
|
10,110 |
|
|
|
98.81 |
|
Calendar Year 2014 |
|
|
1,000,000 |
|
|
|
2,740 |
|
|
|
90.55 |
|
|
|
|
|
|
|
|
|
|
|
|
Totals |
|
|
11,650,000 |
|
|
|
|
|
|
|
|
|
Average price |
|
|
|
|
|
|
|
|
|
$ |
90.19 |
|
At December 31, 2010, 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
|
Barrels |
|
|
|
|
|
|
Swap |
|
Crude Oil Swap Contracts by Expiration Dates |
|
Purchased |
|
|
BPD |
|
|
($/Bbl) |
|
First Quarter 2011 |
|
|
1,215,000 |
|
|
|
13,500 |
|
|
$ |
75.32 |
|
Second Quarter 2011 |
|
|
1,729,000 |
|
|
|
19,000 |
|
|
|
76.62 |
|
Third Quarter 2011 |
|
|
1,610,000 |
|
|
|
17,500 |
|
|
|
77.38 |
|
Fourth Quarter 2011 |
|
|
1,334,000 |
|
|
|
14,500 |
|
|
|
77.71 |
|
Calendar Year 2012 |
|
|
5,535,000 |
|
|
|
15,123 |
|
|
|
86.30 |
|
|
|
|
|
|
|
|
|
|
|
|
Totals |
|
|
11,423,000 |
|
|
|
|
|
|
|
|
|
Average price |
|
|
|
|
|
|
|
|
|
$ |
81.41 |
|
Fuel Products Swap Contracts
The Company is exposed to fluctuations in the prices of gasoline, diesel and jet fuel. The
Company utilizes swap contracts to manage diesel, gasoline and jet fuel price risk and volatility
of cash flows in its fuel products segment. The Companys policy is generally to enter into diesel,
jet fuel and gasoline swap contracts for a period no longer than five years forward and for no more
than 75% of forecasted fuel sales.
23
Diesel Swap Contracts
At September 30, 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
|
|
|
|
Swap |
|
Diesel Swap Contracts by Expiration Dates |
|
Barrels Sold |
|
|
BPD |
|
|
($/Bbl) |
|
Fourth Quarter 2011 |
|
|
552,000 |
|
|
|
6,000 |
|
|
$ |
91.74 |
|
Calendar Year 2012 |
|
|
1,651,000 |
|
|
|
4,511 |
|
|
|
103.79 |
|
Calendar Year 2013 |
|
|
1,466,000 |
|
|
|
4,016 |
|
|
|
123.49 |
|
|
|
|
|
|
|
|
|
|
|
Totals |
|
|
3,669,000 |
|
|
|
|
|
|
|
|
|
Average price |
|
|
|
|
|
|
|
|
|
$ |
109.85 |
|
At December 31, 2010, 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
|
|
|
|
Swap |
|
Diesel Swap Contracts by Expiration Dates |
|
Barrels Sold |
|
|
BPD |
|
|
($/Bbl) |
|
First Quarter 2011 |
|
|
630,000 |
|
|
|
7,000 |
|
|
$ |
89.57 |
|
Second Quarter 2011 |
|
|
637,000 |
|
|
|
7,000 |
|
|
|
89.57 |
|
Third Quarter 2011 |
|
|
552,000 |
|
|
|
6,000 |
|
|
|
91.74 |
|
Fourth Quarter 2011 |
|
|
552,000 |
|
|
|
6,000 |
|
|
|
91.74 |
|
Calendar Year 2012 |
|
|
1,560,000 |
|
|
|
4,262 |
|
|
|
99.27 |
|
|
|
|
|
|
|
|
|
|
|
|
Totals |
|
|
3,931,000 |
|
|
|
|
|
|
|
|
|
Average price |
|
|
|
|
|
|
|
|
|
$ |
94.03 |
|
Jet Fuel Swap Contracts
At September 30, 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
|
|
|
|
Swap |
|
Jet Fuel Swap Contracts by Expiration Dates |
|
Barrels Sold |
|
|
BPD |
|
|
($/Bbl) |
|
Fourth Quarter 2011 |
|
|
644,000 |
|
|
|
7,000 |
|
|
$ |
89.21 |
|
Calendar Year 2012 |
|
|
3,838,500 |
|
|
|
10,488 |
|
|
|
99.78 |
|
Calendar Year 2013 |
|
|
2,044,000 |
|
|
|
5,600 |
|
|
|
125.13 |
|
Calendar Year 2014 |
|
|
1,000,000 |
|
|
|
2,740 |
|
|
|
115.56 |
|
|
|
|
|
|
|
|
|
|
|
|
Totals |
|
|
7,526,500 |
|
|
|
|
|
|
|
|
|
Average price |
|
|
|
|
|
|
|
|
|
$ |
107.86 |
|
At December 31, 2010, 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
|
|
|
|
Swap |
|
Jet Fuel Swap Contracts by Expiration Dates |
|
Barrels Sold |
|
|
BPD |
|
|
($/Bbl) |
|
First Quarter 2011 |
|
|
405,000 |
|
|
|
4,500 |
|
|
$ |
86.12 |
|
Second Quarter 2011 |
|
|
819,000 |
|
|
|
9,000 |
|
|
|
89.58 |
|
Third Quarter 2011 |
|
|
920,000 |
|
|
|
10,000 |
|
|
|
89.86 |
|
Fourth Quarter 2011 |
|
|
644,000 |
|
|
|
7,000 |
|
|
|
89.21 |
|
Calendar Year 2012 |
|
|
3,838,500 |
|
|
|
10,488 |
|
|
|
99.78 |
|
|
|
|
|
|
|
|
|
|
|
|
Totals |
|
|
6,626,500 |
|
|
|
|
|
|
|
|
|
Average price |
|
|
|
|
|
|
|
|
|
$ |
95.28 |
|
24
Gasoline Swap Contracts
At September 30, 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
|
|
|
|
Swap |
|
Gasoline Swap Contracts by Expiration Dates |
|
Barrels Sold |
|
|
BPD |
|
|
($/Bbl) |
|
Fourth Quarter 2011 |
|
|
138,000 |
|
|
|
1,500 |
|
|
$ |
85.50 |
|
Calendar Year 2012 |
|
|
136,500 |
|
|
|
373 |
|
|
|
89.04 |
|
Calendar Year 2013 |
|
|
180,000 |
|
|
|
493 |
|
|
|
110.38 |
|
|
|
|
|
|
|
|
|
|
|
|
Totals |
|
|
454,500 |
|
|
|
|
|
|
|
|
|
Average price |
|
|
|
|
|
|
|
|
|
$ |
96.41 |
|
At December 31, 2010, the Company had the following derivatives related to gasoline sales in
its fuel products segment, all of which are designated as cash flow hedges.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
|
|
|
|
Swap |
|
Gasoline Swap Contracts by Expiration Dates |
|
Barrels Sold |
|
|
BPD |
|
|
($/Bbl) |
|
First Quarter 2011 |
|
|
180,000 |
|
|
|
2,000 |
|
|
$ |
81.84 |
|
Second Quarter 2011 |
|
|
273,000 |
|
|
|
3,000 |
|
|
|
82.66 |
|
Third Quarter 2011 |
|
|
138,000 |
|
|
|
1,500 |
|
|
|
85.50 |
|
Fourth Quarter 2011 |
|
|
138,000 |
|
|
|
1,500 |
|
|
|
85.50 |
|
Calendar Year 2012 |
|
|
136,500 |
|
|
|
373 |
|
|
|
89.04 |
|
|
|
|
|
|
|
|
|
|
|
|
Totals |
|
|
865,500 |
|
|
|
|
|
|
|
|
|
Average price |
|
|
|
|
|
|
|
|
|
$ |
84.40 |
|
Jet Fuel Put Spread Contracts
At September 30, 2011, the Company had the following jet fuel put options related to jet fuel
crack spreads in its fuel products segment, none of which are designated as cash flow hedges.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
Average |
|
|
|
|
|
|
|
|
|
|
|
Sold Put |
|
|
Bought Put |
|
Jet Fuel Put Option Crack Spread Contracts by Expiration Dates |
|
Barrels |
|
|
BPD |
|
|
($/Bbl) |
|
|
($/Bbl) |
|
Fourth Quarter 2011 |
|
|
184,000 |
|
|
|
2,000 |
|
|
$ |
4.75 |
|
|
$ |
7.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals |
|
|
184,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Average price |
|
|
|
|
|
|
|
|
|
$ |
4.75 |
|
|
$ |
7.00 |
|
At December 31, 2010, the Company had the following jet fuel put options related to jet fuel
crack spreads in its fuel products segment, none of which are designated as cash flow hedges.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
Average |
|
|
|
|
|
|
|
|
|
|
|
Sold Put |
|
|
Bought Put |
|
Jet Fuel Put Option Crack Spread Contracts by Expiration Dates |
|
Barrels |
|
|
BPD |
|
|
($/Bbl) |
|
|
($/Bbl) |
|
First Quarter 2011 |
|
|
630,000 |
|
|
|
7,000 |
|
|
$ |
4.00 |
|
|
$ |
6.00 |
|
Fourth Quarter 2011 |
|
|
184,000 |
|
|
|
2,000 |
|
|
|
4.75 |
|
|
|
7.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals |
|
|
814,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Average price |
|
|
|
|
|
|
|
|
|
$ |
4.17 |
|
|
$ |
6.23 |
|
Natural Gas Swap Contracts
Natural gas purchases comprise a significant component of the Companys cost of sales;
therefore, changes in the price of natural gas also significantly affect its profitability and cash
flows. The Company utilizes swap contracts to manage natural gas price risk and volatility of cash
flows. The Companys policy is generally to enter into natural gas derivative contracts to hedge no
more than 75% of its upcoming fall and winter months anticipated natural gas requirement for a
period no greater than three years forward. At September 30, 2011 and December 31, 2010, the
Company had no derivatives outstanding related to natural gas purchases.
25
Interest Rate Swap Contracts
The Companys profitability and cash flows are affected by changes in interest rates,
specifically LIBOR and prime rates. The primary purpose of the Companys interest rate risk
management activities is to hedge its exposure to changes in interest rates. Historically, the
Companys policy has been to enter into interest rate swap agreements to hedge up to 75% of its
interest rate risk related to variable rate debt. With the issuances of the 2019 Notes, which
constitute fixed rate debt, the Company does not expect to enter into additional hedges to fix its
interest rates.
During 2010, the Company entered into forward swap contracts to manage interest rate risk
related to a portion of its then existing variable rate senior secured first lien term loan. The
Company hedged the future interest payments related to $100,000 of the total outstanding term loan
indebtedness for the period from February 15, 2011 to February 15, 2012 pursuant to these forward
swap contracts. These swap contracts were designated as cash flow hedges of the future payments of
interest with three-month LIBOR fixed at an average rate during the hedge period of 2.03%. Due to
the repayment of the variable rate senior secured first lien term loan in April 2011 with proceeds
from the issuance of the 2019 Notes, the interest rate swap contract was discontinued as a cash
flow hedge for the future payment of interest.
In 2009, the Company hedged the future interest payments related to $200,000 of its total
outstanding term loan indebtedness for the period from February 15, 2010 to February 15, 2011. This
swap contract was designated as a cash flow hedge of the future payment of interest with
three-month LIBOR fixed at an average rate during the hedge period of 0.94%. The cash flow hedge
settled during the first quarter of 2011.
In 2008, the Company entered into a forward swap contract to manage interest rate risk related
to a portion of its then existing variable rate senior secured first lien term loan which closed
January 3, 2008. The Company hedged the future interest payments related to $50,000 of the total
outstanding term loan indebtedness in 2010, pursuant to this forward swap contract. This swap
contract was designated as a cash flow hedge of the future payment of interest with three-month
LIBOR fixed at 3.66% per annum in 2010 and the first quarter of 2011. The cash flow hedge settled
during the first quarter of 2011.
In 2006, the Company entered into a forward swap contract to manage interest rate risk related
to a portion of its then existing variable rate senior secured first lien term loan. Due to the
repayment of $19,000 of the outstanding balance of the Companys then existing term loan facility
in August 2007 and subsequent refinancing of the remaining term loan balance, this swap contract
was not designated as a cash flow hedge of the future payment of interest. The entire change in the
fair value of this interest rate swap is recorded to unrealized loss on derivative instruments in
the unaudited condensed consolidated statements of operations. In the first quarter of 2008, the
Company fixed its unrealized loss on this interest rate swap derivative instrument by entering into
an offsetting interest rate swap expiring December 2012, which is not designated as a cash flow
hedge.
8. Fair Value of Financial Instruments
The Companys financial instruments, which require fair value disclosure, consist primarily of
cash and cash equivalents, accounts receivable, financial derivatives, accounts payable and
indebtedness. The carrying values of cash and cash equivalents, accounts receivable and accounts
payable are considered to be representative of their respective fair values, due to the short
maturity of these instruments. Derivative instruments are reported in the accompanying unaudited
condensed consolidated financial statements at fair value. The fair value of the Companys 2019
Notes issued in April 2011 and the 2019 Notes issued in September 2011 were $384,000 and $192,000,
respectively at September 30, 2011, using quoted market prices. The fair value of the Companys
term loan was $355,445 at December 31, 2010, using quoted market prices. The carrying values of
borrowings under the Companys revolving credit facility were $56,000 and $10,832 at September,
2011 and December 31, 2010, respectively, and approximate their fair values.
9. Fair Value Measurements
The Company uses a three-tier fair value hierarchy, which prioritizes the inputs used in
measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted
prices in active markets; Level 2, defined as inputs other than quoted prices in active markets
that are either directly or indirectly observable and Level 3, defined as 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.
26
As of September 30, 2011, the Company held certain assets and liabilities that are required to
be measured at fair value on a recurring basis. These included the Companys derivative instruments
related to crude oil, gasoline, diesel, jet fuel and interest rates and investments associated with
the Companys non-contributory defined benefit plan (Pension Plan).
The Companys derivative instruments consist of over-the-counter (OTC) contracts, which are
not traded on a public exchange. Substantially all of the Companys derivative instruments are with
counterparties that have long-term credit ratings of at least Baa1 and A by Moodys and S&P,
respectively. To estimate the fair values of the Companys derivative instruments, the Company uses
the market approach. Under this approach, the fair values of the Companys derivative instruments
for crude oil, gasoline, diesel, jet fuel and interest rates 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. The Company determines
the fair value of its crude oil option contracts utilizing a standard option pricing model based on
inputs that can be derived from information available in publicly quoted markets, or are quoted by
counterparties to these contracts. 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
Companys 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
counterpartys CDS, or a peer groups estimated CDS when a CDS for the counterparty is not
available. The Company uses its own peer groups estimated CDS when it is in a net liability
position. As a result of applying the applicable CDS, at September 30, 2011 and December 31, 2010,
the Companys liability was reduced by approximately $7,159 and $687, respectively. Based on the
use of various unobservable inputs, principally non-performance risk and unobservable inputs in
forward years for gasoline, jet fuel and diesel, the Company has categorized these derivative
instruments as Level 3. 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.
The Companys investments associated with its Pension Plan primarily consist of (i) mutual
funds that are publicly traded and (ii) a commingled fund. The mutual 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.
