CLMT-2012.09.30-10Q
Table of Contents

 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
Form 10-Q
 
 
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2012
OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF 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) 
 
 
Delaware
 
37-1516132
(State or Other Jurisdiction of
Incorporation or Organization)
 
(I.R.S. Employer
Identification Number)
 
 
2780 Waterfront Parkway East Drive, Suite 200
 
 
Indianapolis, Indiana
 
46214
(Address of Principal Executive Officers)
 
(Zip Code)
(317) 328-5660
(Registrant’s Telephone Number Including Area Code)
None
(Former Name, Former Address and Former Fiscal Year, If Changed Since Last Report)
 
 
 
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  x    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of 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  x    No  ¨
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):
Large accelerated filer
 
¨
  
Accelerated filer
 
x
 
 
 
 
Non-accelerated filer
 
o  (Do not check if a smaller reporting company)
  
Smaller reporting company
 
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  x
At November 7, 2012, there were 57,529,778 common units outstanding.
 

Table of Contents

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
QUARTERLY REPORT
For the Three and Nine Months Ended September 30, 2012
Table of Contents
 
 
Page
 
 
 

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FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q (this “Quarterly Report”) includes certain “forward-looking statements”. These statements can be identified by the use of forward-looking terminology including “may,” “intend,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or other similar words. The statements regarding (i) estimated capital expenditures as a result of the required audits or required operational changes 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 and (iii) our ability to meet our financial commitments, minimum quarterly distributions to our unitholders, debt service obligations, debt instrument covenants, contingencies and anticipated capital expenditures, as well as other matters discussed in this 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. Known material factors that could cause our actual results to differ from those in the forward-looking statements are those described in (1) Part I Item 3 “Quantitative and Qualitative Disclosures About Market Risk” and Part I Item 1A “Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2011 (“2011 Annual Report”) and (2) Part II Item 1A Risk Factors in this Quarterly Report. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.
References in this 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 Calumet Specialty Products Partners, L.P.


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PART I
Item 1. Financial Statements
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS

 
September 30, 2012
 
December 31, 2011
 
(Unaudited)
 
 
 
(In thousands, except unit data)
ASSETS
Current assets:
 
 
 
Cash and cash equivalents
$
190,538

 
$
64

Accounts receivable:
 
 
 
Trade
261,142

 
208,928

Other
2,999

 
3,137

 
264,141

 
212,065

Inventories
494,112

 
497,740

Derivative assets
—

 
58,502

Prepaid expenses and other current assets
10,315

 
8,179

Deposits
3,949

 
2,094

Total current assets
963,055

 
778,644

Property, plant and equipment, net
863,364

 
842,101

Goodwill
161,150

 
48,335

Other intangible assets, net
203,752

 
22,675

Other noncurrent assets, net
47,840

 
40,303

Total assets
$
2,239,161

 
$
1,732,058

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
 
 
 
Accounts payable
$
336,034

 
$
302,826

Accrued interest payable
30,843

 
10,500

Accrued salaries, wages and benefits
19,507

 
13,481

Taxes payable
16,710

 
13,068

Other current liabilities
9,202

 
4,600

Current portion of long-term debt
783

 
551

Derivative liabilities
95,802

 
43,581

Total current liabilities
508,881

 
388,607

Pension and postretirement benefit obligations
18,315

 
26,957

Other long-term liabilities
1,132

 
1,055

Long-term debt, less current portion
862,513

 
586,539

Total liabilities
1,390,841

 
1,003,158

Commitments and contingencies

 

Partners’ capital:
 
 
 
Limited partners’ interest (57,529,778 and 51,529,778 units issued and outstanding, respectively, at September 30, 2012 and December 31, 2011)
877,258

 
666,471

General partner’s interest
29,740

 
23,902

Accumulated other comprehensive income (loss)
(58,678
)
 
38,527

Total partners’ capital
848,320

 
728,900

Total liabilities and partners’ capital
$
2,239,161

 
$
1,732,058

See accompanying notes to unaudited condensed consolidated financial statements.


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
 
 
For the Three Months Ended
 
For the Nine Months Ended
 
September 30,
 
September 30,
 
2012
 
2011
 
2012
 
2011
 
(In thousands, except per unit data)
Sales
$
1,179,818

 
$
777,780

 
$
3,436,400

 
$
2,116,790

Cost of sales
1,021,412

 
681,179

 
3,064,942

 
1,922,760

Gross profit
158,406

 
96,601

 
371,458

 
194,030

Operating costs and expenses:
 
 
 
 
 
 
 
Selling
15,002

 
2,809

 
26,668

 
8,220

General and administrative
12,810

 
11,339

 
41,333

 
26,923

Transportation
28,404

 
23,696

 
80,903

 
69,462

Taxes other than income taxes
1,723

 
1,683

 
5,371

 
4,246

Insurance recoveries
—

 
—

 
—

 
(8,698
)
Other
1,613

 
543

 
4,856

 
1,781

Operating income
98,854

 
56,531

 
212,327

 
92,096

Other income (expense):
 
 
 
 
 
 
 
Interest expense
(24,271
)
 
(12,577
)
 
(61,247
)
 
(30,602
)
Debt extinguishment costs
—

 
—

 
—

 
(15,130
)
Realized gain (loss) on derivative instruments
(10,156
)
 
(3,814
)
 
20,486

 
(5,798
)
Unrealized loss on derivative instruments
(22,101
)
 
(20,335
)
 
(11,337
)
 
(23,876
)
Other
268

 
45

 
382

 
148

Total other expense
(56,260
)
 
(36,681
)
 
(51,716
)
 
(75,258
)
Net income before income taxes
42,594

 
19,850

 
160,611

 
16,838

Income tax expense
178

 
236

 
610

 
674

Net income
$
42,416

 
$
19,614

 
$
160,001

 
$
16,164

Allocation of net income:
 
 
 
 
 
 
 
Net income
$
42,416

 
$
19,614

 
$
160,001

 
$
16,164

Less:
 
 
 
 
 
 
 
General partner’s interest in net income
848

 
392

 
3,200

 
323

General partner’s incentive distribution rights
1,637

 
40

 
3,256

 
40

Nonvested share based payments
262

 
—

 
947

 
—

Net income available to limited partners
$
39,669

 
$
19,182

 
$
152,598

 
$
15,801

Weighted average limited partner units outstanding:
 
 
 
 
 
 
 
Basic
57,746

 
41,828

 
54,827

 
39,352

Diluted
57,826

 
41,837

 
54,867

 
39,368

Limited partners’ interest basic and diluted net income per unit
$
0.69

 
$
0.46

 
$
2.78

 
$
0.40

Cash distributions declared per limited partner unit
$
0.59

 
$
0.50

 
$
1.68

 
$
1.45

See accompanying notes to unaudited condensed consolidated financial statements.


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
 
 
For the Three Months Ended
 
For the Nine Months Ended
 
September 30,
 
September 30,
 
2012
 
2011
 
2012
 
2011
 
(In thousands)
 
(In thousands)
Net income
$
42,416

 
$
19,614

 
$
160,001

 
$
16,164

Other comprehensive loss:
 
 
 
 
 
 
 
Cash flow hedges:
 
 
 
 
 
 
 
Cash flow hedge loss reclassified to net income
41,766

 
34,350

 
137,797

 
81,294

Change in fair value of cash flow hedges
(83,391
)
 
(37,762
)
 
(236,279
)
 
(180,537
)
Defined benefit pension and retiree health benefit plans
1,009

 
61

 
1,277

 
183

Total other comprehensive loss
(40,616
)
 
(3,351
)
 
(97,205
)
 
(99,060
)
Comprehensive income (loss) attributable to partners’ capital
$
1,800

 
$
16,263

 
$
62,796

 
$
(82,896
)
See accompanying notes to unaudited condensed consolidated financial statements.


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
 

Accumulated  Other
Comprehensive
Income (Loss)
 
Partners’ Capital
 
 

 
General
Partner
 
Limited
Partners
 
Total

(In thousands)
Balance at December 31, 2011
$
38,527

 
$
23,902

 
$
666,471

 
$
728,900

Other comprehensive loss
(97,205
)
 
—

 
—

 
(97,205
)
Net income
—

 
6,456

 
153,545

 
160,001

Units repurchased for phantom unit grants
—

 
—

 
(2,110
)
 
(2,110
)
Issuance of phantom units
—

 
—

 
1,648

 
1,648

Amortization of vested phantom units
—

 
—

 
1,610

 
1,610

Proceeds from public offering of common units, net
—

 
—

 
146,558

 
146,558

Contributions from Calumet GP, LLC
—

 
3,122

 
—

 
3,122

Distributions to partners
—

 
(3,740
)
 
(90,464
)
 
(94,204
)
Balance at September 30, 2012
$
(58,678
)
 
$
29,740

 
$
877,258

 
$
848,320

See accompanying notes to unaudited condensed consolidated financial statements.


