CLMT-2014.03.31-10Q
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 MARCH 31, 2014
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.
Large accelerated filer
 
x
  
Accelerated filer
 
¨
 
 
 
 
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 Exchange Act).    Yes  ¨    No  x
At May 9, 2014, there were 69,317,278 common units outstanding.
 

Table of Contents

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
QUARTERLY REPORT
For the Three Months Ended March 31, 2014
Table of Contents
 
 
Page
 

2
Table of Contents

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 required audits or required operational changes or other environmental and regulatory liabilities, (ii) estimated capital expenditures as a result of our planned organic growth projects, (iii) our anticipated levels of, use and effectiveness of derivatives to mitigate our exposure to crude oil price changes, natural gas price changes and fuel products price changes, (iv) estimated costs of complying with the U.S. Environmental Protection Agency’s (“EPA”) Renewable Fuel Standards, including the prices paid for Renewable Identification Numbers (“RINs”) and (v) 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 sales 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 (i) Part II, Item 7A “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, 2013 (“2013 Annual Report”) and (ii) Part I, Item 3 “Quantitative and Qualitative Disclosures About Market Risk” and 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 they are made. 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.,” “Calumet,” “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.


3
Table of Contents

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

 
March 31, 2014
 
December 31, 2013
 
(Unaudited)
 
 
 
(In millions, except unit data)
ASSETS
Current assets:
 
 
 
Cash and cash equivalents
$
179.6

 
$
121.1

Accounts receivable:
 
 
 
Trade
388.6

 
250.3

Other
5.9

 
13.0

 
394.5

 
263.3

Inventories
675.9

 
567.4

Derivative assets
17.2

 
—

Prepaid expenses and other current assets
16.7

 
18.9

Deposits
0.5

 
3.7

Total current assets
1,284.4

 
974.4

Property, plant and equipment, net
1,221.6

 
1,160.4

Investment in unconsolidated affiliates
51.7

 
33.4

Goodwill
272.5

 
207.0

Other intangible assets, net
284.6

 
212.9

Other noncurrent assets, net
102.8

 
100.0

Total assets
$
3,217.6

 
$
2,688.1

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
 
 
 
Accounts payable
$
566.2

 
$
355.8

Accrued interest payable
15.1

 
22.5

Accrued salaries, wages and benefits
18.1

 
14.0

Other taxes payable
17.9

 
18.4

Other current liabilities
35.9

 
36.2

Current portion of long-term debt
0.4

 
0.4

Derivative liabilities
4.2

 
54.8

Total current liabilities
657.8

 
502.1

Deferred income tax liability
25.3

 
—

Pension and postretirement benefit obligations
11.5

 
11.7

Other long-term liabilities
1.0

 
1.1

Long-term debt, less current portion
1,518.4

 
1,110.4

Total liabilities
2,214.0

 
1,625.3

Commitments and contingencies

 

Partners’ capital:
 
 
 
Limited partners’ interest (69,317,278 units issued and outstanding as of March 31, 2014 and December 31, 2013)
975.7

 
1,079.6

General partner’s interest
34.6

 
36.6

Accumulated other comprehensive loss
(6.7
)
 
(53.4
)
Total partners’ capital
1,003.6

 
1,062.8

Total liabilities and partners’ capital
$
3,217.6

 
$
2,688.1

See accompanying notes to unaudited condensed consolidated financial statements.

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Table of Contents

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
 
 
Three Months Ended March 31,
 
2014
 
2013
 
(In millions, except per unit and unit data)
Sales
$
1,341.0

 
$
1,318.6

Cost of sales
1,216.2

 
1,184.2

Gross profit
124.8

 
134.4

Operating costs and expenses:
 
 
 
Selling
19.0

 
15.9

General and administrative
25.9

 
25.1

Transportation
40.4

 
35.4

Taxes other than income taxes
2.1

 
3.0

Other
2.1

 
0.6

Operating income
35.3

 
54.4

Other income (expense):
 
 
 
Interest expense
(26.2
)
 
(24.8
)
Debt extinguishment costs
(89.6
)
 
—

Realized gain (loss) on derivative instruments
6.6

 
(8.6
)
Unrealized gain on derivative instruments
24.6

 
24.5

Other
(0.3
)
 
0.7

Total other expense
(84.9
)
 
(8.2
)
Net income (loss) before income taxes
(49.6
)
 
46.2

Income tax expense
0.2

 
0.2

Net income (loss)
$
(49.8
)
 
$
46.0

Allocation of net income (loss):
 