27
The Companys assets and liabilities measured at fair value at September 30, 2011 were as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements - (b) |
|
|
|
Level 1 |
|
|
Level 2 (a) |
|
|
Level 3 |
|
|
Total |
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
66 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
66 |
|
Crude oil swaps |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline swaps |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diesel swaps |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jet fuel swaps |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil options |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jet fuel options |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension plan investments |
|
|
14,598 |
|
|
|
2,391 |
|
|
|
|
|
|
|
16,989 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets at fair value |
|
$ |
14,664 |
|
|
$ |
2,391 |
|
|
$ |
|
|
|
$ |
17,055 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil swaps |
|
$ |
|
|
|
$ |
|
|
|
$ |
(87,573 |
) |
|
$ |
(87,573 |
) |
Gasoline swaps |
|
|
|
|
|
|
|
|
|
|
(2,150 |
) |
|
|
(2,150 |
) |
Diesel swaps |
|
|
|
|
|
|
|
|
|
|
(14,131 |
) |
|
|
(14,131 |
) |
Jet fuel swaps |
|
|
|
|
|
|
|
|
|
|
(55,322 |
) |
|
|
(55,322 |
) |
Crude oil options |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jet fuel options |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate swaps |
|
|
|
|
|
|
|
|
|
|
(1,685 |
) |
|
|
(1,685 |
) |
Pension plan investments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities at fair value |
|
$ |
|
|
|
$ |
|
|
|
$ |
(160,861 |
) |
|
$ |
(160,861 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Transferred from Level 1 to Level 2 in the first quarter of 2011 because of lack of
observable market data in the underlying investments. |
|
(b) |
|
The table excludes the pension plan assets from the Superior Acquisition of $17,718. The
final determination of the fair value for these assets will be completed as soon as the
information necessary to complete the analysis is obtained. |
The Companys financial assets and liabilities measured at fair value at December 31, 2010
were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements |
|
|
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Total |
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
37 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
37 |
|
Crude oil swaps |
|
|
|
|
|
|
|
|
|
|
135,578 |
|
|
|
135,578 |
|
Gasoline swaps |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diesel swaps |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jet fuel swaps |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil options |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jet fuel options |
|
|
|
|
|
|
|
|
|
|
20 |
|
|
|
20 |
|
Pension plan investments |
|
|
16,039 |
|
|
|
|
|
|
|
|
|
|
|
16,039 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets at fair value |
|
$ |
16,076 |
|
|
$ |
|
|
|
$ |
135,598 |
|
|
$ |
151,674 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil swaps |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Gasoline swaps |
|
|
|
|
|
|
|
|
|
|
(14,149 |
) |
|
|
(14,149 |
) |
Diesel swaps |
|
|
|
|
|
|
|
|
|
|
(53,744 |
) |
|
|
(53,744 |
) |
Jet fuel swaps |
|
|
|
|
|
|
|
|
|
|
(96,556 |
) |
|
|
(96,556 |
) |
Crude oil options |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jet fuel options |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate swaps |
|
|
|
|
|
|
|
|
|
|
(3,963 |
) |
|
|
(3,963 |
) |
Pension plan investments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities at fair value |
|
$ |
|
|
|
$ |
|
|
|
$ |
(168,412 |
) |
|
$ |
(168,412 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
28
The table below sets forth a summary of net changes in fair value of the Companys Level 3
financial assets and liabilities for the nine months ended September 30, 2011 and 2010:
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
|
2011 |
|
|
2010 |
|
Fair value at January 1, |
|
$ |
(32,814 |
) |
|
$ |
26,138 |
|
Realized losses |
|
|
5,798 |
|
|
|
8,147 |
|
Unrealized losses |
|
|
(23,876 |
) |
|
|
(13,835 |
) |
Change in fair value of cash flow hedges |
|
|
(180,537 |
) |
|
|
(20,080 |
) |
Settlements |
|
|
70,568 |
|
|
|
(20,469 |
) |
Transfers in (out) of Level 3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value at September 30, |
|
$ |
(160,861 |
) |
|
$ |
(20,099 |
) |
|
|
|
|
|
|
|
Total losses included in net loss attributable
to changes in unrealized losses relating to
financial assets and liabilities held as of
September 30, |
|
$ |
(23,876 |
) |
|
$ |
(13,835 |
) |
|
|
|
|
|
|
|
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 unaudited condensed 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 immediately in unrealized loss on derivative instruments in the unaudited
condensed consolidated statements of operations. All settlements from derivative instruments not
designated as cash flow hedges are recorded in realized loss on derivative instruments in the
unaudited condensed consolidated statements of operations. See Note 7 for further information on
derivative instruments.
10. 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 an equity 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 partners capital contribution) were
$92,290 and were used to repay borrowings under its revolving credit facility. Underwriting
discounts totaled $3,915. The Companys general partner contributed $1,970 to retain its 2% general
partner interest.
On September 8, 2011, the Company completed an equity offering of its common units in which it
sold 11,000,000 common units to the underwriters of the offering at a price 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 partners capital contribution) were $189,580 and
were used to fund a portion of the purchase price of the Superior Acquisition. Underwriting
discounts totaled $7,866. The Companys general partner contributed $4,041 to retain its 2% general
partner interest. See Note 3 for further information on the Superior Acquisition.
For the three and nine months ended September 30, 2011 and 2010 the general partner was
allocated $40 and $0, respectively, in incentive distribution rights.
29
11. Comprehensive Income (Loss)
Comprehensive income (loss) for the Company includes the change in fair value of cash flow
hedges and the minimum pension liability adjustment that have not been recognized in net income.
Comprehensive income (loss) for the three and nine months ended September 30, 2011 and 2010 was as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
Net income |
|
$ |
19,614 |
|
|
$ |
21,221 |
|
|
$ |
16,164 |
|
|
$ |
7,247 |
|
Cash flow hedge (gain) loss reclassified to net income |
|
|
34,350 |
|
|
|
(3,952 |
) |
|
|
81,294 |
|
|
|
(11,473 |
) |
Change in fair value of cash flow hedges |
|
|
(37,762 |
) |
|
|
(9,156 |
) |
|
|
(180,537 |
) |
|
|
(20,080 |
) |
Defined benefit pension and retiree health benefit plans |
|
|
61 |
|
|
|
59 |
|
|
|
183 |
|
|
|
523 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income (loss) |
|
$ |
16,263 |
|
|
$ |
8,172 |
|
|
$ |
(82,896 |
) |
|
$ |
(23,783 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
12. Unit-Based Compensation and Distributions
A summary of the Companys nonvested phantom units as of September 30, 2011 and the changes
during the nine months ended September 30, 2011 is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average |
|
|
|
|
|
|
|
Grant Date |
|
Nonvested Phantom Units |
|
Grant |
|
|
Fair Value |
|
Nonvested at December 31, 2010 |
|
|
105,492 |
|
|
$ |
17.68 |
|
Granted |
|
|
55,355 |
|
|
|
21.31 |
|
Vested |
|
|
(57,482 |
) |
|
|
19.78 |
|
Forfeited |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonvested at September 30, 2011 |
|
|
103,365 |
|
|
$ |
18.45 |
|
|
|
|
|
|
|
|
For the three months ended September 30, 2011 and 2010, compensation expense of $662 and $151,
respectively, was recognized in the unaudited condensed consolidated statements of operations
related to vested phantom unit grants. For the nine months ended September 30, 2011 and 2010,
compensation expense of $1,944 and $443, respectively, was recognized in the unaudited condensed
consolidated statements of operations related to vested phantom unit grants. As of September 30, 2011 and 2010,
there was a total of $1,907 and $928, respectively, of unrecognized compensation costs related to
nonvested phantom unit grants. These costs are expected to be recognized over a weighted-average
period of approximately three years.
The Companys distribution policy is as defined in its partnership agreement. For the three
months ended September 30, 2011 and 2010, the Company made distributions of $20,124 and $16,391,
respectively, to its partners. For the nine months ended September 30, 2011 and 2010, the Company
made distributions of $56,382 and $49,179, respectively, to its partners.
13. Employee Benefit Plans
The components of net periodic pension and other post retirement benefits cost for the three
months ended September 30, 2011 and 2010 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended September 30, |
|
|
|
2011 |
|
|
2010 |
|
|
|
|
|
|
|
Other Post |
|
|
|
|
|
|
Other Post |
|
|
|
Pension |
|
|
Retirement |
|
|
Pension |
|
|
Retirement |
|
|
|
Benefits |
|
|
Employee Benefits |
|
|
Benefits |
|
|
Employee Benefits |
|
Service cost |
|
$ |
24 |
|
|
$ |
|
|
|
$ |
21 |
|
|
$ |
|
|
Interest cost |
|
|
332 |
|
|
|
5 |
|
|
|
334 |
|
|
|
6 |
|
Expected return on assets |
|
|
(264 |
) |
|
|
|
|
|
|
(259 |
) |
|
|
|
|
Amortization of net (gain) loss |
|
|
71 |
|
|
|
(1 |
) |
|
|
69 |
|
|
|
(1 |
) |
Prior service cost |
|
|
|
|
|
|
(8 |
) |
|
|
|
|
|
|
(9 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost |
|
$ |
163 |
|
|
$ |
(4 |
) |
|
$ |
165 |
|
|
$ |
(4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
30
The components of net periodic pension and other post retirement benefits cost for the nine
months ended September 30, 2011 and 2010 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Nine Months Ended September 30, |
|
|
|
2011 |
|
|
2010 |
|
|
|
|
|
|
|
Other Post |
|
|
|
|
|
|
Other Post |
|
|
|
Pension |
|
|
Retirement |
|
|
Pension |
|
|
Retirement |
|
|
|
Benefits |
|
|
Employee Benefits |
|
|
Benefits |
|
|
Employee Benefits |
|
Service cost |
|
$ |
73 |
|
|
$ |
|
|
|
$ |
63 |
|
|
$ |
|
|
Interest cost |
|
|
998 |
|
|
|
14 |
|
|
|
1,002 |
|
|
|
18 |
|
Expected return on assets |
|
|
(793 |
) |
|
|
|
|
|
|
(776 |
) |
|
|
|
|
Amortization of net (gain) loss |
|
|
211 |
|
|
|
(2 |
) |
|
|
206 |
|
|
|
(2 |
) |
Prior service cost |
|
|
|
|
|
|
(26 |
) |
|
|
|
|
|
|
(27 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost |
|
$ |
489 |
|
|
$ |
(14 |
) |
|
$ |
495 |
|
|
$ |
(11 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
During the three months ended September 30, 2011 and 2010, the Company made contributions of
$374 and $337, respectively, to its non-contributory defined benefit plan (the Pension Plan).
During the nine months ended September 30, 2011 and 2010, the Company made contributions of $1,310
and $337, respectively, and expects to make total contributions to its Pension Plan in 2011 of
$1,918.
At
September 30, 2011, the Companys investments associated with its Pension Plan
primarily consist of (i) mutual funds that are publicly traded and (ii) a commingled fund. The
mutual 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 quarter end. The
Companys Pension Plan assets measured at fair value at September 30, 2011 and December 31, 2010
were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2011 |
|
|
December 31, 2010 |
|
|
|
Pension Benefits (a) |
|
|
Pension Benefits |
|
|
|
Level 1 |
|
|
Level 2 |
|
|
Level 1 |
|
|
Level 2 |
|
Cash |
|
$ |
3,903 |
|
|
$ |
|
|
|
$ |
347 |
|
|
$ |
|
|
Equity |
|
|
3,567 |
|
|
|
|
|
|
|
7,784 |
|
|
|
|
|
Foreign equities |
|
|
664 |
|
|
|
|
|
|
|
1,890 |
|
|
|
|
|
Commingled fund |
|
|
|
|
|
|
2,391 |
|
|
|
|
|
|
|
|
|
Fixed income |
|
|
6,464 |
|
|
|
|
|
|
|
6,018 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
14,598 |
|
|
$ |
2,391 |
|
|
$ |
16,039 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
The table excludes the pension plan assets from the Superior Acquisition of $17,718, for which
the Company is awaiting final information. |
14. Transactions with Related Parties
On March 24, 2011, Calumet Lubricants Co., Limited Partnership (Calumet Lubricants), a
wholly owned subsidiary of the Company, entered into Amendment No. 5 (the Princeton Amendment) to
that certain Crude Oil Supply Agreement, effective as of April 30, 2008 (as amended since such
date, the Princeton Crude Oil Supply Agreement), by and between Calumet Lubricants and Legacy
Resources Co., L.P. (Legacy), under which Legacy supplied the Companys Princeton refinery with
all of the refinerys crude oil requirements on a just-in-time basis. The Princeton Amendment,
effective as of March 1, 2011, modified the market-based pricing mechanism established in the
Princeton Crude Oil Supply Agreement and shortened the termination notice period set forth in the
Princeton Crude Oil Supply Agreement from approximately 90 days to approximately 60 days.
Concurrent with entering into the Princeton Amendment, on March 24, 2011, Calumet Lubricants
provided notice to Legacy that it was exercising its contractual rights under the Princeton Crude
Oil Supply Agreement, as amended by the Princeton Amendment, to terminate the Princeton Crude Oil
Supply Agreement on May 31, 2011. The Company did not incur any material early termination
penalties in connection with its termination of the Princeton Crude Oil Supply Agreement.
On March 24, 2011, Calumet Shreveport Fuels, LLC (Calumet Shreveport Fuels), a wholly owned
subsidiary of the Company, entered into Amendment No. 5 (the Shreveport Amendment) to that
certain Crude Oil Supply Agreement, effective as of September 1, 2009 (as amended since such date,
the Shreveport Crude Oil Supply Agreement), by and between Calumet Shreveport Fuels and Legacy,
under which Legacy supplies the Companys Shreveport refinery with a portion of the refinerys
crude oil requirements on a just-in-time basis. The Shreveport Amendment, effective as of March 1,
2011, modified the market-based pricing mechanism established in the Shreveport Crude Oil
31
Supply Agreement and shortened the termination notice
period set forth in the Shreveport Crude Oil Supply Agreement from approximately 90 days to
approximately 60 days. Concurrent with entering into the Shreveport Amendment, on March 24, 2011,
Calumet Shreveport Fuels provided notice to Legacy that it was exercising its contractual rights
under the Shreveport Crude Oil Supply Agreement, as amended by the Shreveport Amendment, to
terminate the Shreveport Crude Oil Supply Agreement on May 31, 2011. The Company did not incur any
material early termination penalties in connection with its termination of the Shreveport Crude Oil
Supply Agreement.
With the termination of the agreements, the Company has one remaining crude oil supply
agreement with Legacy, 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.
Legacy is owned in part by three of the Companys limited partners, an affiliate of the
Companys general partner, the Companys chief executive officer and vice chairman, F. William
Grube, and the Companys president and chief operating officer, Jennifer G. Straumins. During the
three and nine months ended September 30, 2011, the Company had crude oil purchases of $285 and
$241,572, respectively, from Legacy. Accounts payable to Legacy at September 30, 2011 were $97.
32
15. 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 and 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 Fuel Products segment
produces a variety of fuel and fuel-related products including gasoline, diesel and jet fuel.
Because of their similar economic characteristics, certain operations have been aggregated for
segment reporting purposes. As a result of the Superior Acquisition on September 30, 2011, the
assets and liabilities from the Superior Acquisition have been included in the Companys condensed
consolidated balance sheets, while the unaudited condensed consolidated statements of operations
for the Company do not contain the results of the Superior Acquisition, as there was no related
revenue in the current period.
The accounting policies of the segments are the same as those described in the summary of
significant accounting policies except that the Company evaluates segment performance based on
operating income (loss). The Company accounts for intersegment sales and transfers at cost plus a
specified mark-up. Reportable segment information is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Specialty |
|
|
Fuel |
|
|
Combined |
|
|
|
|
|
|
Consolidated |
|
Three Months Ended September 30, 2011 |
|
Products |
|
|
Products |
|
|
Segments |
|
|
Eliminations |
|
|
Total |
|
Sales: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External customers |
|
$ |
477,489 |
|
|
$ |
300,291 |
|
|
$ |
777,780 |
|
|
$ |
|
|
|
$ |
777,780 |
|
Intersegment sales |
|
|
285,559 |
|
|
|
13,271 |
|
|
|
298,830 |
|
|
|
(298,830 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total sales |
|
$ |
763,048 |
|
|
$ |
313,562 |
|
|
$ |
1,076,610 |
|
|
$ |
(298,830 |
) |
|
$ |
777,780 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
17,930 |
|
|
|
|
|
|
|
17,930 |
|
|
|
|
|
|
|
17,930 |
|
Operating income |
|
|
54,404 |
|
|
|
2,127 |
|
|
|
56,531 |
|
|
|
|
|
|
|
56,531 |
|
Reconciling items to net income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12,577 |
) |
Loss on derivative instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(24,149 |
) |
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
45 |
|
Income tax expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(236 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
19,614 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
$ |
10,032 |
|
|
$ |
|
|
|
$ |
10,032 |
|
|
$ |
|
|
|
$ |
10,032 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Specialty |
|
|
Fuel |
|
|
Combined |
|
|
|
|
|
|
Consolidated |
|
Three Months Ended September 30, 2010 |
|
Products |
|
|
Products |
|
|
Segments |
|
|
Eliminations |
|
|
Total |
|
Sales: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External customers |
|
$ |
386,051 |
|
|
$ |
209,222 |
|
|
$ |
595,273 |
|
|
$ |
|
|
|
$ |
595,273 |
|
Intersegment sales |
|
|
200,728 |
|
|
|
7,286 |
|
|
|
208,014 |
|
|
|
(208,014 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total sales |
|
$ |
586,779 |
|
|
$ |
216,508 |
|
|
$ |
803,287 |
|
|
$ |
(208,014 |
) |
|
$ |
595,273 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
18,420 |
|
|
|
|
|
|
|
18,420 |
|
|
|
|
|
|
|
18,420 |
|
Operating income (loss) |
|
|
31,126 |
|
|
|
(1,554 |
) |
|
|
29,572 |
|
|
|
|
|
|
|
29,572 |
|
Reconciling items to net income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,794 |
) |
Loss on derivative instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(357 |
) |
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(121 |
) |
Income tax expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(79 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
21,221 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
$ |
10,293 |
|
|
$ |
|
|
|
$ |
10,293 |
|
|
$ |
|
|
|
$ |
10,293 |
|
33
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Specialty |
|
|
Fuel |
|
|
Combined |
|
|
|
|
|
|
Consolidated |
|
Nine Months Ended September 30, 2011 |
|
Products |
|
|
Products |
|
|
Segments |
|
|
Eliminations |
|
|
Total |
|
Sales: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External customers |
|
$ |
1,341,005 |
|
|
$ |
775,785 |
|
|
$ |
2,116,790 |
|
|
$ |
|
|
|
$ |
2,116,790 |
|
Intersegment sales |
|
|
792,987 |
|
|
|
32,178 |
|
|
|
825,165 |
|
|
|
(825,165 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total sales |
|
$ |
2,133,992 |
|
|
$ |
807,963 |
|
|
$ |
2,941,955 |
|
|
$ |
(825,165 |
) |
|
$ |
2,116,790 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
54,295 |
|
|
|
|
|
|
|
54,295 |
|
|
|
|
|
|
|
54,295 |
|
Operating income (loss) |
|
|
106,359 |
|
|
|
(14,263 |
) |
|
|
92,096 |
|
|
|
|
|
|
|
92,096 |
|
Reconciling items to net income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(30,602 |
) |
Debt extinguishment costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(15,130 |
) |
Loss on derivative instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(29,674 |
) |
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
148 |
|
Income tax expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(674 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
16,164 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
$ |
30,667 |
|
|
$ |
|
|
|
$ |
30,667 |
|
|
$ |
|
|
|
$ |
30,667 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Specialty |
|
|
Fuel |
|
|
Combined |
|
|
|
|
|
|
Consolidated |
|
Nine Months Ended September 30, 2010 |
|
Products |
|
|
Products |
|
|
Segments |
|
|
Eliminations |
|
|
Total |
|
Sales: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External customers |
|
$ |
1,020,950 |
|
|
$ |
573,592 |
|
|
$ |
1,594,542 |
|
|
$ |
|
|
|
$ |
1,594,542 |
|
Intersegment sales |
|
|
563,989 |
|
|
|
34,503 |
|
|
|
598,492 |
|
|
|
(598,492 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total sales |
|
$ |
1,584,939 |
|
|
$ |
608,095 |
|
|
$ |
2,193,034 |
|
|
$ |
(598,492 |
) |
|
$ |
1,594,542 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
53,928 |
|
|
|
|
|
|
|
53,928 |
|
|
|
|
|
|
|
53,928 |
|
Operating income |
|
|
47,961 |
|
|
|
4,282 |
|
|
|
52,243 |
|
|
|
|
|
|
|
52,243 |
|
Reconciling items to net income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(22,505 |
) |
Loss on derivative instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(21,982 |
) |
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(170 |
) |
Income tax expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(339 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
7,247 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
$ |
27,310 |
|
|
$ |
|
|
|
$ |
27,310 |
|
|
$ |
|
|
|
$ |
27,310 |
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2011 |
|
|
December 31, 2010 |
|
Segment assets: |
|
|
|
|
|
|
|
|
Specialty products |
|
$ |
1,121,912 |
|
|
$ |
962,850 |
|
Fuel products |
|
|
519,684 |
|
|
|
53,822 |
|
|
|
|
|
|
|
|
Total assets |
|
$ |
1,641,596 |
|
|
$ |
1,016,672 |
|
|
|
|
|
|
|
|
b. Geographic Information
International sales accounted for less than 10% of consolidated sales in each of the three
months and nine months ended September 30, 2011 and 2010. All of the Companys long-lived assets
are domestically located.