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
For the Nine Months Ended
 
September 30,
 
2012
 
2011
 
(In thousands)
Operating activities
 
 
 
Net income
$
160,001

 
$
16,164

Adjustments to reconcile net income to net cash provided by (used in) operating activities:
 
 
 
Depreciation and amortization
63,828

 
43,644

Amortization of turnaround costs
10,315

 
8,288

Non-cash interest expense
4,409

 
2,363

Non-cash debt extinguishment costs
—

 
14,401

Provision for doubtful accounts
296

 
255

Unrealized loss on derivative instruments
11,337

 
23,876

Non-cash equity based compensation
5,108

 
3,298

Other non-cash activities
1,100

 
(1,468
)
Changes in assets and liabilities:
 
 
 
Accounts receivable
(32,370
)
 
(44,714
)
Inventories
33,678

 
(109,787
)
Prepaid expenses and other current assets
(1,628
)
 
(1,926
)
Derivative activity
904

 
4,928

Turnaround costs
(14,141
)
 
(8,849
)
Deposits
(1,842
)
 
(426
)
Other assets
—

 
(197
)
Accounts payable
26,845

 
32,158

Accrued interest payable
20,343

 
22,758

Accrued salaries, wages and benefits
2,327

 
2,917

Taxes payable
3,444

 
1,676

Other liabilities
2,851

 
(9,082
)
Pension and postretirement benefit obligations
(7,365
)
 
(836
)
Net cash provided by (used in) operating activities
289,440

 
(559
)
Investing activities
 
 
 
Additions to property, plant and equipment
(36,735
)
 
(30,667
)
Proceeds from insurance recoveries — equipment
—

 
1,942

Cash paid for acquisitions, net of cash acquired
(379,048
)
 
(441,626
)
Proceeds from sale of property, plant and equipment
1,960

 
219

Net cash used in investing activities
(413,823
)
 
(470,132
)
Financing activities
 
 
 
Proceeds from borrowings — revolving credit facility
1,147,778

 
1,152,898

Repayments of borrowings — revolving credit facility
(1,147,753
)
 
(1,107,730
)
Repayments of borrowings — term loan credit facility
—

 
(367,385
)
Payments on capital lease obligations
(1,179
)
 
(802
)
Proceeds from public offerings of common units, net
146,558

 
281,870

Proceeds from senior notes offerings
270,187

 
586,000

Debt issuance costs
(7,542
)
 
(23,140
)

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Contributions from Calumet GP, LLC
3,122

 
6,011

Units repurchased for phantom unit grants
(2,110
)
 
(620
)
Distributions to partners
(94,204
)
 
(56,382
)
Net cash provided by financing activities
314,857

 
470,720

Net increase in cash and cash equivalents
190,474

 
29

Cash and cash equivalents at beginning of period
64

 
37

Cash and cash equivalents at end of period
$
190,538

 
$
66

Supplemental disclosure of noncash financing and investing activities
 
 
 
Equipment acquired under capital lease
$
5,771

 
$
—

See accompanying notes to unaudited condensed consolidated financial statements.


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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, 2012, the Company had 57,529,778 limited partner common units and 1,174,077 general partner equivalent units outstanding. The general partner owns 2% of the Company and all of the incentive distribution rights (as defined in the Company’s partnership agreement), while the remaining 98% is owned by limited partners. The general partner employs all employees and the limited partnership reimburses the general partner for all expenses. The Company is engaged in the production and marketing of crude oil-based specialty lubricating oils, white mineral oils, solvents, petrolatums, asphalt, waxes and fuel and fuel related products including gasoline, diesel, jet fuel and heavy fuel oils. The Company owns facilities located in Shreveport, Louisiana (“Shreveport” and “TruSouth”); Superior, Wisconsin (“Superior”); Princeton, Louisiana (“Princeton”); Cotton Valley, Louisiana (“Cotton Valley”); Karns City, Pennsylvania (“Karns City”); Dickinson, Texas (“Dickinson”); Louisiana, Missouri (“Missouri”) and Houston, Texas (“Royal Purple”) 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, 2012 and for the three and nine months ended September 30, 2012 and 2011 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, 2012 are not necessarily indicative of the results that may be expected for the year ending December 31, 2012. These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s 2011 Annual Report.
2. New and Recently Adopted Accounting Pronouncements
In October 2012, the FASB issued ASU No. 2012-04, Technical Corrections and Improvements ("ASU 2012-04"). ASU 2012-04 covers a wide range of topics in the Accounting Standards Codification. These amendments include technical corrections and improvements to the Accounting Standards Codification and conforming amendments related to fair value measurements. ASU 2012-04 is effective for fiscal periods beginning after December 15, 2012. The Company is in the process of evaluating the impact of the adoption of ASU 2012-04 on its financial statements.
In July 2012, the FASB issued ASU No. 2012-02, Intangibles (Topic 350)—Testing Indefinite-Lived Intangible Assets for Impairment (“ASU 2012-02”). ASU 2012-02 permits an entity to first assess qualitative factors to determine if it is more likely than not that the fair value of an indefinite-lived intangible asset is more than its carrying amount. If based on its qualitative assessment an entity concludes it is more likely than not that the fair value of an indefinite-lived intangible asset exceeds its carrying amount, quantitative impairment testing is not required. However, if an entity concludes otherwise, quantitative impairment testing is required. ASU 2012-02 is effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012, with early adoption permitted. The Company is in the process of evaluating the impact of the adoption of ASU 2012-02 on its financial statements.
In December 2011, the FASB issued ASU No. 2011-11, Balance Sheet (Topic 210)—Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”). ASU 2011-11 will require entities to disclose information about offsetting and related arrangements to enable financial statement users to understand the effect of such arrangements on the balance sheet. Entities are required to disclose both gross information and net information about financial instruments and derivative instruments that are either offset in the balance sheet or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset. ASU 2011-11 is effective for the first reporting period (including interim periods) beginning after January 1, 2013 and should be applied retrospectively for any period presented. The Company is in the process of evaluating the impact of the adoption of ASU 2011-11 on its financial statements.
In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (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 (loss) as part of the statement of partners’ capital. Instead, the Company must report comprehensive income in either a single continuous statement of comprehensive income (loss) which

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contains two sections, net income and other comprehensive income (loss), or in two separate but consecutive statements. In December 2011, the FASB issued ASU No. 2011-12, Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 (“ASU 2011-12), which indefinitely defers the requirement in ASU 2011-05 to present reclassification adjustments out of accumulated other comprehensive income (loss) by component in both the statement in which net income is presented and the statement in which other comprehensive income (loss) is presented. During the deferral period, the existing requirements in U.S. GAAP for the presentation of reclassification adjustments must continue to be followed. Amendments to ASU 2011-05, as superseded by ASU 2011-12, are effective for fiscal years (including interim periods) beginning after December 15, 2011 and are to be applied retrospectively, with early adoption permitted. The Company elected to present the components of comprehensive loss in two separate but consecutive financial statements, namely the unaudited condensed consolidated statements of operations and the unaudited condensed consolidated statements of comprehensive income (loss).
In May 2011, the FASB issued ASU No. 2011-04, Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRS (“ASU 2011-04”). ASU 2011-04 is intended to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and IFRS. The amendments are of two types: (i) those that clarify the FASB’s intent about the application of existing fair value measurement and disclosure requirements and (ii) those that change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. ASU 2011-04 is effective for the first reporting period (including interim periods) beginning after December 15, 2011. The adoption of ASU 2011-04 did not have a material impact on the Company’s unaudited condensed consolidated financial statements.
3. Acquisitions
Superior Acquisition
On September 30, 2011, the Company completed the acquisition of the Superior, Wisconsin refinery and associated operating assets and inventories and related business of Murphy Oil Corporation (“Murphy Oil”) for aggregate consideration of approximately $413,173 (“Superior Acquisition”). The Superior Acquisition was financed by a combination of (i) net proceeds of $193,538 from the Company’s September 2011 public offering of common units (including the general partner’s contribution but excluding the over-allotment option exercised), (ii) net proceeds of $180,296 from the Company’s September 2011 private placement of 9 3/8% senior notes due May 1, 2019 and (iii) borrowings under the Company’s revolving credit facility.
The allocation of the aggregate purchase price to assets acquired and liabilities assumed is as follows:
 
 
Allocation of Purchase Price
Inventories
$
183,602

Prepaid expenses and other current assets
5,845

Property, plant and equipment
239,478

Accrued salaries, wages and benefits
(775
)
Pension and postretirement benefit obligations
(14,977
)
Total purchase price
$
413,173

Missouri Acquisition
On January 3, 2012, the Company completed the acquisition of the aviation and refrigerant lubricants business (a polyolester based synthetic lubricants business) of Hercules Incorporated, a subsidiary of Ashland, Inc., including a manufacturing facility located in Louisiana, Missouri (“Missouri Acquisition”) for aggregate consideration of approximately $19,575. The Missouri Acquisition was financed with borrowings under the Company’s revolving credit facility and cash on hand. The Company believes the Missouri Acquisition provides greater diversity to its specialty products segment. The assets acquired have been included in the condensed consolidated balance sheets and results have been included in the unaudited condensed consolidated statements of operations since the date of acquisition. In connection with the Missouri Acquisition, during the three and nine months ended September 30, 2012, the Company incurred acquisition costs of approximately $0 and $505, respectively, which are reflected in general and administrative expenses in the unaudited condensed consolidated statements of operations.