 
 
Net income (loss)
$
(49.8
)
 
$
46.0

Less:
 
 
 
General partner’s interest in net income (loss)
(1.0
)
 
0.9

General partner’s incentive distribution rights
3.8

 
3.2

Non-vested share based payments
—

 
0.2

Net income (loss) available to limited partners
$
(52.6
)
 
$
41.7

Weighted average limited partner units outstanding:
 
 
 
Basic
69,622,884

 
62,831,155

Diluted
69,622,884

 
63,017,869

Limited partners’ interest basic net income (loss) per unit
$
(0.76
)
 
$
0.67

Limited partners’ interest diluted net income (loss) per unit
$
(0.76
)
 
$
0.66

Cash distributions declared per limited partner unit
$
0.685

 
$
0.65

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)
 
 
Three Months Ended March 31,
 
2014
 
2013
 
(In millions)
Net income (loss)
$
(49.8
)
 
$
46.0

Other comprehensive income (loss):
 
 
 
Cash flow hedges:
 
 
 
Cash flow hedge loss reclassified to net income (loss)
3.9

 
11.6

Change in fair value of cash flow hedges
42.4

 
(17.3
)
Defined benefit pension and retiree health benefit plans
0.2

 
0.6

Foreign currency translation adjustment
0.2

 
—

Total other comprehensive income (loss)
46.7

 
(5.1
)
Comprehensive income (loss) attributable to partners’ capital
$
(3.1
)
 
$
40.9

See accompanying notes to unaudited condensed consolidated financial statements.


6
Table of Contents

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
 
 
Accumulated Other
Comprehensive
Loss
 
Partners’ Capital
 
 
 
 
General
Partner
 
Limited
Partners
 
Total
 
(In millions)
Balance at December 31, 2013
$
(53.4
)
 
$
36.6

 
$
1,079.6

 
$
1,062.8

Other comprehensive income
46.7

 
—

 
—

 
46.7

Net income (loss)
—

 
2.8

 
(52.6
)
 
(49.8
)
Common units repurchased for phantom unit grants
—

 
—

 
(2.1
)
 
(2.1
)
Amortization of vested phantom units
—

 
—

 
0.6

 
0.6

Cash settlement of unit based compensation
—

 
—

 
(0.9
)
 
(0.9
)
Issuances of phantom units, net of taxes withheld
—

 
—

 
(1.2
)
 
(1.2
)
Distributions to partners
—

 
(4.8
)
 
(47.7
)
 
(52.5
)
Balance at March 31, 2014
$
(6.7
)
 
$
34.6

 
$
975.7

 
$
1,003.6

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
 
 
Three Months Ended March 31,
 
2014
 
2013
 
(In millions)
Operating activities
 
 
 
Net income (loss)
$
(49.8
)

$
46.0

Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
 
 
Depreciation and amortization
30.2


29.3

Amortization of turnaround costs
5.8


2.6

Non-cash interest expense
1.9


1.7

Non-cash debt extinguishment costs
18.7

 
—

Provision for doubtful accounts
0.6


0.3

Unrealized gain on derivative instruments
(24.6
)

(24.5
)
Non-cash equity based compensation
3.0


2.9

Other non-cash activities
1.1


0.6

Changes in assets and liabilities:
 
 
 
Accounts receivable
(54.1
)

(85.9
)
Inventories
(51.3
)

(51.4
)
Prepaid expenses and other current assets
2.6


(7.1
)
Derivative activity
1.5


(1.3
)
Turnaround costs
(3.0
)

(13.9
)
Deposits
3.2


5.4

Accounts payable
163.2


82.6

Accrued interest payable
(7.4
)

5.3

Accrued salaries, wages and benefits
0.3


(2.7
)
Accrued income taxes payable
—


(27.6
)
Other taxes payable
(1.7
)

(0.7
)
Other liabilities
(0.6
)

5.3

Pension and postretirement benefit obligations
—


(0.7
)
Net cash provided by (used in) operating activities
39.6

 
(33.8
)
Investing activities
 
 
 
Additions to property, plant and equipment
(46.3
)

(21.1
)
Cash paid for acquisitions, net of cash acquired
(247.0
)

(117.7
)
Investment in unconsolidated affiliates
(16.0
)

(9.2
)
Net cash used in investing activities
(309.3
)
 
(148.0
)
Financing activities
 
 
 
Proceeds from borrowings — revolving credit facility
6.5


607.8

Repayments of borrowings — revolving credit facility
(6.5
)

(578.6
)
Repayments of borrowings — senior notes
(500.0
)
 