34
c. Product Information
The Company offers products primarily in five general categories consisting of lubricating
oils, solvents, waxes, fuels and asphalt and by-products. Fuel products primarily consist of
gasoline, diesel, jet fuel and by-products. The following table sets forth the major product
category sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
Specialty products: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lubricating oils |
|
$ |
262,175 |
|
|
$ |
214,926 |
|
|
$ |
717,674 |
|
|
$ |
555,328 |
|
Solvents |
|
|
126,709 |
|
|
|
102,276 |
|
|
|
380,687 |
|
|
|
285,907 |
|
Waxes |
|
|
38,908 |
|
|
|
34,089 |
|
|
|
107,089 |
|
|
|
88,698 |
|
Fuels |
|
|
1,047 |
|
|
|
298 |
|
|
|
2,470 |
|
|
|
4,268 |
|
Asphalt and other by-products |
|
|
48,650 |
|
|
|
34,462 |
|
|
|
133,085 |
|
|
|
86,749 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
477,489 |
|
|
$ |
386,051 |
|
|
$ |
1,341,005 |
|
|
$ |
1,020,950 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel products: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline |
|
|
132,286 |
|
|
|
73,550 |
|
|
|
355,519 |
|
|
|
225,720 |
|
Diesel |
|
|
116,914 |
|
|
|
97,405 |
|
|
|
290,678 |
|
|
|
239,031 |
|
Jet fuel |
|
|
47,190 |
|
|
|
34,998 |
|
|
|
114,650 |
|
|
|
100,378 |
|
By-products |
|
|
3,901 |
|
|
|
3,269 |
|
|
|
14,938 |
|
|
|
8,463 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
300,291 |
|
|
$ |
209,222 |
|
|
$ |
775,785 |
|
|
$ |
573,592 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated sales |
|
$ |
777,780 |
|
|
$ |
595,273 |
|
|
$ |
2,116,790 |
|
|
$ |
1,594,542 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
d. Major Customers
During the three and nine months ended September 30, 2011 and 2010, the Company had no
customer that represented 10% or greater of consolidated sales.
16. Subsequent Events
On October 5, 2011, Calumet Superior, LLC (Calumet Superior), a wholly-owned subsidiary of
the Company, entered into a Crude Oil Purchase Agreement (the BP Purchase Agreement) with BP
Products North America Inc. (BP), pursuant to which BP will supply the Superior refinery with
approximately 75% of its daily crude oil requirements, with such requirements estimated to be
between 35,000 and 45,000 barrels per day, utilizing a market-based pricing mechanism, plus
transportation and handling costs. The BP Purchase Agreement is effective as of October 1, 2011,
with deliveries commencing November 1, 2011. The BP Purchase Agreement has an initial term of seven
months, will automatically renew for successive one-year terms and may be terminated by either
party on written notice delivered at least 90 days prior to the end of the then-current term. To
secure a portion of Calumet Superiors payment obligations under the BP Purchase Agreement, the
Company and its affiliates have granted a limited interest in the collateral pledged as security
under the Collateral Trust Agreement to BP as a Forward Purchase Secured Hedge Counterparty under
the Collateral Trust Agreement, as such term is defined therein.
On October 11, 2011, the Company declared a quarterly cash distribution of $0.50 per unit on
all outstanding units, or approximately $26,362 in aggregate, for the quarter ended September 30,
2011. The distribution will be paid on November 14, 2011 to unitholders of record as of the close
of business on November 4, 2011. This quarterly distribution of $0.50 per unit equates to $2.00 per
unit, or approximately $105,448 in aggregate on an annualized basis.
On October 13, 2011, the underwriters of the Companys September 8, 2011 public equity
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 the offering price of $18.00 per unit,
less the underwriting discount. The proceeds received by the Company from this offering (net of
underwriting discounts, commissions and expenses but before its general partners capital
contribution) were $12,910 and were used to repay borrowings under its revolving credit facility.
Underwriting discounts totaled $540. The Companys general partner contributed $276 to retain its
2% general partner interest.
The fair value of
the Companys derivatives increased by approximately $32,000 subsequent
to September 30, 2011 to a liability of approximately $129,000. The fair value of the Companys
long-term debt, excluding capital leases, has not changed materially subsequent to September 30,
2011.
35
In addition, subsequent to the closing of the Superior Acquisition on September 30, 2011, the
Company entered into additional derivative positions to hedge the increased exposure to crack
spreads resulting from the Superior Acquisition. The following tables provide a summary of such
derivatives entered into as of November 4, 2011, all of which are designated as cash flow hedges.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
|
Barrels |
|
|
|
|
|
|
Swap |
|
Crude Oil Swap Contracts by Expiration Dates |
|
Purchased |
|
|
BPD |
|
|
($/Bbl) |
|
Fourth Quarter 2011 |
|
|
552,000 |
|
|
|
6,000 |
|
|
$ |
78.50 |
|
Calendar Year 2012 |
|
|
5,490,000 |
|
|
|
15,000 |
|
|
|
83.35 |
|
|
|
|
|
|
|
|
|
|
|
|
Totals |
|
|
6,042,000 |
|
|
|
|
|
|
|
|
|
Average price |
|
|
|
|
|
|
|
|
|
$ |
82.90 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
|
Barrels |
|
|
|
|
|
|
Swap |
|
Diesel Swap Contracts by Expiration Dates |
|
Sold |
|
|
BPD |
|
|
($/Bbl) |
|
Calendar Year 2012 |
|
|
1,830,000 |
|
|
|
5,000 |
|
|
|
115.27 |
|
|
|
|
|
|
|
|
|
|
|
|
Totals |
|
|
1,830,000 |
|
|
|
|
|
|
|
|
|
Average price |
|
|
|
|
|
|
|
|
|
$ |
115.27 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
|
Barrels |
|
|
|
|
|
|
Swap |
|
Gasoline Swap Contracts by Expiration Dates |
|
Sold |
|
|
BPD |
|
|
($/Bbl) |
|
Fourth Quarter 2011 |
|
|
552,000 |
|
|
|
6,000 |
|
|
$ |
102.22 |
|
Calendar Year 2012 |
|
|
3,660,000 |
|
|
|
10,000 |
|
|
|
102.48 |
|
|
|
|
|
|
|
|
|
|
|
|
Totals |
|
|
4,212,000 |
|
|
|
|
|
|
|
|
|
Average price |
|
|
|
|
|
|
|
|
|
$ |
102.44 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Implied |
|
|
|
|
|
|
|
|
|
|
|
Crack |
|
|
|
|
|
|
|
|
|
|
|
Spread |
|
Crude Oil and Fuel Products Swap Contracts by Expiration Dates |
|
Barrels |
|
|
BPD |
|
|
($/Bbl) |
|
Fourth Quarter 2011 |
|
|
552,000 |
|
|
|
6,000 |
|
|
$ |
23.72 |
|
Calendar Year 2012 |
|
|
5,490,000 |
|
|
|
15,000 |
|
|
|
23.39 |
|
|
|
|
|
|
|
|
|
|
|
|
Totals |
|
|
6,042,000 |
|
|
|
|
|
|
|
|
|
Average price |
|
|
|
|
|
|
|
|
|
$ |
23.42 |
|
36
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
The historical 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, us). The following discussion analyzes the financial
condition and results of operations of Calumet for the three and nine months ended September 30,
2011 and 2010. Unitholders should read the following discussion and analysis of the financial
condition and results of operations for Calumet in conjunction with our 2010 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 own plants located in Princeton, Louisiana; Cotton Valley, Louisiana; Shreveport,
Louisiana; Superior, Wisconsin; Karns City, Pennsylvania and Dickinson, Texas and terminals located
in Burnham, Illinois; Rhinelander, Wisconsin; Crookston, Minnesota and Proctor, Minnesota. Our
business is organized into two segments: specialty products and fuel products. In our specialty
products segment, we process crude oil and other feedstocks into a wide variety of customized
lubricating oils, white mineral oils, solvents, petrolatums and waxes. Our specialty products are
sold to domestic and international customers who purchase them primarily as raw material components
for basic industrial, consumer and automotive goods. In our fuel products segment, we process crude
oil into a variety of fuel and fuel-related products, including gasoline, diesel and jet fuel. In
connection with our production of specialty products and fuel products, we also produce asphalt and
a limited number of other by-products.
Third Quarter 2011 Update
For the three months ended September 30, 2011 and 2010, 48.9% and 53.4%, respectively, of our
sales volume and 90.9% and 98.0%, respectively, of our gross profit was generated from our
specialty products segment while, for the same periods, 51.1% and 46.6%, respectively, of our sales
volume and 9.1% and 2.0%, respectively, of our gross profit was generated from our fuel products
segment.
Despite a slight decline in specialty product segment sales volume specialty products
refining margins significantly strengthened quarter over quarter. Specialty products segment
generated a gross profit margin of 18.4% in the third quarter of 2011, as compared to a gross
profit margin of 15.8% for the same period in the prior year as specialty products pricing
continued to improve throughout the first three quarters of 2011.
We noted significant improvement in both sales and production volume in our fuel products
segment during the third quarter which allowed us to take advantage of higher market crack spreads.
Fuel products sales volumes increased 13.8% for the three months ended September 30, 2011 compared
to the same period in 2010, while generating a gross profit margin of 2.9% during the quarter
compared to 0.6% in same period in 2010. We recorded realized derivative losses of $34.4 million
during the third quarter in our fuel products segment. During the third quarter we entered into
additional crack spread hedges due to the strength in forward markets, hedging crack spreads on an average of
6,425 barrels per day in 2013 and 2014 at an average of $24.97 per barrel, a $12.81 per barrel
increase over our average hedged crack spreads in 2011.
Our third quarter 2011 total production increased by 5.2% quarter over quarter, due primarily
to our decision to increase production run rates at our Shreveport refinery to take advantage of
strengthened fuel products crack spreads. Production levels at our other facilities, which focus
primarily on the production of specialty products, also increased quarter over quarter to take
advantage of higher specialty products demand.
We improved our cash flow from operations during the third quarter by generating $70.0 million
in the three months ended September 30, 2011 due primarily to our improved operating income before
depreciation. In the first and second quarters of 2011, we used cash in response to increasing
crude inventory levels as a result of terminating certain just-in-time inventory supply
arrangements with a related party, Legacy, effective May 31, 2011, increased working capital
requirements resulting from increased run rates at our Shreveport refinery and higher commodity
prices in general. 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) pay quarterly
distributions to our unitholders, (iii) service our debt obligations and (iv) provide funding for
general partnership purposes.
37
Superior Acquisition
On September 30, 2011, we 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 $411.1 million, excluding customary post-closing
purchase price adjustments (Superior Acquisition). Pursuant to the Superior Acquisition, we
acquired the following (collectively the Superior Business):
|
|
|
Murphy Oils refinery located in Superior, Wisconsin and associated inventories; |
|
|
|
|
Superiors wholesale marketing business and related assets, including certain owned
or leased Murphy Oil product terminals located in Superior and Rhinelander, Wisconsin,
Duluth and Crookston and Proctor, Minnesota and Toole, Utah and associated inventories
and logistics assets located at each of the foregoing facilities; and |
|
|
|
|
Murphy Oils SPUR branded gasoline wholesale business and related assets. |
The Superior refinery produces gasoline, diesel, asphalt and specialty petroleum products that
are marketed in the Midwest region of the U.S., including the surrounding border states, and
Canada. 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 and through its own leased and owned product terminals located in Superior and Rhinelander,
Wisconsin, Duluth, Crookston and Proctor, Minnesota and Toole, Utah. The Superior wholesale
business also sells gasoline wholesale to SPUR branded gas stations, which are owned and operated
by independent franchisees.
We believe the Superior Acquisition provides greater scale, geographic diversity and
development potential to our refining business, as our current total refining throughput capacity
has increased by 50% to 135,000 barrels per day.
The Superior Acquisition was financed by a combination of (i) net proceeds of $193.6 million
from our September 2011 public offering of common units, (ii) net proceeds of $180.3 million from
the September 2011 private placement of 9 3/8% senior notes due May 1, 2019 and (iii) borrowings
under our revolving credit facility.
In addition, subsequent to September 30, 2011, we have entered into additional derivative
contracts to hedge our increased exposure to crack spreads resulting from the Superior Acquisition. We plan to hedge a portion of the Superior refinerys estimated fuels production in 2013 and
2014 consistent with our existing hedging policy.
Key Performance Measures
Our sales and net income are principally affected by the price of crude oil, demand for
specialty and fuel products, prevailing crack spreads for fuel products, the price of natural gas
used as fuel in our operations and our results from derivative instrument activities.
Our primary raw materials are crude oil and other specialty feedstocks and our primary outputs
are specialty petroleum and fuel products. The prices of crude oil, specialty products and fuel
products are subject to fluctuations in response to changes in supply, demand, market uncertainties
and a variety of additional factors beyond our control. We monitor these risks and enter into
financial derivatives designed to mitigate the impact of commodity price fluctuations on our
business. The primary purpose of our commodity risk management activities is to economically hedge
our cash flow exposure to commodity price risk so that we can meet our cash distribution, debt
service and capital expenditure requirements despite fluctuations in crude oil and fuel products
prices. We enter into derivative contracts for future periods in quantities that do not exceed our
projected purchases of crude oil and natural gas and sales of fuel products. Please read Part I
Item 3 Quantitative and Qualitative Disclosures About Market Risk Commodity Price Risk. As of
September 30, 2011, we have hedged approximately 11.7 million barrels of fuel products through
December 2014 at an average refining margin of $17.85 per barrel with average refining margins
ranging from a low of $12.16 per barrel in 2011 to a high of $25.01 per barrel in 2014. In
addition, subsequent to the closing of the Superior Acquisition, we have entered into approximately
6.0 million barrels of fuel products crack spread hedges at an average crack spread of $23.42 per
barrel. Please refer to Note 7 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 Existing Commodity Derivative Instruments for detailed
information regarding our derivative instruments.
38
Our management uses several financial and operational measurements to analyze our performance.
These measurements include the following:
|
|
|
sales volumes; |
|
|
|
|
production yields; and |
|
|
|
|
specialty products and fuel products gross profit. |
Sales volumes. We view the volumes of specialty products and fuel products sold as an
important measure of our ability to effectively utilize our refining assets. Our ability to meet
the demands of our customers is driven by the volumes of crude oil and feedstocks that we run at
our facilities. Higher volumes improve profitability both through the spreading of fixed costs over
greater volumes and the additional gross profit achieved on the incremental volumes.
Production yields. In order to maximize our gross profit and minimize lower margin
by-products, we seek the optimal product mix for each barrel of crude oil we refine, which we refer
to as production yield.
Specialty products and fuel products gross profit. Specialty products and fuel products gross
profit are important measures of our ability to maximize the profitability of our specialty
products and fuel products segments. We define specialty products and fuel products gross profit as
sales less the cost of crude oil and other feedstocks and other production-related expenses, the
most significant portion of which includes labor, plant fuel, utilities, contract services,
maintenance, depreciation and processing materials. We use specialty products and fuel products
gross profit as indicators of our ability to manage our business during periods of crude oil and
natural gas price fluctuations, as the prices of our specialty products and fuel products generally
do not change immediately with changes in the price of crude oil and natural gas. The increase in
selling prices typically lags behind the rising costs of crude oil feedstocks for specialty
products. Other than plant fuel, production-related expenses generally remain stable across broad
ranges of throughput volumes, but can fluctuate depending on maintenance activities performed
during a specific period.