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The Company recorded $1,478 of goodwill as a result of the Missouri Acquisition, all of which was recorded within the Company’s specialty products segment. Goodwill recognized in the acquisition relates primarily to enhancing the Company’s strategic platform for expansion in its specialty products segment. The allocation of the aggregate purchase price to assets acquired is as follows:
 
 
Allocation of Purchase Price
Inventories
$
2,775

Property, plant and equipment
9,955

Goodwill
1,478

Other intangible assets
5,367

Total purchase price
$
19,575


The component of the intangible asset listed in the table above as of January 3, 2012, based upon a third party appraisal, was as follows:
 
 
Amount
 
Life (Years)
Customer relationships
$
5,367

 
20
TruSouth Acquisition
On January 6, 2012, the Company completed the acquisition of all of the outstanding membership interests of TruSouth Oil, LLC ("TruSouth"), a specialty petroleum packaging and distribution company located in Shreveport, Louisiana (“TruSouth Acquisition”) for aggregate consideration of approximately $26,827, net of cash acquired. The TruSouth Acquisition was financed with borrowings under the Company’s revolving credit facility. Immediately prior to its acquisition by the Company, TruSouth was owned in part by affiliates of the Company’s general partner. The Company believes the TruSouth Acquisition provides greater diversity to its specialty products segment. The assets acquired and liabilities assumed have been included in the condensed consolidated balance sheets and results have been included in the unaudited condensed consolidated statements of operations since the date of acquisition. In connection with the TruSouth Acquisition, during the three and nine months ended September 30, 2012, the Company incurred acquisition costs of $0 and $179, respectively, which are reflected in general and administrative expenses in the unaudited condensed consolidated statements of operations.
The Company recorded $637 of goodwill as a result of the TruSouth Acquisition, all of which was recorded within the Company’s specialty products segment. Goodwill recognized in the acquisition relates primarily to enhancing the Company’s strategic platform for expansion in its specialty products segment. The allocation of the aggregate purchase price to assets acquired and liabilities assumed is as follows:
 
 
Allocation of Purchase Price
Accounts receivable
$
4,972

Inventories
7,976

Prepaid expenses and other current assets
272

Property, plant and equipment
17,682

Goodwill
637

Other intangible assets
2,545

Accounts payable
(2,672
)
Accrued salaries, wages and benefits
(151
)
Other current liabilities
(918
)
Long-term debt
(3,516
)
Total purchase price, net of cash acquired
$
26,827

The components of intangible assets listed in the table above as of January 6, 2012, based upon a third party appraisal, were as follows:

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Amount
 
Life (Years)
Customer relationships
$
1,775

 
16
Tradenames
675

 
9
Non-competition agreements
95

 
2
Total
$
2,545

 
 
Weighted average amortization period
 
 
14
Royal Purple Acquisition
On July 3, 2012, the Company completed the acquisition of Royal Purple, Inc. ("Royal Purple"), a Texas corporation which was converted into a Delaware limited liability company at closing, a leading independent formulator and marketer of premium industrial and consumer lubricants to a diverse customer base across several large markets including oil and gas, chemicals and refining, power generation, manufacturing and transportation, food and drug manufacturing and automotive aftermarket for aggregate consideration of approximately $332,646, net of cash acquired (“Royal Purple Acquisition”). The Royal Purple Acquisition was financed with net proceeds of $262,645 from the Company’s June 2012 private placement of 9 5/8% senior notes due August 1, 2020 and cash on hand. The Company believes the Royal Purple Acquisition increases its position in the specialty lubricants markets, expands its geographic reach, increases its asset diversity and enhances its specialty products segment. The assets acquired have been included in the condensed consolidated balance sheets and results have been included in the unaudited condensed consolidated statements of operations since the date of acquisition. In connection with the Royal Purple Acquisition, during the three and nine months ended September 30, 2012, the Company incurred acquisition costs of approximately $271 and $396, respectively, which are reflected in general and administrative expenses in the unaudited condensed consolidated statements of operations.
The Company recorded $110,700 of goodwill as a result of the Royal Purple Acquisition, all of which was recorded within the Company’s specialty products segment. Goodwill recognized in the acquisition relates primarily to enhancing the Company’s strategic platform for expansion in its specialty products segment.
The preliminary allocation of the aggregate purchase price to assets acquired and liabilities assumed is as follows:
 
Allocation of Purchase Price
Accounts receivable
$
15,030

Inventories
19,299

Prepaid expenses and other current assets
236

Deposits
13

Property, plant and equipment
10,580

Goodwill
110,700

Other intangible assets
183,398

Accounts payable
(3,804
)
Accrued salaries, wages and benefits
(1,698
)
Taxes payable
(198
)
Other current liabilities
(910
)
Total purchase price, net of cash acquired
$
332,646

The components of intangible assets listed in the table above as of July 3, 2012, based upon a preliminary third party appraisal, were as follows:
 

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Amount
 
Life (Years)
Customer relationships
$
118,683

 
20
Tradenames
14,790

 
Indefinite
Tradenames
5,746

 
10
Trade secrets
44,179

 
12
Total
$
183,398

 
 
Weighted average amortization period
 
 
18
Results of Sales and Earnings
The following financial information reflects the results of sales and operating income of the Superior, Missouri, TruSouth and Royal Purple Acquisitions that are included in the unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2012:
 
 
Three Months Ended
 
Nine Months Ended
 
September 30, 2012
 
September 30, 2012
Sales
$
457,938

 
$
1,143,096

Operating income
$
77,640

 
$
126,171

Pro Forma Financial Information
The following unaudited pro forma financial information reflects the unaudited condensed consolidated results of operations of the Company as if the Superior, Missouri, TruSouth and Royal Purple Acquisitions had taken place on January 1, 2011.
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2012
 
2011
 
2012
 
2011
Sales
$
1,179,818

 
$
1,283,828

 
$
3,496,575

 
$
3,395,675

Net income
$
42,416

 
$
64,709

 
$
151,306

 
$
65,360

Limited partners’ interest net income per unit — basic and diluted
$
0.69

 
$
1.10

 
$
2.50

 
$
1.11

The Company’s historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the Superior, Missouri, TruSouth and Royal Purple Acquisitions. This unaudited proforma 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 proforma events taken place on the dates indicated, or the future consolidated results of operations of the combined company.
For the three months ended September 30, 2012 , there were no adjustments recorded for pro forma information as actual results reflect all acquisition activity for the period.
For the three months ended September 30, 2011, the unaudited pro forma financial information reflects adjustments to increase interest expense as a result of the issuance of the 2019 Notes and 2020 Notes (defined below), amending and restating the revolving credit facility, additional borrowings under the revolving credit facility to fund portions of the Superior, Missouri and TruSouth Acquisitions and the repayment of borrowings under the prior term loan from the net proceeds of the 2019 Notes issued in April 2011. The unaudited pro forma financial information reflects adjustments to increase amortization expense by $5,625 as a result of recording Royal Purple's intangible assets.
For the nine months ended September 30, 2012, the unaudited pro forma financial information reflects adjustments to increase interest expense as a result of the issuance of the 2020 Notes (defined below). The unaudited pro forma financial information reflects adjustments to increase amortization expense by $10,864 as a result of recording Royal Purple's intangible assets.
For the nine months ended September 30, 2011, the unaudited pro forma financial information reflects adjustments to increase interest expense as a result of the issuance of the 2019 Notes and 2020 Notes (defined below), amending and restating the revolving credit facility, additional borrowings under the revolving credit facility to fund a portion of the Superior, Missouri

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and TruSouth Acquisitions and the repayment of borrowings under the prior term loan from the net proceeds of the 2019 Notes issued in April 2011. The unaudited pro forma financial information reflects adjustments to increase amortization expense by $16,087 as a result of recording Royal Purple's intangible assets.
Fair Value Measurements of Acquisitions
The fair value of the property, plant and equipment and intangible assets are based upon the discounted cash flow method that involves inputs that are not observable in the market (Level 3). Goodwill assigned represents the amount of consideration transferred in excess of the fair value assigned to individual assets acquired and liabilities assumed.

4. Inventories
The Company uses the last-in, first-out (LIFO) method of valuing inventory. An actual valuation of inventory under the LIFO method can be made only at the end of each year based on the inventory levels and costs at that time. Accordingly, interim LIFO calculations are based on management’s estimates of expected year-end inventory levels and costs and are subject to the final year-end LIFO inventory valuation. 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:
 
 
September 30, 2012
 
December 31, 2011
Raw materials
$
83,041

 
$
105,802

Work in process
108,169

 
91,763

Finished goods
302,902

 
300,175

 
$
494,112

 
$
497,740


The replacement cost of these inventories, based on current market values, would have been $52,175 and $87,635 higher as of September 30, 2012 and December 31, 2011, respectively.

5. Goodwill and Intangible Assets

The Company has recorded $48,335 of goodwill as a result of the acquisition of Penreco in 2008, all of which is recorded within the Company's specialty products segment. During 2012, the Company has recorded $1,478 of goodwill as a result of the Missouri Acquisition, $637 of goodwill as a result of the TruSouth Acquisition and $110,700 of goodwill as a result of the Royal Purple Acquisition, all of which is recorded within the Company's specialty products segment.
Other intangible assets consist of the following:
 
 
Weighted Average Life (Years) 
 
September 30, 2012
 
December 31, 2011
 
 
Gross Amount 
 
 
Accumulated Amortization 
 
 
Gross Amount 
 
 
Accumulated Amortization 
 
Customer relationships
20
 
$
154,307

 
$
(18,648
)
 
$
28,482

 
$
(12,936
)
Supplier agreements
4
 
21,519

 
(21,120
)
 
21,519

 
(19,926
)
Tradenames - Royal Purple Retail
Indefinite
 
14,790

 
—

 
—

 
—

Tradenames
9
 
6,421

 
(294
)
 
—

 
—

Trade secrets
12
 
44,179

 
(1,558
)
 
—

 
—

Patents
12
 
1,573

 
(1,075
)
 
1,573

 
(966
)
Noncompetition agreements
5
 
5,827

 
(5,381
)
 
5,732

 
(4,182
)
Distributor agreements
3
 
2,019

 
(2,019
)
 
2,019

 
(2,019
)
Royalty agreements
19
 
4,499

 
(1,287
)
 
4,499

 
(1,120
)
 
16
 
$
255,134

 
$
(51,382
)
 
$
63,824

 
$
(41,149
)
Intangible assets associated with supplier agreements, tradenames, trade secrets, patents, noncompetition agreements, distributor agreements and royalty agreements are being amortized to properly match expense with the discounted estimated future cash flows over the terms of the related agreements. Agreements with terms allowing for the potential extension of such agreements