—

Payments on capital lease obligations
(0.3
)

(0.2
)
Proceeds from other financing obligations
—

 
3.5

Proceeds from senior notes offering
900.0


—

Debt issuance costs
(15.9
)

—

Proceeds from public offering of common units, net
—


175.5

Contribution from Calumet GP, LLC
—


3.7

Common units repurchased for phantom unit grants
(2.1
)

(7.1
)
Cash settlement of unit based compensation
(0.9
)
 
—

Distributions to partners
(52.6
)

(44.5
)
Net cash provided by financing activities
328.2

 
160.1

Net increase (decrease) in cash and cash equivalents
58.5

 
(21.7
)
Cash and cash equivalents at beginning of period
121.1

 
32.2

Cash and cash equivalents at end of period
$
179.6

 
$
10.5

Supplemental disclosure of noncash financing and investing activities
 
 
 
Non-cash property, plant and equipment additions
$
16.4

 
$
—

See accompanying notes to unaudited condensed consolidated financial statements.


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Table of Contents

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


1. Description of the Business
Calumet Specialty Products Partners, L.P. (the “Company”) is a publicly traded Delaware limited partnership listed on the NASDAQ Global Select Market (“NASDAQ”) under the ticker symbol “CLMT.” The general partner of the Company is Calumet GP, LLC, a Delaware limited liability company. As of March 31, 2014, the Company had 69,317,278 limited partner common units and 1,414,638 general partner equivalent units outstanding. The general partner owns 2% of the Company and all of the incentive distribution rights (as defined in the Company’s partnership agreement), while the remaining 98% is owned by limited partners. The general partner employs all of the Company’s employees and the Company reimburses the general partner for certain of its expenses.

The Company is engaged in the production and marketing of crude oil-based specialty products including lubricating oils, white mineral oils, solvents, petrolatums, waxes, and fuel and fuel related products including gasoline, diesel, jet fuel, asphalt, heavy fuel oils and drilling fluids. The Company is also engaged in the resale of purchased crude oil to third party customers. The Company is based in Indianapolis, Indiana and has thirteen operating facilities primarily located in northwest Louisiana, northwest Wisconsin, northern Montana, western Pennsylvania, Texas, New Jersey and Oklahoma. The Company owns and leases additional facilities, primarily related to production and distribution of specialty and fuel products, throughout the United States (“U.S.”).
The unaudited condensed consolidated financial statements of the Company as of March 31, 2014 and for the three months ended March 31, 2014 and 2013 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 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 months ended March 31, 2014 are not necessarily indicative of the results that may be expected for the year ending December 31, 2014. These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s 2013 Annual Report.
2. New and Recently Adopted Accounting Pronouncements
In February 2013, the FASB issued ASU No. 2013-04, Liabilities (Topic 405) — Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation Is Fixed at the Reporting Date (“ASU 2013-04”). ASU 2013-04 provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements from which the total amount of the obligation within the scope of this guidance is fixed at the reporting date. ASU 2013-04 is effective for fiscal periods (including interim periods) beginning after December 15, 2013 and should be applied retrospectively. The adoption of ASU 2013-04 did not have an impact on the Company’s unaudited condensed consolidated financial statements.
3. Acquisitions
On March 31, 2014, the Company completed the acquisition of ADF Holdings, Inc., the parent company of Anchor Drilling Fluids USA, Inc., (“Anchor”) an independent provider and marketer of drilling fluids, completion fluids and production chemicals to the oil and gas industry (“Anchor Acquisition”). In connection with the Anchor Acquisition, the Company is required to pay 50% by which the amount of taxes paid in a post-closing tax period are reduced (or a refund is actually received or credited) as a result of the utilization of post-closing transaction tax deductions in the 2014 taxable year (but, for the avoidance of doubt, no other taxable year). Total consideration was approximately $236.6 million, net of cash acquired and subject to working capital and certain other adjustments including aforementioned tax adjustments. Anchor is a corporation and will be subject to federal and state income taxes in future reporting periods. Anchor designs, manufactures and packages drilling fluid products at its locations in Texas, Oklahoma, Louisiana, Arkansas, Colorado, Utah, Wyoming, Montana, New Mexico, New York, North Dakota, Pennsylvania and Ohio. The Anchor Acquisition was financed by using a portion of the net proceeds of $884.1 million from the Company’s March 2014 private placement of 6.50% senior notes due April 15, 2021. The Company believes the Anchor Acquisition increases its position in the specialty products market, expands its geographic reach and increases its asset diversity.