Our fuel products segment gross profit may differ from a standard U.S. Gulf Coast 2/1/1 or
3/2/1 market crack spread due to many factors, including our fuel products mix as shown in our
production table being different than the ratios used to calculate such market crack spreads, the
allocation of by-product (primarily asphalt) losses at the Shreveport refinery to the fuel products
segment, operating costs including fixed costs, derivative activity to hedge our fuel products
segment revenues and cost of crude oil reflected in gross profit and our local market pricing
differential in Shreveport, Louisiana as compared to U.S. Gulf Coast postings.
In addition to the foregoing measures, we also monitor our selling, general and administrative
expenditures, substantially all of which are incurred through our general partner.
Results of Operations for the Three and Nine Months Ended September 30, 2011 and 2010
Production Volume. The following table sets forth information about our combined operations.
Facility production volume differs from sales volume due to changes in inventory.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2011 |
|
|
2010 |
|
|
% Change |
|
|
2011 |
|
|
2010 |
|
|
% Change |
|
|
|
|
|
|
|
(In bpd) |
|
|
|
|
|
|
|
|
|
|
(In bpd) |
|
|
|
|
|
Total sales volume (1) |
|
|
62,337 |
|
|
|
60,163 |
|
|
|
3.6 |
% |
|
|
58,546 |
|
|
|
54,861 |
|
|
|
6.7 |
% |
Total feedstock runs (2) |
|
|
63,567 |
|
|
|
61,678 |
|
|
|
3.1 |
% |
|
|
60,529 |
|
|
|
55,774 |
|
|
|
8.5 |
% |
Facility production: (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Specialty products: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lubricating oils |
|
|
15,017 |
|
|
|
14,707 |
|
|
|
2.1 |
% |
|
|
14,316 |
|
|
|
13,268 |
|
|
|
7.9 |
% |
Solvents |
|
|
10,963 |
|
|
|
10,715 |
|
|
|
2.3 |
% |
|
|
10,717 |
|
|
|
9,240 |
|
|
|
16.0 |
% |
Waxes |
|
|
1,434 |
|
|
|
1,307 |
|
|
|
9.7 |
% |
|
|
1,234 |
|
|
|
1,157 |
|
|
|
6.7 |
% |
Fuels |
|
|
491 |
|
|
|
942 |
|
|
|
(47.9 |
)% |
|
|
519 |
|
|
|
1,023 |
|
|
|
(49.3 |
)% |
Asphalt and other by-products |
|
|
8,984 |
|
|
|
8,079 |
|
|
|
11.2 |
% |
|
|
8,660 |
|
|
|
6,649 |
|
|
|
30.2 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
36,889 |
|
|
|
35,750 |
|
|
|
3.2 |
% |
|
|
35,446 |
|
|
|
31,337 |
|
|
|
13.1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel products: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline |
|
|
9,741 |
|
|
|
8,538 |
|
|
|
14.1 |
% |
|
|
9,660 |
|
|
|
8,674 |
|
|
|
11.4 |
% |
Diesel |
|
|
13,470 |
|
|
|
11,883 |
|
|
|
13.4 |
% |
|
|
11,896 |
|
|
|
10,592 |
|
|
|
12.3 |
% |
Jet fuel |
|
|
4,872 |
|
|
|
5,336 |
|
|
|
(8.7 |
)% |
|
|
4,495 |
|
|
|
5,306 |
|
|
|
(15.3 |
)% |
By-products |
|
|
492 |
|
|
|
735 |
|
|
|
(33.1 |
)% |
|
|
704 |
|
|
|
586 |
|
|
|
20.1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
28,575 |
|
|
|
26,492 |
|
|
|
7.9 |
% |
|
|
26,755 |
|
|
|
25,158 |
|
|
|
6.3 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total facility production (3) |
|
|
65,464 |
|
|
|
62,242 |
|
|
|
5.2 |
% |
|
|
62,201 |
|
|
|
56,495 |
|
|
|
10.1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
39
|
|
|
(1) |
|
Total sales volume includes sales from the production at our facilities and certain
third-party facilities pursuant to supply and/or processing agreements and sales of
inventories. |
|
(2) |
|
Total feedstock runs represent the barrels per day of crude oil and other feedstocks
processed at our facilities and at certain third-party facilities pursuant to supply and/or
processing agreements. The increase in the total feedstock runs for the three months ended
September 30, 2011 compared to the same quarter in 2010 is due primarily to the decision to
increase feedstock run rates at our facilities because of the favorable economics of running
additional barrels. The increase in feedstock runs for the nine months ended September 30,
2011 compared to the same period in 2010 is due primarily to the decision to increase crude
oil run rates at our facilities because of favorable economics of running additional barrels
and the failure of an environmental operating unit at our Shreveport refinery which impacted
run rates in the 2010 period. This increase is partially offset by the impact of the
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. |
|
(3) |
|
Total facility production represents the barrels per day of specialty products and fuel
products yielded from processing crude oil and other feedstocks at our facilities and at
certain third-party facilities, pursuant to supply and/or processing agreements, including
such agreements with LyondellBasell. The difference between total facility production and
total feedstock runs is primarily a result of the time lag between the input of feedstock and
production of finished products and volume loss. The increase in production in the three and
nine months ended September 30, 2011 compared to the same periods in 2010 is due primarily to
higher throughput rates at our Shreveport refinery period over period as discussed above in
footnote 2 of this table. |
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 in accordance with GAAP, please read Non-GAAP Financial Measures.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
|
(In thousands) |
|
|
(In thousands) |
|
Sales |
|
$ |
777,780 |
|
|
$ |
595,273 |
|
|
$ |
2,116,790 |
|
|
$ |
1,594,542 |
|
Cost of sales |
|
|
681,179 |
|
|
|
533,167 |
|
|
|
1,922,760 |
|
|
|
1,451,141 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit |
|
|
96,601 |
|
|
|
62,106 |
|
|
|
194,030 |
|
|
|
143,401 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Selling, general and administrative |
|
|
14,148 |
|
|
|
7,403 |
|
|
|
35,143 |
|
|
|
22,894 |
|
Transportation |
|
|
23,696 |
|
|
|
23,258 |
|
|
|
69,462 |
|
|
|
63,460 |
|
Taxes other than income taxes |
|
|
1,683 |
|
|
|
1,308 |
|
|
|
4,246 |
|
|
|
3,431 |
|
Insurance recoveries |
|
|
|
|
|
|
|
|
|
|
(8,698 |
) |
|
|
|
|
Other |
|
|
543 |
|
|
|
565 |
|
|
|
1,781 |
|
|
|
1,373 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
56,531 |
|
|
|
29,572 |
|
|
|
92,096 |
|
|
|
52,243 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
|
(12,577 |
) |
|
|
(7,794 |
) |
|
|
(30,602 |
) |
|
|
(22,505 |
) |
Debt extinguishment costs |
|
|
|
|
|
|
|
|
|
|
(15,130 |
) |
|
|
|
|
Realized loss on derivative instruments |
|
|
(3,814 |
) |
|
|
(2,288 |
) |
|
|
(5,798 |
) |
|
|
(8,147 |
) |
Unrealized gain (loss) on derivative instruments |
|
|
(20,335 |
) |
|
|
1,931 |
|
|
|
(23,876 |
) |
|
|
(13,835 |
) |
Other |
|
|
45 |
|
|
|
(121 |
) |
|
|
148 |
|
|
|
(170 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expense |
|
|
(36,681 |
) |
|
|
(8,272 |
) |
|
|
(75,258 |
) |
|
|
(44,657 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income before income taxes |
|
|
19,850 |
|
|
|
21,300 |
|
|
|
16,838 |
|
|
|
7,586 |
|
Income tax expense |
|
|
236 |
|
|
|
79 |
|
|
|
674 |
|
|
|
339 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
19,614 |
|
|
$ |
21,221 |
|
|
$ |
16,164 |
|
|
$ |
7,247 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA |
|
$ |
70,548 |
|
|
$ |
44,006 |
|
|
$ |
146,042 |
|
|
$ |
96,265 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable Cash Flow |
|
$ |
50,487 |
|
|
$ |
30,862 |
|
|
$ |
94,076 |
|
|
$ |
45,166 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40
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 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; |
|
|
|
|
the ability of our assets to generate cash sufficient to pay interest costs and
support our indebtedness; |
|
|
|
|
our operating performance and return on capital as compared to those of other
companies in our industry, without regard to financing or capital structure; and |
|
|
|
|
the viability of acquisitions and capital expenditure projects and the overall
rates of return on alternative investment opportunities. |
We believe that these non-GAAP measures are useful to analysts and investors as they exclude
transactions not related to our core cash operating activities and provide metrics to analyze our
ability to pay distributions. We believe that excluding these transactions allows investors to
meaningfully trend and analyze the performance of our core cash operations.
We define EBITDA for any period as net income plus interest expense (including debt issuance
and extinguishment costs), income taxes and depreciation and amortization.
We define Adjusted EBITDA for any period as: (1) net income plus (2)(a) interest expense; (b)
income taxes; (c) depreciation and amortization; (d) unrealized losses from mark to market
accounting for hedging activities; (e) realized gains under derivative instruments excluded from
the determination of net income; (f) non-cash equity based compensation expense and other non-cash
items (excluding items such as accruals of cash expenses in a future period or amortization of a
prepaid cash expense) that were deducted in computing net income; (g) debt refinancing fees,
premiums and penalties and (h) all extraordinary, unusual or non-recurring items of gain or loss,
or revenue or expense; minus (3)(a) unrealized gains from mark to market accounting for hedging
activities; (b) realized losses under derivative instruments excluded from the determination of net
income and (c) other non-recurring expenses and unrealized items that reduced net income for a
prior period, but represent a cash item in the current period.
We define Distributable Cash Flow for any period as Adjusted EBITDA less replacement capital
expenditures, turnaround costs, cash interest expense (consolidated interest expense less non-cash
interest expense) and income tax expense. Distributable Cash Flow is used by us and our investors
to analyze our ability to pay distributions.
The definitions of Adjusted EBITDA and Distributable Cash that are presented in this Quarterly
Report have been updated to reflect the calculation of Consolidated Cash Flow contained in the
indentures governing our 2019 Notes. We are required to report Consolidated Cash Flow to the
holders of our 2019 Notes and Adjusted EBITDA to the lenders under our revolving credit facility,
and these measures are used by them to determine our compliance with certain covenants governing
those debt instruments. Adjusted EBITDA and Distributable Cash Flow that are presented in this
Quarterly Report for prior periods have been updated to reflect the use of the new calculations.
Please refer to Liquidity and Capital Resources Debt and Credit Facilities within this item
for additional details regarding the covenants governing our debt instruments.
EBITDA, Adjusted EBITDA and Distributable Cash Flow should not be considered alternatives to
net income, operating income, net cash provided by (used in) operating activities or any other
measure of financial performance presented in accordance with GAAP. In evaluating our performance
as measured by EBITDA, Adjusted EBITDA and Distributable Cash Flow, management recognizes and
considers the limitations of these measurements. EBITDA, Adjusted EBITDA and Distributable Cash
Flow do not reflect our obligations for the payment of income taxes, interest expense or other
obligations such as capital expenditures. Accordingly, EBITDA, Adjusted EBITDA and Distributable
Cash Flow are only three of the measurements that management utilizes. Moreover, our EBITDA,
Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of
another company because all companies may not calculate EBITDA, Adjusted EBITDA and Distributable
Cash Flow in the same manner. The following tables present a reconciliation of both net income to EBITDA, Adjusted
41
EBITDA and
Distributable Cash Flow, and Distributable Cash Flow, Adjusted EBITDA and EBITDA to net cash
provided by (used in) operating activities, our most directly comparable GAAP financial performance
and liquidity measures, for each of the periods indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
|
(In thousands) |
|
|
(In thousands) |
|
Reconciliation of Net Income to EBITDA, Adjusted EBITDA and
Distributable Cash Flow: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
19,614 |
|
|
$ |
21,221 |
|
|
$ |
16,164 |
|
|
$ |
7,247 |
|
Add: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
|
12,577 |
|
|
|
7,794 |
|
|
|
30,602 |
|
|
|
22,505 |
|
Debt extinguishment costs |
|
|
|
|
|
|
|
|
|
|
15,130 |
|
|
|
|
|
Depreciation and amortization |
|
|
14,680 |
|
|
|
14,908 |
|
|
|
43,644 |
|
|
|
44,410 |
|
Income tax expense |
|
|
236 |
|
|
|
79 |
|
|
|
674 |
|
|
|
339 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA |
|
$ |
47,107 |
|
|
$ |
44,002 |
|
|
$ |
106,214 |
|
|
$ |
74,501 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Add: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized (gain) loss on derivatives |
|
$ |
20,335 |
|
|
$ |
(1,931 |
) |
|
$ |
23,876 |
|
|
$ |
13,835 |
|
Realized gain (loss) on derivatives, not included in net income |
|
|
(771 |
) |
|
|
(594 |
) |
|
|
4,366 |
|
|
|
848 |
|
Amortization of turnaround costs |
|
|
2,542 |
|
|
|
2,539 |
|
|
|
8,288 |
|
|
|
6,639 |
|
Non-cash equity based compensation |
|
|
1,335 |
|
|
|
(10 |
) |
|
|
3,298 |
|
|
|
442 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA |
|
$ |
70,548 |
|
|
$ |
44,006 |
|
|
$ |
146,042 |
|
|
$ |
96,265 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Replacement capital expenditures (1) |
|
|
6,608 |
|
|
|
5,751 |
|
|
|
14,204 |
|
|
|
22,093 |
|
Cash interest expense (2) |
|
|
11,869 |
|
|
|
6,821 |
|
|
|
28,239 |
|
|
|
19,626 |
|
Turnaround costs |
|
|
1,348 |
|
|
|
493 |
|
|
|
8,849 |
|
|
|
9,041 |
|
Income tax expense |
|
|
236 |
|
|
|
79 |
|
|
|
674 |
|
|
|
339 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable Cash Flow |
|
$ |
50,487 |
|
|
$ |
30,862 |
|
|
$ |
94,076 |
|
|
$ |
45,166 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Replacement capital expenditures are defined as those capital expenditures which do not
increase operating capacity or reduce operating costs and exclude turnaround costs. |
|
(2) |
|
Represents consolidated interest expense less non-cash interest expense. |
42
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
|
2011 |
|
|
2010 |
|
|
|
(In thousands) |
|
Reconciliation of Distributable Cash Flow, Adjusted EBITDA and
EBITDA to net cash provided by (used in) operating activities: |
|
|
|
|
|
|
|
|
Distributable Cash Flow |
|
$ |
94,076 |
|
|
$ |
45,166 |
|
Add: |
|
|
|
|
|
|
|
|
Replacement capital expenditures (1) |
|
|
14,204 |
|
|
|
22,093 |
|
Cash interest expense (2) |
|
|
28,239 |
|
|
|
19,626 |
|
Turnaround costs |
|
|
8,849 |
|
|
|
9,041 |
|
Income tax expense |
|
|
674 |
|
|
|
339 |
|
|
|
|
|
|
|
|
Adjusted EBITDA |
|
$ |
146,042 |
|
|
$ |
96,265 |
|
|
|
|
|
|
|
|
Less: |
|
|
|
|
|
|
|
|
Unrealized loss on derivative instruments |
|
|
23,876 |
|
|
|
13,835 |
|
Realized gain on derivatives, not included in net income |
|
|
4,366 |
|
|
|
848 |
|
Amortization of turnaround costs |
|
|
8,288 |
|
|
|
6,639 |
|
Non-cash equity based compensation |
|
|
3,298 |
|
|
|
442 |
|
|
|
|
|
|
|
|
EBITDA |
|
$ |
106,214 |
|
|
$ |
74,501 |
|
|
|
|
|
|
|
|
Add: |
|
|
|
|
|
|
|
|
Unrealized loss on derivative instruments |
|
|
23,876 |
|
|
|
13,835 |
|
Cash interest expense (2) |
|
|
(28,239 |
) |
|
|
(19,626 |
) |
Non-cash equity based compensation |
|
|
3,298 |
|
|
|
442 |
|
Amortization of turnaround costs |
|
|
8,288 |
|
|
|
6,639 |
|
Income tax expense |
|
|
(674 |
) |
|
|
(339 |
) |
Provision for doubtful accounts |
|
|
255 |
|
|
|
74 |
|
Debt extinguishment costs |
|
|
(729 |
) |
|
|
|
|
Changes in assets and liabilities: |
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(44,714 |
) |
|
|
(42,004 |
) |
Inventories |
|
|
(109,787 |
) |
|
|
(12,964 |
) |
Other current assets |
|
|
(2,352 |
) |
|
|
3,664 |
|
Turnaround costs |
|
|
(8,849 |
) |
|
|
(9,041 |
) |
Derivative activity |
|
|
4,928 |
|
|
|
849 |
|
Other assets |
|
|
(197 |
) |
|
|
|
|
Accounts payable |
|
|
54,916 |
|
|
|
68,995 |
|
Other liabilities |
|
|
(4,489 |
) |
|
|
1,842 |
|
Other, including changes in noncurrent assets and liabilities |
|
|
(2,304 |
) |
|
|
835 |
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities |
|
$ |
(559 |
) |
|
$ |
87,702 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Replacement capital expenditures are defined as those capital expenditures which do not
increase operating capacity or reduce operating costs and exclude turnaround costs. |
|
(2) |
|
Represents consolidated interest expense less non-cash interest expense. |
43
Changes in Results of Operations for the Three Months Ended September 30, 2011 and 2010
Sales. Sales increased $182.5 million, or 30.7%, to $777.8 million in the three months ended
September 30, 2011 from $595.3 million in the same period in 2010. Sales for each of our principal
product categories in these periods were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
|
2011 |
|
|
2010 |
|
|
% Change |
|
|
|
(Dollars in thousands, except per barrel data) |
|
Sales by segment: |
|
|
|
|
|
|
|
|
|
|
|
|
Specialty products: |
|
|
|
|
|
|
|
|
|
|
|
|
Lubricating oils |
|
$ |
262,175 |
|
|
$ |
214,926 |
|
|
|
22.0 |
% |
Solvents |
|
|
126,709 |
|
|
|
102,276 |
|
|
|
23.9 |
% |
Waxes |
|
|
38,908 |
|
|
|
34,089 |
|
|
|
14.1 |
% |
Fuels (1) |
|
|
1,047 |
|
|
|
298 |
|
|
|
251.3 |
% |
Asphalt and by-products (2) |
|
|
48,650 |
|
|
|
34,462 |
|
|
|
41.2 |
% |
|
|
|
|
|
|
|
|
|
|
Total specialty products |
|
$ |
477,489 |
|
|
$ |
386,051 |
|
|
|
23.7 |
% |
|
|
|
|
|
|
|
|
|
|
Total specialty products sales volume (in barrels) |
|
|
2,803,000 |
|
|
|
2,958,000 |
|
|
|
(5.2 |
)% |
Average specialty products sales price per barrel |
|
$ |
170.35 |
|
|
$ |
130.51 |
|
|
|
30.5 |
% |
Fuel products: |
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline |
|
$ |
132,286 |
|
|
$ |
73,550 |
|
|
|
79.9 |
% |
Diesel |
|
|
116,914 |
|
|
|
97,405 |
|
|
|
20.0 |
% |
Jet fuel |
|
|
47,190 |
|
|
|
34,998 |
|
|
|
34.8 |
% |
By-products (3) |
|
|
3,901 |
|
|
|
3,269 |
|
|
|
19.3 |
% |
|
|
|
|
|
|
|
|
|
|
Total fuel products |
|
$ |
300,291 |
|
|
$ |
209,222 |
|
|
|
43.5 |
% |
|
|
|
|
|
|
|
|
|
|
Total fuel products sales volume (in barrels) |
|
|
2,932,000 |
|
|
|
2,577,000 |
|
|
|
13.8 |
% |
Average fuel products sales price per barrel (4) |
|
$ |
102.42 |
|
|
$ |
81.19 |
|
|
|
26.1 |
% |
Total sales |
|
$ |
777,780 |
|
|
$ |
595,273 |
|
|
|
30.7 |
% |
|
|
|
|
|
|
|
|
|
|
Total sales volume (in barrels) |
|
|
5,735,000 |
|
|
|
5,535,000 |
|
|
|
3.6 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents fuels produced in connection with the production of specialty products at the
Princeton, Cotton Valley and Karns City refineries. |
|
(2) |
|
Represents asphalt and other by-products produced in connection with the production of
specialty products at the Princeton, Cotton Valley and Shreveport refineries. |
|
(3) |
|
Represents by-products produced in connection with the production of fuels at the Shreveport
refinery. |
|
(4) |
|
Average fuel products sales price per barrel includes impact of hedging contracts. |
Specialty products segment sales for the three months ended September 30, 2011 increased $91.4
million, or 23.7%, as a result of an increase in the average selling price per barrel of $39.84, or
30.5%. The increase is partially offset by a 5.2% decrease in sales volume as compared to the same
period in 2010. Lubricating oils and solvents experienced price increases, driven by improving
overall demand and a 23.4% increase in the average cost of crude oil per barrel for the 2011 period
as compared to the same period in 2010.