15
Table of Contents

are being amortized based on the initial term only. Intangible assets associated with customer relationships are being amortized using discounted estimated future cash flows based upon assumed rates of annual customer attrition. For the three months ended September 30, 2012 and 2011, the Company recorded amortization expense of intangible assets of $6,665 and $1,747, respectively. For the nine months ended September 30, 2012 and 2011, the Company recorded amortization expense of intangible assets of $10,233 and $5,243, respectively.
The Company estimates that amortization of intangible assets for the next five years will be as follows:
Year
 
Amortization Amount
Remainder of 2012
 
$
6,669

2013
 
$
25,401

2014
 
$
24,297

2015
 
$
22,165

2016
 
$
20,217

2017
 
$
17,669

6. 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 U.S. Environmental Protection Agency (“EPA”), the Louisiana Department of Environmental Quality (“LDEQ”), the Wisconsin Department of Natural Resources (“WDNR”), the Internal Revenue Service, various state and local departments of revenue and the federal Occupational Safety and Health Administration (“OSHA”), as the result of audits or reviews of the Company’s business. In addition, the Company has property, business interruption, general liability and various other insurance policies that may result in certain losses or expenditures being reimbursed to the Company.
Environmental
The Company operates crude oil and specialty hydrocarbon refining and terminal operations, which are subject to stringent and complex federal, state, regional and local laws and regulations governing worker health and safety, the discharge of materials into the environment and environmental protection. These laws and regulations can impose obligations that are applicable to the Company’s operations, such as requiring the acquisition of permits to conduct regulated activities, restricting the manner in which the Company may release materials into the environment, requiring remedial activities or capital expenditures to mitigate pollution from former or current operations, requiring the application of specific health and safety criteria addressing worker protection and imposing substantial liabilities for pollution resulting from its operations. Certain of these laws impose joint and several, strict liability for costs required to remediate and restore sites where petroleum hydrocarbons, wastes, or other materials have been released or disposed.
In connection with the Montana Acquisition (see Note 15 below), the Company became a party to an existing 2002 Refinery Initiative consent decree (“Montana Consent Decree”) with the EPA and State of Montana. The material obligations imposed by the Montana Consent Decree have been completed. Periodic reporting is the primary current obligation under this Montana Consent Decree. On September 27, 2012, Montana Refining Company, Inc. received a final Corrective Action Order on Consent, replacing the refinery's previous Hazardous Waste Permit. This Corrective Action Order on Consent governs the investigation and remediation of contamination at the Montana refinery. The Company believes that all such contamination is subject to the indemnification of Montana Refining Company, Inc. by Holly Corporation ("Holly") for pre-existing conditions. The Company is indemnified by Holly under the asset purchase agreement between Holly and Connacher, which the Company became a party to by virtue of the share purchase agreement between the Company and Connacher. Holly is responsible for existing environmental conditions at the Montana refinery, and has been reimbursing Connacher for remedial actions subject to the indemnification.
In connection with the Superior Acquisition, the Company became a party to an existing consent decree (“Consent Decree”) with the EPA and the WDNR that applies, in part, to its Superior refinery. Under the Consent Decree, the Company will have to complete certain reductions in air emissions at the Superior refinery as well as report upon certain emissions from the facility to the EPA and the WDNR. The Company currently estimates costs of approximately $4,300 to make known equipment upgrades and conduct other discrete tasks in compliance with the Consent Decree. Failure to perform required tasks under the Consent Decree could result in the imposition of stipulated penalties, which could be significant. In addition, the Company may have to pursue certain additional environmental and safety-related projects at the Superior refinery including, but not limited to: (i) installing process equipment pursuant to applicable EPA fuel content regulations; (ii) purchasing emission credits on an interim basis until such time as any process equipment that may be required under the EPA fuel content

16
Table of Contents

regulations is installed and operational; (iii) performing monitoring of historical contamination at the facility; (iv) upgrading treatment equipment or possibly pursuing other remedies, as necessary, to satisfy new effluent discharge limits under a federal Clean Water Act permit renewal that is pending and (v) pursuing various voluntary programs at the Superior refinery, including removing asbestos-containing materials or enhancing process safety or other maintenance practices. Completion of these additional projects would result in the Company incurring additional costs, which could be substantial. For the three and nine months ended September 30, 2012, the Company incurred approximately $646 and $2,075, respectively, of costs related to installing process equipment pursuant to the EPA fuel content regulations.
On June 29, 2012, the EPA issued a Finding of Violation/Notice of Violation to the Company’s Superior refinery. This finding is in response to information provided to the EPA by the Company in response to an information request. The EPA alleges that the efficiency of the flares at the Superior refinery is lower than regulatory requirements. The Company is contesting the allegations and is currently awaiting an informal conference with the EPA. The Company does not believe that the resolution of these allegations will have a material adverse effect on the Company’s financial results or operations.
In addition, the Company is indemnified by Murphy Oil for specified environmental liabilities 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 Oil’s transport of certain wastes and other materials to specified offsite real properties for disposal or recycling prior to the Superior Acquisition and (iii) certain liabilities for certain third party actions, suits or proceedings alleging exposure, prior to the Superior Acquisition, of an individual to wastes or other materials at the specified on-site real property, which wastes or other materials were spilled, released, emitted or discharged by Murphy Oil. The Company is also indemnified by Murphy Oil for two years following the Superior Acquisition for liabilities arising from breaches of certain environmental representations and warranties made by Murphy Oil, subject to a maximum liability of $22,000, for which the Company is required to contribute up to the first $6,600.
On December 23, 2010, the Company entered into a settlement agreement with the LDEQ under LDEQ’s “Small Refinery and Single Site Refinery Initiative,” covering the Shreveport, Princeton and Cotton Valley refineries. This settlement agreement became effective on January 31, 2012. The settlement agreement, termed the “Global Settlement,” resolved alleged violations of the federal Clean Air Act and federal Clean Water Act regulations prior to December 31, 2010. The Company made a $1,000 payment to the LDEQ and agreed to complete beneficial environmental programs and implement emissions reduction projects at the Company’s Shreveport, Cotton Valley and Princeton refineries on an agreed-upon schedule. During the three and nine months ended September 30, 2012, the Company incurred approximately $50 and $2,222, respectively, of expenditures and estimates additional expenditures of approximately $4,000 to $8,000 of capital expenditures and expenditures related to additional personnel and environmental studies over the next four years as a result of the implementation of these requirements. This settlement agreement also fully settles the alleged environmental and permit violations at the Company’s Shreveport, 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 Company’s Shreveport, Princeton and Cotton Valley 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 completing the Global Settlement with the LDEQ, and currently anticipates completion of these projects over the next four years. These capital investment requirements will be incorporated into the Company’s 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 Global Settlement to have a material adverse effect on the Company’s financial results or operations. The terms of this settlement agreement were deemed final and effective on January 31, 2012 upon the concurrence of the Louisiana Attorney General.
In addition, new laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement or other developments could require us to make additional unforeseen expenditures. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. For example, on June 1, 2012, the EPA issued final amendments to the New Source Performance Standards (“NSPS”) for petroleum refineries, including standards for emissions of nitrogen oxides from process heaters and work practice standards and monitoring requirements for flares. The Company is currently evaluating the effect that the NSPS rule may have on the Company's refinery operations.
Voluntary remediation of subsurface contamination is in process at each of the Company’s refinery sites. The remedial projects are being overseen by the appropriate state agencies. Based on current investigative and remedial activities, the Company believes that the groundwater contamination at these refineries can be controlled or remedied without having a

17
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material adverse effect on the Company’s financial condition. However, such costs are often unpredictable and, therefore, there can be no assurance that the future costs will not become material. The Company incurred approximately $129 and $142 of such capital expenditures at its Cotton Valley refinery, respectively, during the three and nine months ended September 30, 2012. The Company incurred approximately $5 and $266, respectively, of such capital expenditures at its Cotton Valley refinery during the three and nine months ended September 30, 2011.
The Company is indemnified by Shell Oil Company, as successor to Pennzoil-Quaker State Company and Atlas Processing Company, for specified environmental liabilities arising from the operations of the Shreveport refinery prior to the Company’s acquisition of the facility. The indemnity is unlimited in amount and duration, but requires the Company to contribute up to $1,000 of the first $5,000 of indemnified costs for certain of the specified environmental liabilities.
Occupational Health and Safety
The Company is subject to various laws and regulations relating to occupational health and safety, including OSHA and comparable state laws. These laws and regulations strictly govern the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in the Company’s operations and that this information be provided to employees, contractors, state and local government authorities and customers. The Company maintains safety and training programs as part of its ongoing efforts to ensure compliance with applicable laws and regulations. The Company has implemented an internal program of inspection designed to monitor and enforce compliance with worker safety requirements as well as a quality system that meets the requirements of the ISO-9001-2008 Standard. The integrity of the Company’s ISO-9001-2008 Standard certification is maintained through surveillance audits by its registrar at regular intervals designed to ensure adherence to the standards. The Company’s compliance with applicable health and safety laws and regulations has required, and continues to require, substantial expenditures.
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. During the three and nine months ended September 30, 2012, the Company incurred approximately $195 and $506, respectively, of capital expenditures and expects to incur between $1,000 and $4,000 of capital expenditures during the remainder of 2012 and in 2013 to address OSHA compliance issues identified in these studies. The Company expects these capital expenditures will enhance its equipment such that the equipment maintains compliance with applicable consensus codes and standards.
In the first quarter of 2011, OSHA conducted an inspection of the Cotton Valley refinery’s process safety management program under OSHA’s National Emphasis Program. On March 14, 2011, OSHA issued a Citation and Notification of Penalty (the “Cotton Valley Citation”) to 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.