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Table of Contents

On February 28, 2014, the Company completed the acquisition of substantially all of the assets of United Petroleum, LLC, a marketer and distributor of high performance lubricants, for aggregate consideration of approximately $10.4 million, subject to certain purchase price adjustments (“United Petroleum Acquisition”). The United Petroleum Acquisition was financed with cash on hand. The Company believes the acquisition increases its position in the specialty lubricants market.
On December 10, 2013, the Company completed the acquisition of Bel-Ray Company, LLC, a manufacturer and global marketer of high-performance lubricants and greases, for aggregate consideration of approximately $53.6 million, net of cash acquired and excluding debt assumed (“Bel-Ray Acquisition”). Bel-Ray distributes, both domestically and internationally, a wide array of high-end specialty synthetic lubricants and greases which are used in the aerospace, automotive, energy, food, marine, military, mining, motorcycle, powersports, steel and textiles industries. The Bel-Ray Acquisition was financed by using a portion of the net proceeds of $337.4 million from the Company’s November 2013 private placement of 7.625% senior notes due January 15, 2022. The Company believes the Bel-Ray Acquisition increases its position in the specialty lubricants market, expands its geographic reach and increases its asset diversity. At closing, the Company repaid the $11.9 million of debt assumed in connection with the Bel-Ray Acquisition.
On August 9, 2013, the Company completed the acquisition of seven crude oil loading facilities and related assets in North Dakota and Montana from Murphy Oil USA, Inc. (“Murphy”) for aggregate consideration of approximately $6.2 million (“Crude Oil Logistics Acquisition”). The Crude Oil Logistics Acquisition was funded with cash on hand. As part of this acquisition, the Company assumed pipeline space on the Enbridge Pipeline System (“Enbridge Pipeline”) previously held by Murphy. The Company has the ability to transport crude oil directly from the point of lease, into the Company’s acquired crude oil loading facilities and then onto the Enbridge Pipeline where it can be routed to the Company’s refineries and/or third party customers. As part of this transaction, the Company and Murphy jointly consented to terminate an existing crude oil purchase agreement (“Murphy Crude Oil Supply Agreement”) wherein Murphy supplied the Company’s Superior refinery with up to 10,000 barrels per day of crude oil. The Company believes this acquisition expands its growing portfolio of crude oil logistics assets, while positioning the Company to purchase increased volumes of price-advantaged feedstock directly from the producers that operate in the major shale oil plays encompassing certain of the Company’s refineries.
On January 2, 2013, the Company completed the acquisition of NuStar Energy L.P.’s (“NuStar”) San Antonio, Texas refinery, together with related assets and the assumption of certain liabilities and obligations (“San Antonio Acquisition”). Total consideration for the San Antonio Acquisition was approximately $117.9 million, net of cash acquired. The refinery has total crude oil throughput capacity of 17,500 bpd and primarily produces diesel, jet fuel, gasoline, other fuel products and specialty solvents. The San Antonio Acquisition was funded with borrowings under the Company’s revolving credit facility with the balance through cash on hand. The Company believes the San Antonio Acquisition further diversifies the Company’s crude oil feedstock slate, operating asset base and geographic presence.
Purchase Price Allocation
The Anchor and United Petroleum Acquisitions purchase price allocations have not yet been finalized due to the timing of the closing of the acquisitions. The final determination of fair value for assets and liabilities will be completed as soon as the information necessary to complete the analysis is obtained. The assets and results of the operations from such assets acquired as a result of the San Antonio and Crude Oil Logistics Acquisitions have been included in the fuel products segments since their dates of acquisition, January 2, 2013 and August 9, 2013, respectively. The assets and results of operations from such assets acquired as a result of the Bel-Ray, United Petroleum and Anchor Acquisitions have been included in the specialty products segment since their dates of acquisition, December 10, 2013, February 28, 2014 and March 31, 2014, respectively.
The allocations of the aggregate purchase prices to assets acquired and liabilities assumed for acquisitions are as follows (in millions):

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Table of Contents

 
2014 Acquisitions
 
2013 Acquisitions
 
Anchor
 
United Petroleum
 
Bel-Ray
 
Crude Oil Logistics
 
San Antonio
Accounts receivable
$
77.7

 
$
—

 
$
4.3

 
$
—

 
$
—

Inventories
57.0

 
0.2

 
11.1

 
—

 
17.0

Prepaid expenses and other current assets
0.4

 
—

 
0.6

 
0.1

 
—

Property, plant and equipment, net
35.0

 
—

 
6.5

 
0.9

 
100.7

Investment in unconsolidated affiliates
2.5

 
—

 
—

 
—

 
—

Goodwill
60.4

 
5.1

 
9.1

 
5.2

 
5.7

Other intangible assets, net
74.0

 
5.1

 
41.4

 
—

 
—

Other noncurrent assets, net
0.5

 
—

 
0.3

 
—

 
—

Accounts payable
(43.9
)
 