Fuel products segment sales for the three months ended September 30, 2011 increased $91.1
million, or 43.5%, due primarily to an increase in the average selling price per barrel (excluding
the impact of hedging activities) of $37.56, or 43.8% and a 13.8% increase in sales volume, driven
by market conditions and higher Shreveport refinery run rates over the prior period. The increase
in the average selling price per barrel of 43.8% compares to a 25.1% increase in the average price
of crude oil per barrel. The average selling price per barrel increased for all fuel products, with
jet fuel and gasoline selling prices experiencing significant increases driven by improved market
pricing. Adversely impacting fuel product sales was a $49.6 million increase in realized derivative
losses on our fuel products cash flow hedges recorded in sales. Please see Gross Profit below for
discussion of the net impact of our crude oil and fuel products derivative instruments designated
as cash flow hedges.
44
Gross Profit. Gross profit increased $34.5 million, or 55.5%, to $96.6 million in the three
months ended September 30, 2011 from $62.1 million in the same period in 2010. Gross profit for our
specialty products and fuel products segments was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
|
2011 |
|
|
2010 |
|
|
% Change |
|
|
|
(Dollars in thousands, except per barrel data) |
|
Gross profit by segment: |
|
|
|
|
|
|
|
|
|
|
|
|
Specialty products |
|
$ |
87,789 |
|
|
$ |
60,880 |
|
|
|
44.2 |
% |
Percentage of sales |
|
|
18.4 |
% |
|
|
15.8 |
% |
|
|
|
|
Specialty products gross profit per barrel |
|
$ |
31.32 |
|
|
$ |
20.58 |
|
|
|
52.2 |
% |
Fuel products |
|
$ |
8,812 |
|
|
$ |
1,226 |
|
|
|
618.8 |
% |
Percentage of sales |
|
|
2.9 |
% |
|
|
0.6 |
% |
|
|
|
|
Fuel products gross profit per barrel |
|
$ |
3.01 |
|
|
$ |
0.48 |
|
|
|
527.1 |
% |
Total gross profit |
|
$ |
96,601 |
|
|
$ |
62,106 |
|
|
|
55.5 |
% |
Percentage of sales |
|
|
12.4 |
% |
|
|
10.4 |
% |
|
|
|
|
The increase in specialty products segment gross profit of $26.9 million quarter over quarter
was due primarily to a 30.5% increase in the average selling price per barrel as discussed above,
partially offset by a 23.4% increase in the average cost of crude oil per barrel, a 5.2% decrease
in sales volume and higher operating costs, primarily repairs and maintenance.
The increase in fuel products segment gross profit of $7.6 million quarter over quarter was
due primarily to a 13.8% increase in sales volume and a 43.8%
increase in the average selling price per
barrel (excluding the impact of realized hedging losses), partially offset by increased realized
losses on derivatives of $38.9 million in our fuel products hedging program, a 25.1% increase in
the average cost of crude oil per barrel and higher operating costs, primarily repairs and maintenance.
Selling, general and administrative. Selling, general and administrative expenses increased
$6.7 million, or 91.1%, to $14.1 million in the three months ended September 30, 2011 from $7.4
million in the same period in 2010. This increase is due primarily to increased accrued incentive
compensation costs of $3.5 million in 2011 compared to 2010 and $2.1 million of acquisition costs
related to the Superior Acquisition with no comparable expenses in 2010.
Interest expense. Interest expense increased $4.8 million, or 61.4%, to $12.6 million in the
three months ended September 30, 2011 from $7.8 million in the three months ended September 30,
2010, due primarily to higher interest rates associated with the 2019 Notes as compared to our term
loan that was repaid in full and extinguished in connection with the issuance of the 2019 Notes.
Realized loss on derivative instruments. Realized loss on derivative instruments increased
$1.5 million to $3.8 million in the three months ended September 30, 2011 from $2.3 million for the
three months ended September 30, 2010. This change was due primarily to a gain of approximately
$0.9 million in the prior period on crack spread derivatives not designated as hedges that were
executed to economically lock in gains on a portion of our fuel products segment derivative hedging
activity with no activity during the three months ended September 30, 2011 and an increase in
ineffectiveness on settled crack spread hedges of approximately $1.9 million. Partially offsetting
these increased realized losses were decreased realized losses of approximately $1.5 million in our
specialty products segment related to crude oil derivatives not designated as hedges.
Unrealized gain (loss) on derivative instruments. Unrealized gain (loss) on derivative
instruments decreased $22.3 million, to a $20.3 million loss in the three months ended September
30, 2011 from a $1.9 million gain in the three months ended September 30, 2010. This change was due
primarily to an increase in ineffectiveness of approximately $21.6 million for the three months
ended September 30, 2011. This increased loss ineffectiveness is due primarily to the continued
widening of the spread between the West Texas Intermediate (NYMEX WTI) crude oil price, upon
which our crude oil derivatives are settled, and other crude oil indices, such as Light Louisiana
Sweet (LLS) and Brent, upon which a portion of our crude oil purchases are based.
45
Changes in Results of Operations for the Nine Months Ended September 30, 2011 and 2010
Sales. Sales increased $522.2 million, or 32.8%, to $2,116.8 million in the nine months ended
September 30, 2011 from $1,594.5 million in the same period in 2010. Sales for each of our
principal product categories in these periods were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
|
2011 |
|
|
2010 |
|
|
% Change |
|
|
|
(Dollars in thousands, except per barrel data) |
|
Sales by segment: |
|
|
|
|
|
|
|
|
|
|
|
|
Specialty products: |
|
|
|
|
|
|
|
|
|
|
|
|
Lubricating oils |
|
$ |
717,674 |
|
|
$ |
555,328 |
|
|
|
29.2 |
% |
Solvents |
|
|
380,687 |
|
|
|
285,907 |
|
|
|
33.2 |
% |
Waxes |
|
|
107,089 |
|
|
|
88,698 |
|
|
|
20.7 |
% |
Fuels (1) |
|
|
2,470 |
|
|
|
4,268 |
|
|
|
(42.1 |
)% |
Asphalt and by-products (2) |
|
|
133,085 |
|
|
|
86,749 |
|
|
|
53.4 |
% |
|
|
|
|
|
|
|
|
|
|
Total specialty products |
|
$ |
1,341,005 |
|
|
$ |
1,020,950 |
|
|
|
31.3 |
% |
|
|
|
|
|
|
|
|
|
|
Total specialty products sales volume (in barrels) |
|
|
8,249,000 |
|
|
|
7,894,000 |
|
|
|
4.5 |
% |
Average specialty products sales price per barrel |
|
$ |
162.57 |
|
|
$ |
129.33 |
|
|
|
25.7 |
% |
Fuel products: |
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline |
|
$ |
355,519 |
|
|
$ |
225,720 |
|
|
|
57.5 |
% |
Diesel |
|
|
290,678 |
|
|
|
239,031 |
|
|
|
21.6 |
% |
Jet fuel |
|
|
114,650 |
|
|
|
100,378 |
|
|
|
14.2 |
% |
By-products (3) |
|
|
14,938 |
|
|
|
8,463 |
|
|
|
76.5 |
% |
|
|
|
|
|
|
|
|
|
|
Total fuel products |
|
$ |
775,785 |
|
|
$ |
573,592 |
|
|
|
35.3 |
% |
|
|
|
|
|
|
|
|
|
|
Total fuel products sales volume (in barrels) |
|
|
7,734,000 |
|
|
|
7,083,000 |
|
|
|
9.2 |
% |
Average fuel products sales price per barrel (4) |
|
$ |
100.31 |
|
|
$ |
80.98 |
|
|
|
23.9 |
% |
Total sales |
|
$ |
2,116,790 |
|
|
$ |
1,594,542 |
|
|
|
32.8 |
% |
|
|
|
|
|
|
|
|
|
|
Total sales volume (in barrels) |
|
|
15,983,000 |
|
|
|
14,977,000 |
|
|
|
6.7 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents fuels produced in connection with the production of specialty products at the
Princeton, Cotton Valley and Karns City refineries. |
|
(2) |
|
Represents asphalt and other by-products produced in connection with the production of
specialty products at the Princeton, Cotton Valley and Shreveport refineries. |
|
(3) |
|
Represents by-products produced in connection with the production of fuels at the Shreveport
refinery. |
|
(4) |
|
Average fuel products sales price per barrel includes impact of hedging contracts. |
Specialty products segment sales for the nine months ended September 30, 2011 increased $320.1
million, or 31.3%, as a result of an increase in the average selling price per barrel of $33.24, or
25.7%, and a 4.5% increase in sales volume as compared to the same period in 2010. Lubricating
oils, solvents and asphalt and by-products experienced price increases, driven by improving overall
demand and a 28.3% increase in the average cost of crude oil per barrel for the 2011 period as
compared to the same period in 2010. The increased volume is due primarily to improving overall
specialty products demand as a result of improved economic conditions and higher refinery run rates
over the prior period.
Fuel products segment sales for the nine months ended September 30, 2011 increased $202.2
million, or 35.3%, due primarily to an increase in the average selling price per barrel (excluding
the impact of hedging activities) of $35.33, or 40.9%, driven by market conditions compared to a
29.5% increase in the average price of crude oil per barrel and a 9.2% increase in sales volume.
The average selling price per barrel increased for all fuel products, with gasoline and diesel
selling prices experiencing significant increases driven by improved market pricing. Adversely
impacting fuel products sales was a $127.4 million increase in realized derivative losses on our
fuel products cash flow hedges recorded in sales. Please see Gross Profit below for discussion of
the net impact of our crude oil and fuel products derivative instruments designated as cash flow
hedges.
46
Gross Profit. Gross profit increased $50.6 million, or 35.3%, to $194.0 million in the nine
months ended September 30, 2011 from $143.4 million in the same period in 2010. Gross profit for
our specialty products and fuel products segments was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
|
2011 |
|
|
2010 |
|
|
% Change |
|
|
|
(Dollars in thousands, except per barrel data) |
|
Gross profit by segment: |
|
|
|
|
|
|
|
|
|
|
|
|
Specialty products |
|
$ |
193,988 |
|
|
$ |
130,706 |
|
|
|
48.4 |
% |
Percentage of sales |
|
|
14.5 |
% |
|
|
12.8 |
% |
|
|
|
|
Specialty products gross profit per barrel |
|
$ |
23.52 |
|
|
$ |
16.56 |
|
|
|
42.0 |
% |
Fuel products |
|
$ |
42 |
|
|
$ |
12,695 |
|
|
|
(99.7 |
)% |
Percentage of sales |
|
|
0.0 |
% |
|
|
2.2 |
% |
|
|
|
|
Fuel products gross profit per barrel |
|
$ |
0.01 |
|
|
$ |
1.79 |
|
|
|
(99.4 |
)% |
Total gross profit |
|
$ |
194,030 |
|
|
$ |
143,401 |
|
|
|
35.3 |
% |
Percentage of sales |
|
|
9.2 |
% |
|
|
9.0 |
% |
|
|
|
|
The increase in specialty products segment gross profit of $63.3 million for the nine months
ended September 30, 2011 compared to the same period in 2010 was due primarily to a 4.5% increase
in sales volume and a 25.7% increase in the average selling price per barrel as discussed above,
partially offset by a 28.3% increase in the average cost of crude oil per barrel and higher
operating costs, primarily repair and maintenance.
The decrease in fuel products segment gross profit of $12.7 million for the nine months ended
September 30, 2011 compared to the same period in 2010 was due primarily to increased realized
losses on derivatives of $94.0 million in our fuel products hedging program, a 29.5% increase in
the cost of crude oil per barrel and increased production of by-products, partially offset by a
9.2% increase in sales volume and a 40.9% increase in selling prices per barrel, excluding the
impact of realized hedging losses. During the second quarter of 2011, our fuel products hedged
volumes, combined with lower refinery run rates, resulted in our diesel and jet fuel sales volumes
being approximately 100% hedged at approximately $12.00 per barrel, preventing us from realizing
the benefit of increased market crack spreads for these products. By-product production increased
in the 2011 period as compared to the 2010 period due primarily to an increase in run rates at the Shreveport refinery.
Selling, general and administrative. Selling, general and administrative expenses increased
$12.2 million, or 53.5%, to $35.1 million in the nine months ended September 30, 2011 from $22.9
million in 2010. This increase is due primarily to increased accrued incentive compensation costs
of $6.5 million in 2011 compared to 2010 and $2.1 million of acquisition costs related to the
Superior Acquisition with no comparable costs in 2010, as well as increased overall salaries and
wages and advertising.
Transportation. Transportation expenses increased $6.0 million, or 9.5%, to $69.5 million in
the nine months ended September 30, 2011 from $63.5 million in the same period in 2010. This
increase is due primarily to increased sales volumes of lubricating oils, solvents and waxes, as
well as higher freight costs.
Insurance recoveries. Insurance recoveries were $8.7 million for the nine months ended
September 30, 2011. The gain was related to a claim settled in the second quarter of 2011 with
insurers related to the failure of an environmental operating unit at the Shreveport refinery in
2010.
Interest expense. Interest expense increased $8.1 million, or 36.0%, to $30.6 million in the
nine months ended September 30, 2011 from $22.5 million in the nine months ended September 30,
2010, due primarily to higher interest rates associated with the 2019 Notes as compared to our term
loan that was repaid in full and extinguished in connection with the issuance of the 2019 Notes.