Labor Matters
The Company has employees covered by various collective bargaining agreements. The Superior collective bargaining agreement was ratified on August 10, 2012 and will expire on June 30, 2017. The Missouri collective bargaining agreement was ratified on May 1, 2012 and will expire on April 30, 2014.
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, 2012 and December 31, 2011, the Company had outstanding standby letters of credit of $180,688 and $230,040, respectively, under its senior secured revolving credit facility (the “revolving credit facility”). Refer to Note 7 for additional information regarding the revolving credit facility. The maximum amount of letters of credit the Company could issue at September 30, 2012 and December 31, 2011 under its revolving credit facility is subject to borrowing base limitations, with a maximum letter of credit sublimit equal to $680,000, which is the greater of (i) $400,000 and (ii) 80% of revolver commitments ($850,000 at September 30, 2012 and December 31, 2011) in effect.
As of September 30, 2012 and December 31, 2011, the Company had availability to issue letters of credit of $477,752 and $340,715, respectively, under its revolving credit facility. As discussed in Note 7, as of September 30, 2012 and December 31, 2011 the outstanding standby letters of credit issued under the revolving credit facility included a $25,000 letter of credit issued to a hedging counterparty to support a portion of its fuel products hedging program.


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Table of Contents

7. Long-Term Debt
Long-term debt consisted of the following:
 
 
September 30,
2012
 
December 31,
2011
Borrowings under amended and restated senior secured revolving credit agreement with third-party lenders, interest payments monthly, borrowings due June 2016, weighted average rate of 4.50% for the nine months ended September 30, 2012
$
25

 
$
—

Borrowings under 2019 Notes, interest at a fixed rate of 9.375%, interest payments semiannually, borrowings due May 2019, effective interest rate of 9.90% for the nine months ended September 30, 2012
600,000

 
600,000

Borrowings under 2020 Notes, interest at a fixed rate of 9.625%, interest payments semiannually, borrowings due August 2020, effective interest rate of 9.98% for the nine months ended September 30, 2012
275,000

 
—

Capital lease obligations, at various interest rates, interest and principal payments monthly through January 2027
5,720

 
786

Less unamortized discounts
(17,449
)
 
(13,696
)
Total long-term debt
863,296

 
587,090

Less current portion of long-term debt
783

 
551

 
$
862,513

 
$
586,539

9 5/8% Senior Notes
On June 29, 2012, in connection with the Royal Purple Acquisition, the Company issued and sold $275,000 in aggregate principal amount of 9 5/8% of senior notes due August 1, 2020 (the “2020 Notes”) in a private placement pursuant to Rule 144A under the Securities Act of 1933, as amended (the “Securities Act”), to eligible purchasers at a discounted price of 98.25 percent of par. The 2020 Notes were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. The Company received net proceeds of $262,645, net of discount, underwriters’ fees and expenses, which the Company used to fund a portion of the purchase price of the Royal Purple Acquisition. Refer to Note 3 for additional information regarding the Royal Purple Acquisition.
Interest on the 2020 Notes is paid semiannually in arrears on February 1 and August 1 of each year, beginning on February 1, 2013. The 2020 Notes will mature on August 1, 2020, unless redeemed prior to maturity. The 2020 Notes are jointly and severally guaranteed on a senior unsecured basis by all of the Company’s current operating subsidiaries and certain of the Company’s future operating subsidiaries, with the exception of Calumet Finance Corp. (a wholly owned Delaware corporation that was organized for the sole purpose of being a co-issuer of certain of the Company’s indebtedness, including the 2020 Notes). The operating subsidiaries may not sell or otherwise dispose of all or substantially all of their properties or assets to, or consolidate with or merge into, another company if such a sale would cause a default under the indenture governing the 2020 Notes.
At any time prior to August 1, 2015, the Company may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2020 Notes with the net proceeds of a public or private equity offering at a redemption price of 109.625% of the principal amount, plus any accrued and unpaid interest to the date of redemption, provided that: (1) at least 65% of the aggregate principal amount of 2020 Notes issued remains outstanding immediately after the occurrence of such redemption and (2) the redemption occurs within 120 days of the date of the closing of such public or private equity offering.
On and after August 1, 2016, the Company may on any one or more occasions redeem all or a part of the 2020 Notes at the redemption prices (expressed as percentages of principal amount) set forth below, plus any accrued and unpaid interest to the applicable redemption date on such 2020 Notes, if redeemed during the twelve-month period beginning on August 1 of the years indicated below:
 
Year
Percentage
2016
104.813
%
2017
102.406
%
2018 and at any time thereafter
100.000
%

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Prior to August 1, 2016, the Company may on any one or more occasions redeem all or part of the 2020 Notes at a redemption price equal to the sum of: (1) the principal amount thereof, plus (2) a make-whole premium (as set forth in the indenture governing the 2020 Notes) at the redemption date, plus any accrued and unpaid interest to the applicable redemption date.
The indenture governing the 2020 Notes contains covenants that, among other things, restrict the Company’s ability and the ability of certain of the Company’s subsidiaries to: (i) sell assets; (ii) pay distributions on, redeem or repurchase the Company’s common units or redeem or repurchase its subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (vii) consolidate, merge or transfer all or substantially all of the Company’s assets; (viii) engage in transactions with affiliates and (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. At any time when the 2020 Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default or Event of Default, each as defined in the indenture governing the 2020 Notes, has occurred and is continuing, many of these covenants will be suspended.
Upon the occurrence of certain change of control events, each holder of the 2020 Notes will have the right to require that the Company repurchase all or a portion of such holder’s 2020 Notes in cash at a purchase price equal to 101% of the principal amount thereof, plus any accrued and unpaid interest to the date of repurchase.
On June 29, 2012, in connection with the issuance and sale of the 2020 Notes, the Company entered into a registration rights agreement (the “Registration Rights Agreement”) with the initial purchasers of the 2020 Notes obligating the Company to use reasonable best efforts to file an exchange registration statement with the SEC, so that holders of the 2020 Notes can offer to exchange the 2020 Notes for registered notes having substantially the same terms as the 2020 Notes and evidencing the same indebtedness as the 2020 Notes. The Company must use reasonable best efforts to cause the exchange offer registration statement to become effective by June 28, 2013 and remain effective until 180 days after the closing of the exchange. Additionally, the Company has agreed to commence the exchange offer promptly after the exchange offer registration statement is declared effective by the SEC and use reasonable best efforts to complete the exchange offer not later than 60 days after such effective date. Under certain circumstances, in lieu of a registered exchange offer, the Company must use reasonable best efforts to file a shelf registration statement for the resale of the 2020 Notes. If the Company fails to satisfy these obligations on a timely basis, the annual interest borne by the 2020 Notes will be increased by up to 1.0% per annum until the exchange offer is completed or the shelf registration statement is declared effective.
9 3/8% Senior Notes
On April 21, 2011, in connection with the restructuring of the majority of its outstanding long-term debt, the Company issued and sold $400,000 in aggregate principal amount of 9 3/8% of senior notes due May 1, 2019 (the “2019 Notes issued in April 2011”) in a private placement pursuant to Rule 144A under the Securities Act to eligible purchasers at par. The 2019 Notes issued in April 2011 were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. The Company received proceeds of $388,999 net of underwriters’ fees and expenses, which the Company used to repay in full borrowings outstanding under its prior term loan, as well as all accrued interest and fees, and for general partnership purposes.
On September 19, 2011, in connection with the Superior Acquisition, the Company issued and sold $200,000 in aggregate principal amount of 9 3/8% of senior notes due May 1, 2019 (the “2019 Notes issued in September 2011”) in a private placement pursuant to Rule 144A under the Securities Act to eligible purchasers at a discounted price of 93 percent of par. The 2019 Notes issued in September 2011 were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. The Company received proceeds of $180,296 net of discount, underwriters’ fees and expenses, which the Company used to fund a portion of the purchase price of the Superior Acquisition. Because the terms of the 2019 Notes issued in September 2011 are substantially identical to the terms of the 2019 Notes issued in April 2011, in this 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 is paid semiannually in arrears on May 1 and November 1 of each year, beginning on November 1, 2011. The 2019 Notes will mature on May 1, 2019, unless redeemed prior to maturity. The 2019 Notes are jointly and severally guaranteed on a senior unsecured basis by all of the Company’s current operating subsidiaries and certain of the Company’s future operating subsidiaries, with the exception of Calumet Finance Corp. (a wholly owned Delaware corporation that was organized for the sole purpose of being a co-issuer of certain of the Company’s indebtedness, including the 2019 Notes). The operating subsidiaries may not sell or otherwise dispose of all or substantially all of their properties or assets to, or consolidate with or merge into, another company if such a sale would cause a default under the indentures governing the 2019 Notes.