Debt extinguishment costs. Debt extinguishment costs were $15.1 million during the nine months
ended September 30, 2011. The debt extinguishment costs were related to the extinguishment of the
term loan with proceeds from the issuance of the 2019 Notes.
Realized loss on derivative instruments. Realized loss on derivative instruments decreased
$2.3 million to $5.8 million in the nine months ended September 30, 2011 from $8.1 million for the
nine months ended September 30, 2010. This change was due primarily to a gain of approximately $3.0
million on crack spread derivatives not designated as hedges that were executed to economically lock in
gains on a portion of our fuel products segment derivative hedging activity with no activity during
the nine months ended September 30, 2011, and an increase in ineffectiveness on settled crack
spread hedges of approximately $0.6 million. Partially offsetting these increased realized losses
were decreased realized losses of approximately $7.0 million in our specialty products segment
related to crude oil derivatives not designate as hedges.
47
Unrealized loss on derivative instruments. Unrealized loss on derivative instruments increased
$10.0 million, to $23.9 million in the nine months ended September 30, 2011 from $13.8 million in
the nine months ended September 30, 2010. The increased loss is due primarily to an increase in
ineffectiveness of $11.2 million during the quarter ended September 30, 2011. This increased loss
ineffectiveness is due primarily to the continued widening of the spread between the NYMEX WTI
crude oil price, upon which our crude oil derivatives are settled, and other crude oil indices,
such as LLS and Brent, upon which a portion of our crude oil purchases are based.
Liquidity and Capital Resources
The following should be read in conjunction with Managements Discussion and Analysis of
Financial Condition and Results of Operations Liquidity and Capital Resources included under
Part I Item 7 in our 2010 Annual Report. There have been no material changes in that information
other than as discussed below. Also, see Note 6 under Part I Item 1 Financial Statements Notes
to Unaudited Condensed Consolidated Financial Statements for additional discussion related to
long-term debt.
Our principal sources of cash have historically included cash flow from operations, proceeds
from public equity offerings, proceeds from notes offerings and bank borrowings. Principal uses of
cash have included capital expenditures, acquisitions, distributions to our unitholders and general
partner and debt service. We expect that our principal uses of cash in the future will be for
distributions to our limited partners and general partner, debt service, replacement and
environmental capital expenditures and capital expenditures related to internal growth projects and
acquisitions from third parties or affiliates. We expect to fund future capital expenditures with
current cash flow from operations and borrowings under our revolving credit facility. Future
internal growth projects or acquisitions may require expenditures in excess of our then-current
cash flow from operations and borrowings under our existing revolving credit facility and may
require us to issue debt or equity securities in public or private offerings or incur additional
borrowings under bank credit facilities to meet those costs.
Cash Flows
We believe that we have sufficient liquid assets, cash flow from operations and borrowing
capacity to meet our financial commitments, debt service obligations and anticipated capital
expenditures. However, we are subject to business and operational risks that could materially
adversely affect our cash flows. A material decrease in our cash flow from operations including a
significant, sudden decrease in crude oil prices would likely produce a corollary material adverse
effect on our borrowing capacity under our revolving credit facility and potentially our ability to
comply with the covenants under our credit facilities. A significant, sudden increase in crude oil
prices, if sustained, would likely result in increased working capital requirements which would be
funded by borrowings under our revolving credit facility.
The following table summarizes our primary sources and uses of cash in each of the periods
presented:
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
|
2011 |
|
|
2010 |
|
|
|
(In thousands) |
|
Net cash provided by (used in) operating activities |
|
$ |
(559 |
) |
|
$ |
87,702 |
|
Net cash used in investing activities |
|
$ |
(470,132 |
) |
|
$ |
(27,109 |
) |
Net cash provided by (used in) financing activities |
|
$ |
470,720 |
|
|
$ |
(60,554 |
) |
Operating Activities. Operating activities used cash of $0.6 million during the nine months
ended September 30, 2011 compared to providing cash of $87.7 million during the same period in
2010. The change was due primarily to increases in working capital requirements of $111.4 million,
primarily from increased crude oil inventory levels as a result of terminating certain just-in-time
inventory supply arrangements with a related party, Legacy, effective May 31, 2011, increased
working capital requirements resulting from increased run rates at our Shreveport facility and
higher commodity prices in general, partially offset by insurance recoveries related to a settled
claim with insurers during the second quarter of 2011 resulting from the failure of an
environmental operating unit at the Shreveport refinery in 2010.
Investing Activities. Cash used in investing activities increased to $470.1 million during the
nine months ended September 30, 2011 compared to $27.1 million during the nine months ended
September 30, 2010. The increase is due primarily to the acquisition of the assets and assumption
of liabilities in conjunction with the Superior Acquisition which closed on September 30, 2011 for
$411.1 million, with no similar acquisition activities in the
prior year.
48
Financing Activities. Financing activities provided cash of $470.7 million for the nine months
ended September 30, 2011 compared to cash used of $60.6 million during the nine months ended
September 30, 2010. The increase is due primarily to the net proceeds from the February 2011 and
September 2011 public equity offerings of $281.9 million and proceeds from the 2019 Notes offerings
of $586.0 million, net of discount, in the second and third quarters of 2011, partially offset by
$23.1 million of debt issuance costs, the $367.4 million repayment of the senior secured first lien
term loan and $56.4 million of distributions to our unitholders.
On October 11, 2011, we declared a quarterly cash distribution of $0.50 per unit on all
outstanding units, or approximately $26.4 million in aggregate, for the quarter ended September 30,
2011. The distribution will be paid on November 14, 2011 to unitholders of record as of the close
of business on November 4, 2011. This quarterly distribution of $0.50 per unit equates to $2.00 per
unit, or approximately $105.4 million in aggregate on an annualized basis.
Capital Expenditures
Our capital expenditure requirements consist of capital improvement expenditures, replacement
capital expenditures and environmental capital expenditures. Capital improvement expenditures
include expenditures to acquire assets to grow our business, to expand existing facilities, such as
projects that increase operating capacity, or to reduce operating costs. Replacement capital
expenditures replace worn out or obsolete equipment or parts. Environmental capital expenditures
include asset additions to meet or exceed environmental and operating regulations.
The following table sets forth our capital improvement expenditures, replacement capital
expenditures and environmental capital expenditures in each of the periods shown.
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
|
2011 |
|
|
2010 |
|
|
|
(In thousands) |
|
Capital improvement expenditures |
|
$ |
16,463 |
|
|
$ |
5,217 |
|
Replacement capital expenditures |
|
|
10,595 |
|
|
|
13,546 |
|
Environmental capital expenditures |
|
|
3,609 |
|
|
|
8,547 |
|
|
|
|
|
|
|
|
Total |
|
$ |
30,667 |
|
|
$ |
27,310 |
|
|
|
|
|
|
|
|
We anticipate that future capital expenditure requirements will be provided primarily through
cash from operations and available borrowings under our revolving credit facility. We estimate our
replacement and environmental capital expenditures will be approximately $15.0 million for the
remainder of 2011, with total replacement and environmental capital expenditures, excluding capital
expenditures related to the Superior refinery, remaining below 2010 levels. These estimated amounts
for 2011 include a portion of the $11.0 million to $15.0 million in environmental projects to be
spent over the next five years as required by our settlement with the LDEQ under the Small
Refinery and Single Site Refining Initiative. Please read Note 5 of Part I Item 1 Financial
Statements Commitments and Contingencies Environmental for additional information. Our
capital improvement expenditures have increased due to various minor capital improvement projects
to reduce energy costs, improve finished product quality and improve finished product yields. We do
not expect to incur significant capital improvement expenditures for the remainder of 2011.
49
Debt and Credit Facilities
As of September 30, 2011, our debt and credit facilities consisted of:
|
|
|
a $850.0 million senior secured revolving credit facility, subject to borrowing base
restrictions, with a maximum letter of credit sublimit equal to $680.0 million, which is the
greater of (i) $400.0 million and (ii) 80% of revolver commitments then in effect; and |
|
|
|
|
$600.0 million of 9 3/8% senior notes due 2019. |
Amended and Restated Senior Secured Revolving Credit Facility
On June 24, 2011, we entered into an amended and restated senior secured revolving credit
facility (the revolving credit facility), which increased the maximum availability of credit
under the revolving credit facility from $375.0 million to $550.0 million, subject to borrowing
base limitations, and included a $300.0 million incremental uncommitted expansion option. On
September 30, 2011, in conjunction with the Superior Acquisition, we fully exercised the $300.0
million expansion option to increase the maximum availability of credit under the revolving credit
facility from $550.0 million to $850.0 million, subject to borrowing base limitations. The lenders under our
revolving credit facility, which matures in June 2016, have a first priority lien on our cash,
accounts receivable, inventory and certain other personal property.
Our revolving credit facility contains various covenants that limit, among other things, our
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. The revolving credit facility generally permits us to make cash
distributions to our unitholders as long as immediately after giving effect to such a cash
distribution we have 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) $45.0 million. Further, the revolving
credit facility contains one springing financial covenant which provides that only if our
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 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, (as increased, upon the effectiveness of the increase
in the maximum availability under our revolving credit facility, by the same percentage as the percentage increase
in our revolving credit agreement commitments), we will be required to maintain as of the end of each fiscal quarter
a Fixed Charge Coverage Ratio (as defined in the credit agreement) of at least 1.0 to 1.0.
Borrowings under the revolving credit facility are limited to a borrowing base that is
determined based on advance rates of percentages of Eligible Accounts Receivable and Inventory (as
defined in the revolving credit agreement). As such, the borrowing base can fluctuate based on
changes in selling prices of our products and our current material costs, primarily the cost of
crude oil. On September 30, 2011, we had availability on our revolving credit facility of $271.5
million, based on a $535.5 million borrowing base, $208.0 million in outstanding standby letters of
credit and outstanding borrowings of $56.0 million. The borrowing base cannot exceed the revolving
credit facility commitments then in effect. The lender group under our revolving credit facility is
comprised of a syndicate of thirteen lenders with total commitments of $850.0 million.
The revolving credit facility, which is our primary source of liquidity for cash needs in
excess of cash generated from operations, currently bears interest at a rate equal to prime plus a
basis points margin or LIBOR plus a basis points margin, at our option. As of September 30, 2011,
this margin was 125 basis points for prime and 250 basis points for LIBOR; however, the margin
fluctuates quarterly based on our average availability for additional borrowings under the
revolving credit facility in the preceding calendar quarter as follows:
|
|
|
|
|
|
|
|
|
Quarterly Average |
|
Margin on Base Rate |
|
Margin on LIBOR |
Availability Percentage |
|
Revolving Loans |
|
Revolving Loans |
≥ 66% |
|
|
1.00 |
% |
|
|
2.25 |
% |
≥ 33% and < 66% |
|
|
1.25 |
% |
|
|
2.50 |
% |
< 33% |
|
|
1.50 |
% |
|
|
2.75 |
% |
If an event of default exists under the revolving credit facility, the lenders will be able to
accelerate the maturity of the credit facility and exercise other rights and remedies. An event of
default includes, among other things, the nonpayment of principal, interest, fees or other amounts;
failure of any representation or warranty to be true and correct when made or confirmed; failure to
perform or observe covenants in
50
the revolving credit facility or other loan documents, subject, in
limited circumstances, to certain grace periods; cross-defaults in other indebtedness if the effect
of such default is to cause, or permit the holders of such indebtedness to cause, the acceleration
of such indebtedness under any material agreement; bankruptcy or insolvency events; monetary
judgment defaults; asserted invalidity of the loan documentation; and a change of control over us.
Amounts outstanding under our revolving credit facility fluctuate materially during each
quarter due to normal changes in working capital, payments of quarterly distributions to
unitholders and debt service costs. Specifically, the amount borrowed under our revolving credit
facility is typically at its highest level after we pay for the majority of our crude oil supplies
on the 20th day of every month per standard industry terms. The maximum revolving credit facility
borrowings during the third quarter of 2011 were $101.5 million. Nonetheless, our availability on
our revolving credit facility during the peak borrowing days of a quarter has been ample to support
our operations and service upcoming requirements. During the quarter ended September 30, 2011,
availability for additional borrowings under our revolving credit facility was approximately $122.1
million at its lowest point. We believe that we will continue to have sufficient cash flow from
operations and borrowing availability under our revolving credit facility to meet our financial
commitments, minimum quarterly distributions to our unitholders, debt service obligations, credit
agreement covenants, contingencies and anticipated capital expenditures.
9 3/8% Senior Notes
On April 21, 2011, in connection with the restructuring of the majority of our outstanding
long-term debt, we issued and sold $400.0 million 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. We
received proceeds of $389.0 million net of underwriters fees and expenses, which we used to repay
in full borrowings outstanding under our existing senior secured first lien term loan facility, as
well as all accrued interest and fees, and for general partnership purposes.
On September 19, 2011, in connection with the Superior Acquisition, we issued and sold $200.0
million 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. We
received proceeds of $180.3 million net of discount, underwriters fees and expenses, which the we
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 Quarterly Report, we collectively refer 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 will be 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 guaranteed on a senior unsecured basis by all of our
operating subsidiaries and certain of our future operating subsidiaries.
At any time prior to May 1, 2014, we 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, we 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:
|
|
|
|
|
Year |
|
Percentage |
|
2015 |
|
|
104.688 |
% |
2016 |
|
|
102.344 |
% |
2017 and at any time thereafter |
|
|
100.000 |
% |
Prior to May 1, 2015, we 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.
51
The indentures governing the 2019 Notes contain covenants that, among other things, restrict
our ability and the ability of certain of our subsidiaries to: (i) sell assets; (ii) pay
distributions on, redeem or repurchase our common units or redeem or repurchase our 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 our restricted subsidiaries to us; (vii) consolidate, merge or transfer all or
substantially all of our 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 either of Moodys Investors Service,
Inc. or Standard & Poors 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 we repurchase all or a portion of such holders 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.
In connection with the 2019 Notes offering on April 21, 2011, our then current senior secured
revolving credit facility was amended on April 15, 2011 to, among other things, (i) permit the
issuance of the 2019 Notes issued in April 2011; (ii) upon consummation of the issuance of the 2019
Notes issued in April 2011 and the termination of the senior secured first lien credit facility,
release the revolving credit facility lenders second priority lien on the collateral securing the
senior secured first lien credit facility and (iii) change the interest rate pricing on the
revolving credit facility.
Registration Rights Agreements
On April 21, 2011 and September 19, 2011, in connection with the issuances and sales of the
2019 Notes, we entered into registration rights agreements with the initial purchasers of the 2019
Notes obligating us to use reasonable best efforts to file an exchange registration statement with
the SEC so that holders of the 2019 Notes can 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. We must use reasonable best efforts to cause the exchange offer registration statement
to become effective by April 20, 2012 and remain effective until 180 days after the closing of the
exchange. Additionally, we have 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, we must use reasonable best efforts to file
a shelf registration statement for the resale of the 2019 Notes. If we fail to satisfy these
obligations on a timely basis, the annual interest borne by the 2019 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.
Senior Secured First Lien Credit Facility
On April 21, 2011, we used approximately $369.5 million of the net proceeds from the issuance
and sale of the 2019 Notes issued in April 2011 to repay in full our 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 $50.0 million prefunded letter of credit to support crack spread hedging. We
did not incur any material early termination penalties in connection with our termination of the
senior secured first lien credit facility. Further, in the second quarter of 2011 we recorded
approximately $15.1 million of extinguishment charges related to the write off of the unamortized
debt issuance costs and the unamortized discount associated with the term loan.
Borrowings under the senior secured first lien credit facility were used (i) to finance a
portion of the acquisition of Penreco in 2008, (ii) to fund the anticipated growth in working
capital and remaining capital expenditures associated with our Shreveport refinery expansion
project completed in 2008, (iii) to refinance our then-existing term loan facility, (iv) to issue a
$50.0 million letter credit to secure our obligations under one of our master derivative contracts
and (v) for general partnership purposes. Each lender under the senior secured first lien credit
facility generally had a first priority lien on our fixed assets and a second priority lien on our
cash, accounts receivable, inventory and certain other personal property. The senior secured first
lien credit facility would have matured in January 2015.
52
Amendments to Master Derivative Contracts
In connection with the termination of the term loan facility and the amendment of our senior
secured revolving credit facility, on April 21, 2011, we entered into amendments to certain of our
master derivatives contracts to provide new credit support arrangements to secure our payment
obligations under these contracts following the termination of the term loan facility and the
amendment and restatement of our senior secured revolving credit facility. Under the new credit
support arrangements, our payment obligations under all of our master derivatives contracts for
commodity hedging generally are secured by a first priority lien on our and our subsidiaries 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). We also issued to one counterparty a
$25.0 million standby letter of credit under the revolving credit facility to replace a prefunded
$50.0 million letter of credit previously issued under the senior secured first lien credit
facility. In the event that such counterpartys exposure to us exceeds $200.0 million, we 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. We had no additional letters of
credit or cash margin posted with any hedging counterparty as of September 30, 2011. Our master
derivatives contracts and Collateral Trust Agreement (described below) continue to impose a number
of covenant limitations on our operating and financing activities, including limitations on liens
on collateral, limitations on dispositions of collateral and collateral maintenance and insurance
requirements. For financial reporting purposes, we do not offset the collateral provided to a
counterparty against the fair value of its obligation to that counterparty. Any outstanding
collateral is released to us upon settlement of the related derivative instrument liability.