20
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The indentures governing the 2019 Notes contain covenants that, among other things, restrict the Company’s ability and the ability of certain of the Company’s subsidiaries to: (i) sell assets; (ii) pay distributions on, redeem or repurchase the Company’s common units or redeem or repurchase its subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (vii) consolidate, merge or transfer all or substantially all of the Company’s assets; (viii) engage in transactions with affiliates and (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. At any time when the 2019 Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default or Event of Default, each as defined in the indentures governing the 2019 Notes, has occurred and is continuing, many of these covenants will be suspended.
Upon the occurrence of certain change of control events, each holder of the 2019 Notes will have the right to require that the Company repurchase all or a portion of such holder’s 2019 Notes in cash at a purchase price equal to 101% of the principal amount thereof, plus any accrued and unpaid interest to the date of repurchase.
Amended and Restated Senior Secured Revolving Credit Facility
The Company has an $850,000 senior secured revolving credit facility, which is its primary source of liquidity for cash needs in excess of cash generated from operations. The revolving credit facility matures in June 1, 2016 and currently bears interest at a rate equal to prime plus a basis points margin or LIBOR plus a basis points margin, at the Company’s option. As of September 30, 2012, the margin was 125 basis points for prime and 250 basis points for LIBOR; however, the margin can fluctuate quarterly based on the Company’s average availability for additional borrowings under the revolving credit facility in the preceding calendar quarter.
In addition to paying interest monthly on outstanding borrowings under the revolving credit facility, the Company is required to pay a commitment fee to the lenders under the revolving credit facility with respect to the unutilized commitments thereunder at a rate equal to 0.375% to 0.50% per annum depending on the average daily available unused borrowing capacity. The Company also pays a customary letter of credit fee, including a fronting fee of 0.125% per annum of the stated amount of each outstanding letter of credit, and customary agency fees.
The borrowing capacity at September 30, 2012 under the revolving credit facility was $658,465. As of September 30, 2012, the Company had $25 in outstanding borrowings under the revolving credit facility, leaving $477,752 available for additional borrowings based on specified availability limitations. Lenders under the revolving credit facility have a first priority lien on the Company’s cash, accounts receivable, inventory and certain other personal property.
The revolving credit facility contains various covenants that limit, among other things, the Company’s ability to: incur indebtedness; grant liens; dispose of certain assets; make certain acquisitions and investments; redeem or prepay other debt or make other restricted payments such as distributions to unitholders; enter into transactions with affiliates and enter into a merger, consolidation or sale of assets. Further, the revolving credit facility contains one springing financial covenant which provides that only if the Company’s availability under the revolving credit facility falls below the greater of (i)12.5% of the lesser of (a) the Borrowing Base (as defined in the revolving credit agreement) (without giving effect to the LC Reserve (as defined in the revolving credit agreement)) and (b) the credit agreement commitments then in effect and (ii) $46,364, (as increased, upon the effectiveness of the increase in the maximum availability under the revolving credit facility, by the same percentage as the percentage increase in the revolving credit agreement commitments), then the Company will be required to maintain as of the end of each fiscal quarter a Fixed Charge Coverage Ratio (as defined in the revolving credit agreement) of at least 1.0 to 1.0.
Capital Lease Obligations
In connection with the TruSouth Acquisition, the Company recorded $5,771 of capital leases for a building and equipment.





21
Table of Contents

Maturities of Long-Term Debt
As of September 30, 2012, maturities of the Company’s long-term debt are as follows:
 
Year
Maturity
2012
$
207

2013
771

2014
423

2015
303

2016
354

Thereafter
878,687

Total
$
880,745


8. 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 current assets or current 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 Company’s financial results are subject to the possibility that changes in a derivative’s fair value could result in significant ineffectiveness and potentially no longer qualify it for hedge accounting. The Company recorded the following derivative assets and liabilities at their fair values as of September 30, 2012 and December 31, 2011:
 
 
Derivative Assets
 
Derivative Liabilities
 
September 30, 2012
 
December 31, 2011
 
September 30, 2012
 
December 31, 2011
Derivative instruments designated as hedges:
 
 
 
 
 
 
 
Fuel products segment:
 
 
 
 
 
 
 
Crude oil swaps
$
—

 
$
83,919

 
$
(21,235
)
 
$
56,041

Gasoline swaps
—

 
(20,605
)
 
67

 
(1,596
)
Diesel swaps
—

 
(4,561
)
 
(33,256
)
 
(22,586
)
Jet fuel swaps
—

 
1,077

 
(28,786
)
 
(72,537
)
Total derivative instruments designated as hedges
—

 
59,830

 
(83,210
)
 
(40,678
)
Derivative instruments not designated as hedges:
 
 
 
 
 
 
 
Fuel products segment:
 
 
 
 
 
 
 
Crude oil swaps
—

 
—

 
9,120

 
—

Gasoline swaps
—

 
—

 
(16,062
)
 
—

Diesel swaps
—

 
—

 
(6,733
)
 
—

Jet fuel swaps
—

 
—

 
—

 
—

Specialty products segment:
 
 
 
 
 
 
 
Crude oil swaps
—

 
—

 
1,628

 
—

Natural gas swaps (1)
—

 
(1,328
)
 
(545
)
 
(1,892
)
Interest rate swaps: (2)
—

 
—

 
—

 
(1,011
)
Total derivative instruments not designated as hedges
—

 
(1,328
)
 
(12,592
)
 
(2,903
)
Total derivative instruments
$
—

 
$
58,502

 
$
(95,802
)
 
$
(43,581
)
 __________________________

22
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(1)
The Company enters into natural gas swaps to economically hedge its exposures to price risk related to these commodities in its specialty products segment. The Company has not designated these derivative instruments as cash flow hedges.
(2)
The Company refinanced a significant majority of its long-term debt in April 2011 and, as a result, all of its interest rate swaps that were designated as cash flow hedges for the interest payments under the previous term loan facility are no longer designated as cash flow hedges.
The Company accounts for certain derivatives hedging purchases of crude oil, sales of gasoline, diesel and jet fuel as cash flow hedges. The derivatives hedging sales and purchases are recorded to sales and cost of sales, respectively, in the 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. At times, the Company may enter into crude oil or fuel product basis swaps to more effectively hedge its crude oil purchases.  These derivatives can be combined with a swap contract in order to create a more effective hedge.  The Company has entered into crude oil basis swaps for the fourth quarter of 2012 and for 2013 that do not qualify as cash flow hedges for accounting purposes as they were not entered into simultaneously with a corresponding NYMEX WTI derivative contract.
To the extent a derivative instrument designated as a hedge is determined to be effective as a cash flow hedge of an exposure to changes in the fair value of a future transaction, the change in fair value of the derivative is deferred in accumulated other comprehensive income (loss), a component of partners’ capital in the condensed consolidated balance sheets, until the underlying transaction hedged is recognized in the unaudited condensed consolidated statements of operations. Hedge accounting is discontinued when it is determined that a derivative no longer qualifies as an effective hedge or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative instrument no longer qualifies as an effective cash flow hedge, the derivative instrument is subject to the mark-to-market method of accounting prospectively. Changes in the mark-to-market fair value of the derivative instrument are recorded to unrealized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. Unrealized gains and losses related to discontinued cash flow hedges that were previously accumulated in accumulated other comprehensive income (loss) will remain in accumulated other comprehensive income (loss) until the underlying transaction is reflected in earnings, unless it is probable that the hedged forecasted transaction will not occur, at which time, associated deferred amounts in accumulated other comprehensive income (loss) are immediately recognized in unrealized gain (loss) on derivative instruments.
Effective January 1, 2012, hedge accounting was discontinued prospectively for certain crude oil derivative instruments when it was determined that they were no longer highly effective in offsetting changes in the cash flows associated with crude oil purchases at the Company’s Superior refinery due to the volatility in crude oil pricing differentials between heavy crude oil and NYMEX WTI. Effective April 1, 2012, hedge accounting was discontinued prospectively for certain gasoline and diesel derivative instruments associated with gasoline and diesel sales at the Company’s Superior refinery. The discontinuance of hedge accounting on these derivative instruments has caused the Company to recognize derivative losses of $4,767 and derivative gains $49,661 in realized gain (loss) on derivative instruments, respectively, in the unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2012. The discontinuance of hedge accounting on these derivative instruments caused the Company to recognize derivative losses of $34,975 and $6,848 in unrealized loss on derivative instruments, respectively, in the unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2012.
The amount reclassified from accumulated other comprehensive income (loss) into earnings, as a result of the discontinuance of hedge accounting for certain jet fuel products derivative instruments because it was no longer probable that the original forecasted transaction would occur by the end of the originally specified time period, has caused the Company to recognize derivative losses of $652 and $1,719 in realized gain (loss) on derivative instruments, respectively, in the unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2012.
For derivative instruments not designated as cash flow hedges and the portion of any cash flow hedge that is determined to be ineffective, the change in fair value of the asset or liability for the period is recorded to unrealized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. Upon the settlement of a derivative not designated as a cash flow hedge, the gain or loss at settlement is recorded to realized gain (loss) on derivative instruments in the 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 has

23
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resulted, in increased volatility in the Company’s financial results. However, even though certain derivative instruments may not qualify for hedge accounting, the Company intends to continue to utilize such instruments as management believes such derivative instruments continue to provide the Company with the opportunity to more effectively stabilize cash flows.
The Company recorded the following amounts in its condensed consolidated balance sheets, unaudited condensed consolidated statements of operations, unaudited condensed consolidated statements of other comprehensive income (loss) and its unaudited condensed consolidated statements of partners’ capital as of, and for the three months ended, September 30, 2012 and 2011 related to its derivative instruments that were designated as cash flow hedges:
 
 
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)
 
Amount of (Gain) Loss Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Effective Portion)
 
Amount of Gain (Loss) Recognized in Net Income on Derivatives (Ineffective Portion)
 
Three Months Ended
 
Location of (Gain) Loss
 
Three Months Ended
 
Location of Gain (Loss)
 
Three Months Ended
 
September 30,
 
 
September 30,
 
 
September 30,
Type of Derivative
2012
 
2011
 
 
2012
 
2011
 
 
2012
 
2011
Fuel products segment:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil swaps
$
13,042

 
$
(171,581
)
 
Cost of sales
 
$
(7,996
)
 
$
(25,411
)
 
Unrealized/ Realized
 
$
34,078

 
$
(22,072
)
Gasoline swaps
8,880

 
5,883

 
Sales
 
—

 
4,493

 
Unrealized/ Realized
 
(23,037
)
 
(19
)
Diesel swaps
(49,261
)
 
46,413

 
Sales
 
29,164

 
18,887

 
Unrealized/ Realized
 
(1,156
)
 
(252
)
Jet fuel swaps
(56,052
)
 
81,523

 
Sales
 
20,408

 
37,745

 
Unrealized/ Realized
 
(4,577
)
 
(1,793
)
Jet fuel collars
—

 
—

 
Sales
 
—

 
—

 
Unrealized/ Realized
 
—

 
—

Specialty products segment:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil swaps
—

 
—

 
Cost of sales
 
190

 
(1,364
)
 
Unrealized/ Realized
 
—

 
—

Natural gas swaps
—

 
—

 
Cost of sales
 
—

 
—

 
Unrealized/ Realized
 
—

 
—

Interest rate swaps:
—

 
—

 
Interest expense
 
—

 
—

 
Unrealized/ Realized
 
—

 
—

Total
$
(83,391
)
 
$
(37,762
)
 
 
 
$
41,766

 
$
34,350

 
 
 
$
5,308

 
$
(24,136
)
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, 2012 and 2011 related to its derivative instruments not designated as cash flow hedges.
 