The fair value of our derivatives increased by approximately $32.0 million subsequent to
September 30, 2011 to a liability of approximately $129.0 million. All credit support thresholds
with our hedging counterparties are at levels such that it would take a substantial increase in
fuel products crack spreads to require significant additional collateral to be posted. As a result,
we do not expect further increases in fuel products crack spreads to significantly impact our
liquidity.
Collateral Trust Agreement
In connection with the Amendments, on April 21, 2011, we entered into a collateral sharing
agreement (the Collateral Trust Agreement) with each of the 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 us to the secured hedging counterparties under their respective master
derivatives contracts. Subject to certain conditions set forth in the Collateral Trust Agreement,
we have the ability to add secured hedging counterparties thereto.
In connection with the closing of the Superior Acquisition, on September 30, 2011, we entered
into an amendment (the CTA Amendment) to the Collateral Trust Agreement with each of the secured
hedging counterparties and the administrative agent. The CTA Amendment modified the Collateral
Trust Agreement so as to limit to $100.0 million 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.
Contractual Obligations and Commercial Commitments
The following table summarizes our contractual cash obligations as of September 30, 2011 at
current maturities and reflects only those line items that are materially changed since December
31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period |
|
|
|
|
|
|
|
Less Than |
|
|
1-3 |
|
|
3-5 |
|
|
More Than |
|
|
|
Total |
|
|
1 Year |
|
|
Years |
|
|
Years |
|
|
5 Years |
|
|
|
(In thousands) |
Operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest on long-term debt at contractual rates (1) |
|
$ |
461,533 |
|
|
$ |
67,159 |
|
|
$ |
125,480 |
|
|
$ |
123,582 |
|
|
$ |
145,312 |
|
Operating lease obligations (2) |
|
|
49,889 |
|
|
|
18,836 |
|
|
|
23,622 |
|
|
|
6,516 |
|
|
|
915 |
|
Letters of credit (3) |
|
|
207,960 |
|
|
|
207,960 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase commitments (4) |
|
|
1,575,693 |
|
|
|
1,094,990 |
|
|
|
463,690 |
|
|
|
17,013 |
|
|
|
|
|
Financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital lease obligations |
|
|
1,042 |
|
|
|
749 |
|
|
|
293 |
|
|
|
|
|
|
|
|
|
Long-term debt obligations, excluding capital
lease obligations |
|
|
656,000 |
|
|
|
|
|
|
|
|
|
|
|
56,000 |
|
|
|
600,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total obligations |
|
$ |
2,952,117 |
|
|
$ |
1,389,694 |
|
|
$ |
613,085 |
|
|
$ |
203,111 |
|
|
$ |
746,227 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
53
|
|
|
(1) |
|
Interest on long-term debt at contractual rates and maturities relates primarily to our 2019
Notes and revolving credit facility. |
|
(2) |
|
We have various operating leases primarily for the use of land, storage tanks, pressure
stations, railcars, equipment, precious metals and office facilities that extend through June
2026. |
|
(3) |
|
Letters of credit primarily supporting crude oil purchases, precious metals leasing and
hedging activities. |
|
(4) |
|
Purchase commitments consist primarily of obligations to purchase fixed volumes of crude oil
and other feedstocks and finished products for resale from various suppliers based on current
market prices at the time of delivery. |
In connection with the closing of the acquisition of Penreco on January 3, 2008, we entered
into a feedstock purchase agreement with ConocoPhillips related to the LVT unit at its Lake
Charles, Louisiana refinery (the LVT Feedstock Agreement). Pursuant to the LVT Feedstock
Agreement, ConocoPhillips is obligated to supply a minimum quantity (the Base Volume) of
feedstock for the LVT unit for a term of ten years. Based upon this minimum supply quantity, we
expect to purchase $71.9 million of feedstock for the LVT unit in each fiscal year of the term
based on pricing estimates as of September 30, 2011. This amount is not included in the table
above. If the Base Volume is not supplied at any point during the first five years of the ten year
term, a penalty for each gallon of shortfall must be paid to us as liquidated damages.
In connection with the Superior Acquisition, we assumed pension plan liabilities, estimated at $17.2 million as of September 30, 2011. Due to the timing of the acquisition, the purchase price
allocation and final opening balance sheet have not been finalized, and the breakout between
periods cannot be determined at this time. We expect to make total contributions of $0.2 million to
this pension plan during the remainder of 2011.
Off-Balance Sheet Arrangements
We have no material off-balance sheet arrangements.
Critical Accounting Policies and Estimates
For additional discussion regarding our critical accounting policies and estimates, see
Critical Accounting Policies and Estimates under Part I Item 7 of our 2010 Annual Report.
Recent Accounting Pronouncements
For additional discussion regarding recent accounting pronouncements, see Note 2 under Part I
Item 1 Financial Statements Notes to Unaudited Condensed Consolidated Financial Statements.
Equity Transactions
In February 2011, we satisfied the last of the earnings and distributions 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 on February 14, 2011. Two days following this quarterly
distribution to our unitholders, or February 16, 2011, all of the outstanding subordinated units
automatically converted to common units.
On February 24, 2011, we completed an equity offering of our common units in which we 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 us from this offering (net of underwriting discounts,
commissions and expenses but before our general partners capital contribution) were $92.3 million.
The net proceeds were used to repay borrowings under our revolving credit facility and for general
partnership purposes. Underwriting discounts totaled $3.9 million. Our general partner contributed
$2.0 million to retain its 2% general partner interest.
On September 8, 2011, we completed an equity offering of our common units in which we sold
11,000,000 common units to the
underwriters of the offering at a price of $18.00 per common unit. The proceeds received by
us from this offering (net of underwriting discounts, commissions and expenses but before its
general partners capital contribution) were $189.6 million and were used to fund a portion of the
purchase price of the Superior Acquisition. Underwriting discounts totaled $7.9 million. Our
general partner contributed $4.0 million to retain its 2% general partner interest.
54
On October 13, 2011, the underwriters of our September 8, 2011 public equity offering elected
to exercise a portion of their overallotment option. As a result, we sold an additional 750,000
common units to the underwriters at the offering price of $18.00 per unit, less the underwriting
discount. The proceeds received by us from this offering (net of underwriting discounts,
commissions and expenses but before our general partners capital contribution) were $12.9 million
and were used to repay borrowings under our revolving credit facility. Underwriting discounts
totaled $0.5 million. Our general partner contributed $0.3 million to retain its 2% general
partner interest.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
The following should be read in conjunction with Quantitative and Qualitative Disclosures
About Market Risk included under Part I Item 7A in our 2010 Annual Report. There have been no
material changes in that information other than as discussed below. Also, see Note 7 under Part I
Item 1 Financial Statements Notes to Unaudited Condensed Consolidated Financial Statements for
additional discussion related to derivative instruments and hedging activities.
Commodity Price Risk
Holding all other variables constant, we expect a $1 increase in the applicable commodity
prices would change our recorded mark-to-market valuation by the following amounts based upon the
volumes hedged as of September 30, 2011:
|
|
|
|
|
|
|
In millions |
|
Crude oil swaps |
|
$ |
11.7 |
|
Diesel swaps |
|
$ |
(3.7 |
) |
Jet fuel swaps |
|
$ |
(7.5 |
) |
Gasoline swaps |
|
$ |
(0.5 |
) |
Interest Rate Risk
Our profitability and cash flows are affected by changes in interest rates, specifically LIBOR
and prime rates. The primary purpose of our interest rate risk management activities is to hedge
our exposure to changes in interest rates. Historically, our policy has been to enter into interest
rate swap agreements to hedge up to 75% of our interest rate risk related to variable rate debt.
With the issuances of our 2019 Notes, which constitute fixed rate debt, we do not expect to enter
into additional hedges to fix our interest rates.
We are exposed to market risk from fluctuations in interest rates. As of September 30, 2011,
we had approximately $56.0 million of variable rate debt outstanding under our revolving credit
facility. Holding other variables constant (such as debt levels), a one hundred basis point change
in interest rates on our variable rate debt as of September 30, 2011 would be expected to have an
impact on net income and cash flows for 2011 of approximately $0.6 million.
Existing Commodity Derivative Instruments
We are also subject to the risk that the crude oil and fuel products derivatives we use to
hedge against fuel products crack spread volatility do not provide adequate protection against
volatility. All of the crude oil derivatives in our hedge portfolio are based on the market price
of NYMEX WTI and the fuel products derivatives are all based on U.S. Gulf Coast market prices. In
recent periods, the spread between NYMEX WTI and other crude oil indices (specifically LLS and
Brent on which a portion of our crude oil purchases are based) has widened, which has led to more
of our crude oil hedges not being as effective. To the extent the spread between NYMEX WTI and the
other crude oil indices stays at current levels or continues to widen, our hedges could continue to
become less effective and not provide adequate protection against crude oil price volatility.
Fuel Products Segment
The following table provides a summary of the implied crack spreads for the crude oil, diesel,
jet fuel and gasoline swaps as of September 30, 2011 disclosed in Note 7 under Part I Item 1
Financial Statements Notes to Unaudited Condensed Consolidated Financial Statements, all of
which are designated as cash flow hedges.
55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Implied Crack |
|
Crude Oil and Fuel Products Swap Contracts by Expiration Dates |
|
Barrels |
|
|
BPD |
|
|
Spread ($/Bbl) |
|
Fourth Quarter 2011 |
|
|
1,334,000 |
|
|
|
14,500 |
|
|
$ |
12.16 |
|
Calendar Year 2012 |
|
|
5,626,000 |
|
|
|
15,372 |
|
|
|
13.27 |
|
Calendar Year 2013 |
|
|
3,690,000 |
|
|
|
10,110 |
|
|
|
24.95 |
|
Calendar Year 2014 |
|
|
1,000,000 |
|
|
|
2,740 |
|
|
|
25.01 |
|
|
|
|
|
|
|
|
|
|
|
|
Totals |
|
|
11,650,000 |
|
|
|
|
|
|
|
|
|
Average price |
|
|
|
|
|
|
|
|
|
$ |
17.85 |
|
At September 30, 2011, we had the following jet fuel put options related to jet fuel crack
spreads in our fuel products segment, none of which are designated as hedges.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
Average |
|
|
|
|
|
|
|
|
|
|
|
Sold Put |
|
|
Bought Put |
|
Jet Fuel Put Option Crack Spread Contracts by Expiration Dates |
|
Barrels |
|
|
BPD |
|
|
($/Bbl) |
|
|
($/Bbl) |
|
Fourth Quarter 2011 |
|
|
184,000 |
|
|
|
2,000 |
|
|
$ |
4.75 |
|
|
$ |
7.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals |
|
|
184,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Average price |
|
|
|
|
|
|
|
|
|
$ |
4.75 |
|
|
$ |
7.00 |
|
Specialty Products Segment
At September 30, 2011, we had no derivative positions outstanding related to crude oil
purchases in our specialty products segment. Please refer to Note 7 under Part I Item 1 Financial
Statements Notes to Unaudited Condensed Consolidated Financial Statements for detailed
information on these derivatives.
Superior Acquisition
In addition, subsequent to the closing of the Superior Acquisition on September 30, 2011, we
have entered into additional derivative positions to hedge our increased exposure to crack spreads
resulting from the Superior Acquisition. The following tables provide a summary of such derivatives
entered into as of November 4, 2011, all of which are designated as cash flow hedges.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
|
Barrels |
|
|
|
|
|
|
Swap |
|
Crude Oil Swap Contracts by Expiration Dates |
|
Purchased |
|
|
BPD |
|
|
($/Bbl) |
|
Fourth Quarter 2011 |
|
|
552,000 |
|
|
|
6,000 |
|
|
$ |
78.50 |
|
Calendar Year 2012 |
|
|
5,490,000 |
|
|
|
15,000 |
|
|
|
83.35 |
|
|
|
|
|
|
|
|
|
|
|
|
Totals |
|
|
6,042,000 |
|
|
|
|
|
|
|
|
|
Average price |
|
|
|
|
|
|
|
|
|
$ |
82.90 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
|
Barrels |
|
|
|
|
|
|
Swap |
|
Diesel Swap Contracts by Expiration Dates |
|
Sold |
|
|
BPD |
|
|
($/Bbl) |
|
Calendar Year 2012 |
|
|
1,830,000 |
|
|
|
5,000 |
|
|
|
115.27 |
|
|
|
|
|
|
|
|
|
|
|
|
Totals |
|
|
1,830,000 |
|
|
|
|
|
|
|
|
|
Average price |
|
|
|
|
|
|
|
|
|
$ |
115.27 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
|
Barrels |
|
|
|
|
|
|
Swap |
|
Gasoline Swap Contracts by Expiration Dates |
|
Sold |
|
|
BPD |
|
|
($/Bbl) |
|
Fourth Quarter 2011 |
|
|
552,000 |
|
|
|
6,000 |
|
|
$ |
102.22 |
|
Calendar Year 2012 |
|
|
3,660,000 |
|
|
|
10,000 |
|
|
|
102.48 |
|
|
|
|
|
|
|
|
|
|
|
|
Totals |
|
|
4,212,000 |
|
|
|
|
|
|
|
|
|
Average price |
|
|
|
|
|
|
|
|
|
$ |
102.44 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Implied |
|
|
|
|
|
|
|
|
|
|
|
Crack |
|
|
|
|
|
|
|
|
|
|
|
Spread |
|
Crude Oil and Fuel Products Swap Contracts by Expiration Dates |
|
Barrels |
|
|
BPD |
|
|
($/Bbl) |
|
Fourth Quarter 2011 |
|
|
552,000 |
|
|
|
6,000 |
|
|
$ |
23.72 |
|
Calendar Year 2012 |
|
|
5,490,000 |
|
|
|
15,000 |
|
|
|
23.39 |
|
|
|
|
|
|
|
|
|
|
|
|
Totals |
|
|
6,042,000 |
|
|
|
|
|
|
|
|
|
Average price |
|
|
|
|
|
|
|
|
|
$ |
23.42 |
|
56
Item 4. Controls and Procedures
(a) Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) of the Securities Exchange Act of 1934 (the Exchange Act), as
amended, 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 Quarterly 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 September 30, 2011 at the reasonable assurance level.
(b) Changes in Internal Control over Financial Reporting
There was no change in our internal control over financial reporting during the third fiscal
quarter of 2011 that has materially affected, or is reasonably likely to materially affect, our
internal control over financial reporting.
57
PART II
Item 1. 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. The information provided under Note 5 Commitments and Contingencies in Part I Item 1
Financial Statements Notes to Unaudited Condensed Consolidated Financial Statements is
incorporated herein by reference.
Item 1A. Risk Factors
In addition to the risk factors set forth below,
you should carefully consider the risk factors discussed in Part I, Item 1A Risk Factors in our 2010 Annual Report and Part II,
Item 1A Risk Factors in our Quarterly Reports on Form 10-Q for the periods ended March 31, 2011 and June 30, 2011, which could
materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to
us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.
Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.
As of September 30, 2011, upon completion of the Superior Acquisition and the issuance of the
2019 Notes issued in September 2011, we had approximately $657.0 million of outstanding
indebtedness. 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 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. |
Any of these factors could result in a material adverse effect on our business, financial
condition, results of operations, business prospects and ability to satisfy our obligations under
the notes.
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 accomplish any of these remedies on satisfactory terms, or at
all. Please read Part I Item 2 Managements Discussion and Analysis of Financial Condition and
Results of Operations Liquidity and Capital Resources Debt and Credit Facilities for
additional information regarding our indebtedness.
Our revolving credit facility, indentures governing the 2019 Notes and master derivative contracts
contain operating and financial restrictions that may restrict our business and financing
activities.
The operating and financial restrictions and covenants in our revolving credit facility,
indentures governing the 2019 Notes, master derivative contracts 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; |
58
|
|
|
create or incur certain liens; |
|
|
|
|
make certain acquisitions and investments; |
|
|
|
|
make capital expenditures above specified amounts; |
|
|
|
|
redeem or repay other debt or make other restricted payments; |
|
|
|
|
make capital expenditures above specified amounts; |
|
|
|
|
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; |
|
|
|
|
cease our commodity hedging program; and |
|
|
|
|
engage in certain business activities. |
Our revolving credit facility contains operating and financial restrictions similar to the
above listed items, including 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 credit agreement) (without giving effect to the LC Reserve (as
defined in the credit agreement)) and (b) the credit agreement commitments then in effect and (ii)
$30.0 million, we will be required to maintain as of the end of each fiscal quarter a Fixed Charge
Coverage Ratio (as defined in the credit agreement) of at least 1.0 to 1.0. The failure to comply
with any of these or other covenants would cause a default under our revolving credit facility.
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 the indentures
governing the 2019 Notes, our revolving credit facility and our master derivative contracts 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 the indentures governing the 2019 Notes, our revolving credit
facility, our master derivative contracts or any future indebtedness could result in an event of
default under the indentures, our revolving credit facility, our master derivatives contracts, the
indentures governing our 2019 Notes or our future indebtedness, which, if not cured or waived,
could have a material adverse affect on our business, financial condition and results of
operations. 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; or |
|
|
|
|
may prevent us from making debt service payments under our other agreements, any of
which could result in an event of default under the notes. |
59
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 credit facilities 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 substantially all of our accounts
receivable, inventory and certain related assets 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 could seek to foreclose on these assets.