 
Amount of Gain (Loss) Recognized in Realized Gain (Loss) on Derivative Instruments
 
Amount of Gain (Loss) Recognized in Unrealized Loss on Derivative Instruments
 
Three Months Ended
 
Three Months Ended
 
September 30,
 
September 30,
Type of Derivative
2012
 
2011
 
2012
 
2011
Fuel products segment:
 
 
 
 
 
 
 
Crude oil swaps
$
(8,854
)
 
$
—

 
$
40,165

 
$
—

Gasoline swaps
2,451

 
—

 
(40,966
)
 
—

Diesel swaps
2,860

 
—

 
(34,174
)
 
—

Jet fuel swaps
(651
)
 
—

 
480

 
—

Jet fuel collars
—

 
—

 
—

 
(1
)
Specialty products segment:
 
 
 
 
 
 
 
Crude oil swaps
—

 
—

 
1,044

 
—

Natural gas swaps
(1,467
)
 
—

 
1,540

 
—

Interest rate swaps:
(137
)
 
(655
)
 
144

 
643

Total
$
(5,798
)
 
$
(655
)
 
$
(31,767
)
 
$
642


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Table of Contents

The Company recorded the following amounts in its condensed consolidated balance sheets, unaudited condensed consolidated statements of operations, unaudited condensed consolidated statements of other comprehensive income (loss) and its unaudited condensed consolidated statements of partners’ capital as of, and for the nine months ended, September 30, 2012 and 2011 related to its derivative instruments that were designated as cash flow hedges:
 
 
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income  (Loss) on Derivatives (Effective Portion)
 
Amount of (Gain) Loss Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Effective Portion)
 
Amount of Gain (Loss) Recognized in Net Income on Derivatives (Ineffective Portion)
 
Nine Months Ended
 
Location of (Gain) Loss
 
Nine Months Ended
 
Location of Gain (Loss)
 
Nine Months Ended
 
September 30,
 
 
September 30,
 
 
September 30,
Type of Derivative
2012
 
2011
 
 
2012
 
2011
 
 
2012
 
2011
Fuel products segment:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil swaps
$
(85,858
)
 
$
(110,393
)
 
Cost of sales
 
$
(42,606
)
 
$
(86,510
)
 
Unrealized/ Realized
 
$
84,004

 
$
(22,569
)
Gasoline swaps
(31,285
)
 
(11,853
)
 
Sales
 
39,204

 
23,308

 
Unrealized/ Realized
 
(38,355
)
 
(1,358
)
Diesel swaps
(70,692
)
 
(22,379
)
 
Sales
 
52,005

 
62,074

 
Unrealized/ Realized
 
(2,996
)
 
(790
)
Jet fuel swaps
(48,444
)
 
(37,891
)
 
Sales
 
89,018

 
80,419

 
Unrealized/ Realized
 
(2,686
)
 
(3,397
)
Jet fuel collars
—

 
—

 
Sales
 
—

 
—

 
Unrealized/ Realized
 
—

 
—

Specialty products segment:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil swaps
—

 
—

 
Cost of sales
 
176

 
1,301

 
Unrealized/ Realized
 
—

 
—

Natural gas swaps
—

 
—

 
Cost of sales
 
—

 
—

 
Unrealized/ Realized
 
—

 
—

Interest rate swaps:
—

 
1,979

 
Interest expense
 
—

 
702

 
Unrealized/ Realized
 
—

 
—

Total
$
(236,279
)
 
$
(180,537
)
 
 
 
$
137,797

 
$
81,294

 
 
 
$
39,967

 
$
(28,114
)
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, 2012 and 2011 related to its derivative instruments not designated as cash flow hedges.
 
Amount of Gain (Loss) Recognized in Realized Gain (Loss) on Derivative Instruments
 
Amount of Gain (Loss) Recognized in Unrealized Loss on Derivative Instruments
 
Nine Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
Type of Derivative
2012
 
2011
 
2012
 
2011
Fuel products segment:
 
 
 
 
 
 
 
Crude oil swaps
$
(16,207
)
 
$
—

 
$
(40,000
)
 
$
—

Gasoline swaps
13,842

 
—

 
(1,149
)
 
—

Diesel swaps
8,044

 
—

 
6,700

 
—

Jet fuel swaps
(1,719
)
 
—

 
—

 
—

Jet fuel collars
—

 
(562
)
 
—

 
542

Specialty products segment:
 
 
 
 
 
 
 
Crude oil swaps
—

 
932

 
1,628

 
(662
)
Natural gas swaps
(4,917
)
 
—

 
2,675

 
—

Interest rate swaps:
(726
)
 
(1,407
)
 
1,011

 
(403
)
Total
$
(1,683
)
 
$
(1,037
)
 
$
(29,135
)
 
$
(523
)
The cash flow impact of the Company’s derivative activities is classified primarily as a component of net income (loss) in the operating activities section in the unaudited condensed consolidated statements of cash flows.

25
Table of Contents

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 Company’s credit exposure related to these derivative instruments is represented by the fair value of contracts reported as derivative assets. As of September 30, 2012, the Company did not have any counterparties, in which derivatives held were net assets. As of December 31, 2011, the Company had three counterparties, in which the derivatives held were net assets, totaling $58,502. To manage credit risk, the Company selects and periodically reviews counterparties based on credit ratings. The Company primarily executes its derivative instruments with large financial institutions that have ratings of at least Baa2 and BBB by Moody’s 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 master derivative contracts with these counterparties. No such collateral was held by the Company as of September 30, 2012 or December 31, 2011. The Company’s contracts with these counterparties allow for netting of derivative instruments executed under each contract. Collateral received from counterparties is reported in other current liabilities, and collateral held by counterparties is reported in deposits, on the Company’s condensed consolidated balance sheets and is not netted against derivative assets or liabilities. As of September 30, 2012 and December 31, 2011, the Company had provided its counterparties with no collateral except for a $25,000 letter of credit provided to one counterparty to support crack spread hedging. For financial reporting purposes, the Company does not offset the collateral provided to a counterparty against the fair value of its obligation to that counterparty. Any outstanding collateral is released to the Company upon settlement of the related derivative instrument liability.
Certain of the Company’s outstanding derivative instruments are subject to credit support agreements with the applicable counterparties which contain provisions setting certain credit thresholds above which the Company may be required to post agreed-upon collateral, such as cash or letters of credit, with the counterparty to the extent that the Company’s mark-to-market net liability, if any, on all outstanding derivatives exceeds the credit threshold amount per such credit support agreement. In certain cases, the Company’s credit threshold is dependent upon the Company’s maintenance of certain corporate credit ratings with Moody’s and S&P. In the event that the Company’s corporate credit rating was lowered below its current level by either Moody’s or S&P, such counterparties would have the right to reduce the applicable threshold to zero and demand full collateralization of the Company’s net liability position on outstanding derivative instruments. As of September 30, 2012 and December 31, 2011, there was a net liability of $9,663 and net asset of $3,561, respectively, associated with the Company’s outstanding derivative instruments subject to such requirements. In addition, the majority of the credit support agreements covering the Company’s outstanding derivative instruments also contain a general provision stating that if the Company experiences a material adverse change in its business, in the reasonable discretion of the counterparty, the Company’s credit threshold could be lowered by such counterparty. The Company does not expect that it will experience a material adverse change in its business.
The effective portion of the cash flow hedges classified in accumulated other comprehensive loss was $51,388 as of September 30, 2012. The effective portion of the cash flow hedges classified in accumulated other comprehensive income was $47,094 as of December 31, 2011. Absent a change in the fair market value of the underlying transactions, the following other comprehensive income (loss) at September 30, 2012 will be reclassified to earnings by December 31, 2015 with balances being recognized as follows:
 
Year
Accumulated Other Comprehensive Loss
2012
$
(13,367
)
2013
(22,515
)
2014
(13,585
)
2015
(1,921
)
Total
$
(51,388
)
Based on fair values as of September 30, 2012, the Company expects to reclassify $34,049 of net losses on derivative instruments from accumulated other comprehensive loss to earnings during the next twelve months due to actual crude oil purchases and gasoline, diesel and jet fuel sales. However, the amounts actually realized will be dependent on the fair values as of the dates of settlement.
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. Historically, the Company has utilized combinations of options and swaps to manage crude oil price risk and volatility of cash flows in its specialty

26
Table of Contents

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 company’s general policy is to enter into crude oil derivative contracts that mitigate the Company’s exposure to price risk associated with crude oil purchases related to specialty products production (for up to 70% of expected purchases). The Company may execute derivative contracts for up to two years forward. As of September 30, 2012, the Company purchased a crude oil derivative swap for 200,000 bbls in the second quarter of 2012 related to future crude oil purchases in its specialty segment, which is not designated as a cash flow hedge. The Company has subsequently sold a crude oil derivative swap in the third quarter of 2012, and the net impact of these two trades is a net gain of $1,044 and $1,628 that has been recorded to unrealized gain, respectively, in the unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2012. This gain will be realized in January 2013 and will be recorded to realized gain (loss) in the unaudited condensed consolidated statement of operations.
At December 31, 2011, the Company did not have any crude oil derivatives related to future crude oil purchases in its specialty products segment.
Natural Gas Swap Contracts
Natural gas purchases comprise a significant component of the Company’s 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 Company’s policy is generally to enter into natural gas derivative contracts to hedge no more than 75% of its anticipated natural gas requirement for a period no greater than three years forward. At September 30, 2012, the Company had the following natural gas derivatives related to natural gas purchases in its specialty products segment, none of which were designated as cash flow hedges.
 
Natural Gas Swap Contracts by Expiration Dates
MMBtu
 
$/MMBtu
Fourth Quarter 2012
600,000

 
$
4.08

Totals
600,000

 
 
Average price
 
 
$
4.08

At December 31, 2011, the Company had the following natural gas derivatives related to natural gas purchases in its specialty products segment, none of which were designated as cash flow hedges.
Natural Gas Swap Contracts by Expiration Dates
MMBtu
 
$/MMBtu
First Quarter 2012
1,200,000

 
$
3.90

Second Quarter 2012
1,200,000

 
3.93

Third Quarter 2012
1,200,000

 
4.03

Fourth Quarter 2012
600,000

 
4.08

Totals
4,200,000

 
 
Average price
 
 
$
3.97

Crude Oil Contracts — Fuel Products Segment
Crude Oil Swap Contracts
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 Company’s 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, 2012, the Company had the following derivatives related to crude oil purchases in its fuel products segment, all of which are designated as cash flow hedges.
 

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Table of Contents

Crude Oil Swap Contracts by Expiration Dates
Barrels Purchased
 
BPD
 
Average Swap ($/Bbl)
Fourth Quarter 2012
1,242,000

 
13,500

 
$
90.50

Calendar Year 2013
5,784,000

 
15,847

 
98.85

Calendar Year 2014
4,195,000

 
11,493

 
89.31

Calendar Year 2015
3,467,500

 
9,500

 
90.44

Totals
14,688,500

 
 
 
 
Average price
 
 
 
 
$
93.43

At September 30, 2012, the Company had the following derivatives related to crude oil purchases in its fuel products segment, none of which are designated as cash flow hedges.
 
Crude Oil Swap Contracts by Expiration Dates
Barrels Purchased
 
BPD
 
Average Swap ($/Bbl)
Fourth Quarter 2012
1,380,000

 
15,000

 
$
83.35

Calendar Year 2013
1,821,000

 
4,989

 
98.72

Totals
3,201,000

 
 
 
 
Average price
 
 
 
 
$
92.09

At December 31, 2011, the Company had the following derivatives related to crude oil purchases in its fuel products segment, all of which are designated as cash flow hedges.
 
Crude Oil Swap Contracts by Expiration Dates
Barrels Purchased
 
BPD
 
Average Swap ($/Bbl)
First Quarter 2012
2,866,500

 
31,500

 
$
85.34

Second Quarter 2012
2,775,500

 
30,500

 
84.83

Third Quarter 2012
2,852,000

 
31,000

 
84.83

Fourth Quarter 2012
2,622,000

 
28,500

 
86.73

Calendar Year 2013
4,420,000

 
12,110

 
97.93

Calendar Year 2014
1,000,000

 
2,740

 
90.55

Totals
16,536,000

 
 
 
 
Average price
 
 
 
 
$
89.07

Crude Oil Basis Swap Contracts
In April and July 2012, the Company entered into crude oil basis swaps to mitigate the risk of future changes in pricing differentials between Canadian heavy crude oil and NYMEX WTI crude oil. At September 30, 2012, the Company had the following derivatives related to crude oil basis swaps in its fuel products segment, none of which are designated as cash flow hedges. 
Crude Oil Basis Swap Contracts by Expiration Dates
Barrels Purchased
 
BPD
 
Average Differential to NYMEX WTI ($/Bbl)
Fourth Quarter 2012
184,000

 
2,000

 
$
(23.50
)
Calendar Year 2013
730,000

 
2,000

 
(23.75
)
Totals
914,000

 
 
 

Average price
 
 
 
 
$
(23.70
)
At December 31, 2011, the Company had no derivatives related to crude oil basis swaps in its fuel products segment.
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

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Table of Contents

Company’s 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.
Diesel Swap Contracts
At September 30, 2012, the Company had the following derivatives related to diesel and jet fuel sales in its fuel products segment, all of which are designated as cash flow hedges.
 
Diesel Swap Contracts by Expiration Dates
Barrels Sold
 
BPD
 
Average Swap ($/Bbl)
Fourth Quarter 2012
506,000

 
5,500

 
$
105.41

Calendar Year 2013
1,926,000

 
5,277

 
121.78

Calendar Year 2014
2,920,000

 
8,000

 
114.83

Calendar Year 2015
3,467,500

 
9,500

 
116.65

Totals
8,819,500

 
 
 
 
Average price
 
 
 
 
$
116.52

At September 30, 2012, the Company had the following derivatives related to diesel and jet fuel sales in its fuel products segment, none of which are designated as cash flow hedges.
 
Diesel Swap Contracts by Expiration Dates
Barrels Sold
 
BPD
 
Average Swap ($/Bbl)
Fourth Quarter 2012
460,000

 
5,000

 
$
115.27

Calendar Year 2013
1,456,000

 
3,989

 
127.20

Totals
1,916,000

 
 
 
 
Average price
 
 
 
 
$
124.34

At December 31, 2011, the Company had the following derivatives related to diesel and jet fuel sales in its fuel products segment, all of which are designated as cash flow hedges.
Diesel Swap Contracts by Expiration Dates
Barrels Sold
 
BPD
 
Average Swap ($/Bbl)
First Quarter 2012
546,000

 
6,000

 
$
118.07

Second Quarter 2012
819,000

 
9,000

 
110.09

Third Quarter 2012
1,150,000

 
12,500

 
105.48

Fourth Quarter 2012
966,000

 
10,500

 
110.11

Calendar Year 2013
1,831,000

 
5,016

 
123.20

Totals
5,312,000

 
 
 
 
Average price
 
 
 
 
$
114.44

Jet Fuel Swap Contracts
At September 30, 2012, the Company had the following derivatives related to diesel and jet fuel sales in its fuel products segment, all of which are designated as cash flow hedges.
 
Jet Fuel Swap Contracts by Expiration Dates
Barrels Sold
 
BPD
 
Average Swap ($/Bbl)
Fourth Quarter 2012
736,000

 
8,000

 
$
104.79

Calendar Year 2013
2,498,000

 
6,844

 
127.09

Calendar Year 2014
1,275,000

 
3,493

 
116.64

Totals
4,509,000

 
 
 
 
Average price
 
 
 
 
$
120.50


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Table of Contents

At December 31, 2011, the Company had the following derivatives related to diesel and jet fuel sales in its fuel products segment, all of which are designated as cash flow hedges.
 
Jet Fuel Swap Contracts by Expiration Dates
Barrels Sold
 
BPD
 
Average Swap ($/Bbl)
First Quarter 2012
1,274,000

 
14,000

 
$
97.97

Second Quarter 2012
1,046,500

 
11,500

 
98.47

Third Quarter 2012
782,000

 
8,500

 
99.78

Fourth Quarter 2012
736,000

 
8,000

 
104.79

Calendar Year 2013
2,044,000

 
5,600

 
125.13

Calendar Year 2014
1,000,000

 
2,740

 
115.56

Totals
6,882,500

 
 
 
 
Average price
 
 
 
 
$
109.60

Gasoline Swap Contracts
At September 30, 2012, the Company had the following derivatives related to gasoline sales in its fuel products segment, all of which are designated as cash flow hedges.
 
Gasoline Swap Contracts by Expiration Dates
Barrels Sold
 
BPD
 
Average Swap ($/Bbl)
Calendar Year 2013
1,360,000

 
3,726

 
$
114.84

Totals
1,360,000

 
 
 
 
Average price
 
 
 
 
$
114.84

At September 30, 2012, the Company had the following derivatives related to gasoline sales in its fuel products segment, none of which are designated as cash flow hedges.
 
Gasoline Swap Contracts by Expiration Dates
Barrels Sold
 
BPD
 
Average Swap ($/Bbl)
Fourth Quarter 2012
920,000

 
10,000

 
$
102.48

Calendar Year 2013
365,000

 
1,000

 
105.50

Totals
1,285,000

 
 
 
 
Average price
 
 
 
 
$
103.33

At December 31, 2011, the Company had the following derivatives related to gasoline sales in its fuel products segment, all of which are designated as cash flow hedges.
 
Gasoline Swap Contracts by Expiration Dates
Barrels Sold
 
BPD
 
Average Swap ($/Bbl)
First Quarter 2012
1,046,500

 
11,500

 
$
100.72

Second Quarter 2012
910,000

 
10,000

 
102.48

Third Quarter 2012
920,000

 
10,000

 
102.48

Fourth Quarter 2012
920,000

 
10,000

 
102.48

Calendar Year 2013
545,000

 
1,493

 
107.11

Totals
4,341,500

 
 
 
 
Average price
 
 
 
 
$
102.63