Please read Part I Item 2 Managements Discussion and Analysis of Financial Condition and Results
of Operations Liquidity and Capital Resources Debt and Credit Facilities for additional
information regarding our long-term debt.
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 on 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 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 payments of
debt obligations, we may be required to adopt one or more alternatives, such as a refinancing of
our indebtedness, including our 2019 Notes, or incurring borrowings under our revolving credit
facility. We cannot assure you that we would be able to refinance our indebtedness or that the
terms on which we could refinance our indebtedness would be favorable.
A change of control could result in us facing substantial repayment obligations under our
revolving credit facility and our 2019 Notes.
Our revolving credit agreement and the indentures governing our 2019 Notes contain provisions
relating to change of control of our managing general partner, our partnership and our operating
subsidiaries. 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, the 2019 Notes and other outstanding indebtedness. The source of funds for these
repayments would be our available cash or cash generated from other sources. In such an event,
there is no assurance that we would be able to pay the indebtedness, in which case the lenders
under our revolving credit facility would have the right to foreclose on our assets, which would
have a material adverse effect on us. Furthermore, certain change of control events would
constitute an event of default under the agreement governing our revolving credit facility, and we
might not be able to obtain a waiver of such default. 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 or the indentures governing
our 2019 Notes.
We depend on certain key crude oil and other feedstock suppliers for a significant portion of our
supply of crude oil and other feedstocks, and the loss of any of these key suppliers or a material
decrease in the supply of crude oil and other feedstocks generally available to our refineries
could materially reduce our ability to make distributions to unitholders.
We purchase crude oil and other feedstocks from major oil companies as well as from various
crude oil gatherers and marketers in east Texas and north Louisiana. In 2010, subsidiaries of
Plains All American Pipeline, L.P. and Genesis Crude Oil, L.P. supplied us with approximately 49.6%
and 4.6%, respectively, of our total crude oil supplies under term contracts and evergreen crude
oil supply contracts and 41.5% of our total crude oil purchases in 2010 were from Legacy Resources,
an affiliate of our general partner, to supply crude oil to our Princeton and Shreveport
refineries. In addition, BP will supply the Superior, Wisconsin refinery with approximately 75% of
its daily crude oil requirements, with such requirements estimated to be between 35,000 and 45,000
barrels per day. Each of our refineries is dependent on one or more of these suppliers and the
loss of any of these suppliers would adversely affect our financial results to the extent we were
unable to find another supplier of this substantial amount of crude oil. We do not maintain
long-term contracts with most of our suppliers. For example, our contracts with Plains are
currently month-to-month terminable upon 90 days notice. Additionally, we expect to purchase the
crude oil supply for the Princeton refinery and Shreveport refinery directly from third-party
suppliers under evergreen supply contracts and on the spot market. These evergreen contracts are
generally terminable on 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 Crude Oil and Feedstock Supply in our 2010 Annual Report.
60
To the extent that our suppliers reduce the volumes of crude oil and other feedstocks that
they supply us as a result of declining production or competition or otherwise, our revenues, net
income and cash available for distribution to unitholders 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. A material decrease in crude oil
production from the fields that supply our refineries, as a result of depressed commodity prices,
lack of drilling activity, natural production declines, governmental moratoriums on drilling or
production activities or otherwise, could result in a decline in the volume of crude oil we refine.
Fluctuations in crude oil prices can greatly affect production rates and investments by third
parties in the development of new oil reserves. Drilling activity generally decreases as crude oil
prices decrease. We have no control over the level of drilling activity in the fields that supply
our refineries, the amount of reserves underlying the wells in these fields, the rate at which
production from a well will decline or the production decisions of producers, which are affected
by, among other things, prevailing and projected energy prices, demand for hydrocarbons, geological
considerations, governmental regulation and the availability and cost of capital.
We are dependent on certain third-party pipelines for transportation of crude oil and refined
products, and if these pipelines become unavailable to us, our revenues and cash available for
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. 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. 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, government regulation, terrorism or other 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. If any of these third-party pipelines
become unavailable to transport crude oil or our refined fuel products because of acts of God,
accidents, government regulation, terrorism or other events, our revenues, net income and cash
available for distributions to our unitholders and payment of our debt obligations could decline.
Decreases in the price of crude oil may lead to a reduction in the borrowing base under our
revolving credit facility or the requirement that we post substantial amounts of cash collateral
for derivative instruments, either of which could adversely affect our liquidity, financial
condition and our ability to distribute cash to our unitholders.
The borrowing base under our revolving credit facility is determined weekly or monthly
depending upon availability levels 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. Further, if at any time our available capacity under our revolving credit
facility falls below $54.1 million, or a default or event of default exists and for an additional
60 days after those circumstances do not exist, our cash balances in a dominion account established
with the administrative agent will be applied on a daily basis to our outstanding obligations and
the revolving credit facility. Further, if at any time our available capacity under our 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) our revolving credit agreement commitments then in effect
and (ii) $54.1 million (as increased, upon the effectiveness of the increase in the maximum
availability under our revolving credit facility, by the same percentage as the percentage increase
in our revolving credit agreement commitments), or a default or event of default exists thereunder
and for an additional 60 days after those circumstances do not exist, 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 hedging positions. At September 30, 2011, we had $271.5
million in availability under our revolving credit facility. Please read Managements Discussion
and Analysis of Financial Condition and Results of Operations Liquidity and Capital Resources
Debt and Credit Facilities for additional information. If the borrowing base under our revolving
credit facility decreases or we are required to post substantial amounts of cash collateral to our
hedging counterparties, it could have a material adverse effect on our liquidity, financial
condition and our ability to distribute cash to our unitholders.
61
An increase in interest rates will cause our debt service obligations to increase.
Borrowings under our revolving credit facility bear interest at a floating rate (4.50% as of
September 30, 2011). The interest rate is subject to adjustment based on fluctuations in the London
Interbank Offered Rate (LIBOR) or prime rate. 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.
We may fail to successfully integrate the Superior Business with our existing business in a timely
manner, which could have a material adverse effect on our business, financial condition, results
of operations or cash flows, or fail to realize all of the expected benefits of the Superior
Acquisition, which could negatively impact our future results of operations.
Integration of the Superior Business with our existing business will be a complex,
time-consuming and costly process, particularly given that the Superior Acquisition has
significantly increased our size, and diversify the geographic areas in which we operate. A failure
to successfully integrate the Superior Business with our existing business in a timely manner may
have a material adverse effect on our business, financial condition, results of operations or cash
flows. The difficulties of combining the Superior Business include, among other things:
|
|
|
operating a larger combined organization and adding operations; |
|
|
|
|
difficulties in the assimilation of the assets and operations of the Superior refinery; |
|
|
|
|
customer or key employee loss from the Superior refinery; |
|
|
|
|
changes in key supply or feedstock agreements related to the Superior refinery; |
|
|
|
|
the diversion of managements attention from other business concerns; |
|
|
|
|
integrating personnel from diverse business backgrounds and organizational cultures,
including employees previously employed by Murphy Oil; |
|
|
|
|
managing relationships with new customers and suppliers for whom we have not previously
provided products or services; |
|
|
|
|
maintaining an effective system of internal controls related to the Superior refinery
and integrating internal controls, compliance under the Sarbanes-Oxley Act of 2002 and
other regulatory compliance and corporate governance matters; |
|
|
|
|
an inability to complete other internal growth projects and/or acquisitions; |
|
|
|
|
difficulties integrating new technology systems that we have not historically used in
our operations or financial reporting; |
|
|
|
|
an increase in our indebtedness; |
|
|
|
|
potential environmental or regulatory compliance matters or liabilities and title
issues, including certain liabilities arising from the operation of the Superior refinery
before the Superior Acquisition; |
|
|
|
|
coordinating geographically disparate organizations, systems and facilities; |
|
|
|
|
coordinating with the labor unions that represent the Superior refinerys operating
personnel; and |
|
|
|
|
coordinating and consolidating corporate and administrative functions. |
If any of these risks or unanticipated liabilities or costs were to materialize, then any desired
benefits of the Superior refinery may not be fully realized, if at all, and our future results of
operations could be negatively impacted. In addition, the Superior refinery may actually perform at
levels below the forecasts we used to evaluate the Superior Acquisition, due to factors that are
beyond our control, such as competition in the Superior refinerys region, market demand for the
products the Superior refinery produces and regulatory requirements for maintenance and improvement
projects at the Superior refinery. If the Superior refinery performs at levels below the forecasts
we used to evaluate the Superior Acquisition, then our future results of operations could be
negatively impacted.
In addition to the other information set forth in this Quarterly Report, you should carefully
consider the factors discussed in Part I Item 1A. Risk Factors in our 2010 Annual Report, which
could materially affect our business, financial condition or future results. The risks described in
this Quarterly Report and in our 2010 Annual Report are not the only risks facing the Company.
Additional risks and uncertainties not currently known to us or that we currently deem to be
immaterial also may materially adversely affect our business, financial condition or future
results.
62
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Removed and Reserved
Item 5. Other Information
None.
63
Item 6. Exhibits
The following documents are filed as exhibits to this Quarterly Report:
|
|
|
Exhibit |
|
|
Number |
|
Description |
2.1*
|
|
Asset Purchase Agreement, dated as of July 25, 2011, between Calumet Specialty Products Partners, L.P. and Murphy
Oil Corporation. |
|
|
|
3.1
|
|
Certificate of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to
Exhibit 3.1 to the Registrants Registration Statement on Form S-1 filed with the Commission on October 7, 2005
(File No. 333-128880)). |
|
|
|
3.2
|
|
Amended and Restated Limited Partnership Agreement of Calumet Specialty Products Partners, L.P. (incorporated by
reference to Exhibit 3.1 to the Registrants Current Report on Form 8-K filed with the Commission on February 13,
2006 (File No. 000-51734)). |
|
|
|
3.3
|
|
Certificate of Formation of Calumet GP, LLC (incorporated by reference to Exhibit 3.3 to the Registrants
Registration Statement on Form S-1 filed with the Commission on October 7, 2005 (File No. 333-128880)). |
|
|
|
3.4
|
|
Amended and Restated Limited Liability Company Agreement of Calumet GP, LLC (incorporated by reference to Exhibit
3.2 to the Registrants Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No.
000-51734)). |
|
|
|
3.5
|
|
Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products
Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrants Current Report on Form 8-K filed with
the Commission on July 11, 2006 (File No. 000-51734)). |
|
|
|
3.6
|
|
Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products
Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrants Current Report on Form 8-K filed with
the Commission on April 18, 2008 (File No. 000-51734)). |
|
|
|
4.1
|
|
Specimen Unit Certificate representing common units (incorporated by reference to Exhibit 3.7 to the Registrants
Quarterly Report on Form 10-Q filed with the SEC on November 4, 2010 (File No. 000-51734)). |
|
|
|
4.2
|
|
Indenture, dated September 19, 2011, by and among the Issuers, the Guarantors and the Trustee, governing the 2019
Senior Notes (incorporated by reference to Exhibit 4.1 to the Registrants Current Report on Form 8-K filed with the
Commission on September 21, 2011 (File No. 000-51734)). |
|
|
|
4.3
|
|
Registration Rights Agreement, dated September 19, 2011, by and among the Issuers, the Guarantors and the Initial
Purchasers, relating to the 2019 Senior Notes (incorporated by reference to Exhibit 4.2 to the Registrants Current
Report on Form 8-K filed with the Commission on September 21, 2011 (File No. 000-51734)). |
|
|
|
10.1
|
|
Amendment No. 2 to Collateral Trust Agreement, effective as of September 30, 2011, by and among Calumet Lubricants
Co., Limited Partnership, the guarantors party thereto, the secured hedge counterparties thereto and Bank of America,
N.A. (incorporated by reference to Exhibit 10.1 to the Registrants Current Report on Form 8-K filed with the
Commission on October 6, 2011 (File No. 000-51734)). |
|
|
|
10.2*
|
|
Amendment to the ISDA Master Agreement, dated as of September 30, 2011, between J. Aron & Company and Calumet
Lubricants Co., Limited Partnership. |
|
|
|
31.1*
|
|
Sarbanes-Oxley Section 302 certification of F. William Grube. |
|
|
|
31.2*
|
|
Sarbanes-Oxley Section 302 certification of R. Patrick Murray, II. |
|
|
|
32.1*
|
|
Section 1350 certification of F. William Grube and R. Patrick Murray, II. |
|
|
|
100.INS**
|
|
XBRL Instance Document |
|
|
|
101.SCH**
|
|
XBRL Taxonomy Extension Schema Document |
|
|
|
101.CAL**
|
|
XBRL Taxonomy Extension Calculation Linkbase Document |
|
|
|
101.DEF**
|
|
XBRL Taxonomy Extension Definition Linkbase Document |
64
|
|
|
Exhibit |
|
|
Number |
|
Description |
101.LAB**
|
|
XBRL Taxonomy Extension Label Linkbase Document |
|
|
|
101.PRE**
|
|
XBRL Taxonomy Extension Presentation Linkbase Document |
|
|
|
* |
|
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. |
65
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, 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/ R. Patrick Murray, II
|
|
|
|
R. Patrick Murray, II Vice President, |
|
|
|
Chief Financial Officer and Secretary of
Calumet GP, LLC, general partner of
Calumet Specialty Products Partners, L.P.
(Authorized Person and Principal Accounting Officer) |
|
|
Date: November 4, 2011
66
Index to Exhibits
|
|
|
Exhibit |
|
|
Number |
|
Description |
2.1*
|
|
Asset Purchase Agreement, dated as of July 25, 2011, between Calumet Specialty Products Partners, L.P. and Murphy
Oil Corporation. |
|
|
|
3.1
|
|
Certificate of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to
Exhibit 3.1 to the Registrants Registration Statement on Form S-1 filed with the Commission on October 7, 2005
(File No. 333-128880)). |
|
|
|
3.2
|
|
Amended and Restated Limited Partnership Agreement of Calumet Specialty Products Partners, L.P. (incorporated by
reference to Exhibit 3.1 to the Registrants Current Report on Form 8-K filed with the Commission on February 13,
2006 (File No. 000-51734)). |
|
|
|
3.3
|
|
Certificate of Formation of Calumet GP, LLC (incorporated by reference to Exhibit 3.3 of Registrants Registration
Statement on Form S-1 filed with the Commission on October 7, 2005 (File No. 333-128880)). |
|
|
|
3.4
|
|
Amended and Restated Limited Liability Company Agreement of Calumet GP, LLC (incorporated by reference to Exhibit
3.2 to the Registrants Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No.
000-51734)). |
|
|
|
3.5
|
|
Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products
Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed with the Commission
on July 11, 2006 (File No. 000-51734)). |
|
|
|
3.6
|
|
Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products
Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed with the Commission
on April 18, 2008 (File No. 000-51734)). |
|
|
|
4.1
|
|
Specimen Unit Certificate representing common units (incorporated by reference to Exhibit 3.7 to the Registrants
Quarterly Report on Form 10-Q filed with the SEC on November 4, 2010 (File No. 000-51734)). |
|
|
|
4.2
|
|
Indenture, dated September 19, 2011, by and among the Issuers, the Guarantors and the Trustee, governing the 2019
Senior Notes (incorporated by reference to Exhibit 4.1 to the Registrants Current Report on Form 8-K filed with the
Commission on September 21, 2011 (File No. 000-51734)). |
|
|
|
4.3
|
|
Registration Rights Agreement, dated September 19, 2011, by and among the Issuers, the Guarantors and the Initial
Purchasers, relating to the 2019 Senior Notes (incorporated by reference to Exhibit 4.2 to the Registrants Current
Report on Form 8-K filed with the Commission on September 21, 2011 (File No. 000-51734)). |
|
|
|
10.1
|
|
Amendment No. 2 to Collateral Trust Agreement, effective as of September 30, 2011, by and among Calumet Lubricants
Co., Limited Partnership, the guarantors party thereto, the secured hedge counterparties thereto and Bank of America,
N.A. (incorporated by reference to Exhibit 10.1 to the Registrants Current Report on Form 8-K filed with the
Commission on October 6, 2011 (File No. 000-51734)). |
|
|
|
10.2*
|
|
Amendment to the ISDA Master Agreement, dated as of September 30, 2011, between J. Aron & Company and Calumet
Lubricants Co., Limited Partnership. |
|
|
|
31.1*
|
|
Sarbanes-Oxley Section 302 certification of F. William Grube. |
|
|
|
31.2*
|
|
Sarbanes-Oxley Section 302 certification of R. Patrick Murray, II. |
|
|
|
32.1*
|
|
Section 1350 certification of F. William Grube and R. Patrick Murray, II. |
|
|
|
100.INS**
|
|
XBRL Instance Document |
|
|
|
101.SCH**
|
|
XBRL Taxonomy Extension Schema Document |
|
|
|
101.CAL**
|
|
XBRL Taxonomy Extension Calculation Linkbase Document |
|
|
|
101.DEF**
|
|
XBRL Taxonomy Extension Definition Linkbase Document |
67
|
|
|
Exhibit |
|
|
Number |
|
Description |
101.LAB**
|
|
XBRL Taxonomy Extension Label Linkbase Document |
|
|
|
101.PRE**
|
|
XBRL Taxonomy Extension Presentation Linkbase Document |
|
|
|
* |
|
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. |
68