—

 
(3.9
)
 
—

 
—

Accrued salaries, wages and benefits
(0.3
)
 
—

 
(1.3
)
 
—

 
(0.1
)
Other taxes payable
(1.2
)
 
—

 
(1.7
)
 
—

 
—

Other current liabilities
(0.2
)
 
—

 
(0.8
)
 
—

 
(5.4
)
Current portion of long-term debt
—

 
—

 
(11.9
)
 
—

 
—

Deferred income tax liability
(25.3
)
 
—

 
—

 
—

 
—

Other long-term liabilities
—

 
—

 
(0.1
)
 
—

 
—

Total purchase price, net of cash acquired
$
236.6

 
$
10.4

 
$
53.6

 
$
6.2

 
$
117.9

Intangible Assets
The components of intangible assets listed in the table above, based upon preliminary third party appraisals, were as follows (in millions):
 
Anchor
 
United Petroleum
 
Bel-Ray
 
March 31, 2014
 
February 28, 2014
 
December 10, 2013
 
Amount

Life (Years)
 
Amount
 
Life (Years)
 
Amount
 
Life (Years)
Customer relationships
$
54.4


20

 
$
5.1

 
20

 
$
28.6

 
30
Tradenames
17.9


21

 
—

 
—

 
4.2

 
18
Trade secrets
—


—

 
—

 
—

 
8.5

 
18
Non-competition agreements
1.7


4

 
—

 
—

 
0.1

 
6
Totals
$
74.0




 
$
5.1

 
 
 
$
41.4

 
 
Weighted average amortization period


20

 
 
 
20

 
 
 
26

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Goodwill
The Company recorded the following goodwill (in millions):
 
Amount
 
Business Segment
Anchor Acquisition (1) (3)
$
60.4

 
Specialty Products
United Petroleum Acquisition (1)
$
5.1

 
Specialty Products
Bel-Ray Acquisition (1)
$
9.1

 
Specialty Products
Crude Oil Logistics Acquisition (2)
$
5.2

 
Fuel Products
San Antonio Acquisition (1)
$
5.7

 
Fuel Products
 
(1) 
Goodwill recognized relates primarily to enhancing the Company’s strategic platform for expansion in the respective business segment noted above.
(2) 
Goodwill recognized relates primarily to enhancing the Company’s crude oil gathering operations to support the Superior refinery.
(3) 
Goodwill associated with the Anchor Acquisition is not tax deductible.
Acquisition Expenses
In connection with the respective acquisitions, the Company incurred the following expenses, which are reflected in general and administrative expenses in the unaudited condensed consolidated statements of operations for the three months ended March 31, 2014 and 2013 (in millions):
 
Three Months Ended March 31,
 
2014
 
2013
Anchor Acquisition
$
0.2

 
$
—

United Petroleum Acquisition
$
0.1

 
$
—

Bel-Ray Acquisition
$
0.2

 
$
—

Crude Oil Logistics Acquisition
$
—

 
$
—

San Antonio Acquisition
$
—

 
$
0.4

Unaudited Pro Forma Financial Information
Due to the timing of the Anchor Acquisition, the Company has not yet completed its initial accounting and analysis. Therefore, it is impractical to provide pro forma information at this time. The Company will file pro forma financial statements on Form 8-K/A within 75 days of the acquisition date of March 31, 2014 in accordance with Rule 3-05 of Regulation S-X.

4. Inventories
The cost of inventory is recorded using the last-in, first-out (LIFO) method. 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. The replacement cost of these inventories, based on current market values, would have been $69.3 million and $32.2 million higher as of March 31, 2014 and December 31, 2013, respectively.
Inventories consist of the following (in millions):
 
 
March 31, 2014
 
December 31, 2013
Raw materials
$
121.3

 
$
122.7

Work in process
126.5

 
102.6

Finished goods
428.1

 
342.1

 
$
675.9

 
$
567.4


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Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs.

5. Investment in Unconsolidated Affiliates
On February 7, 2013, the Company entered into a joint venture agreement with MDU Resources Group, Inc. (“MDU”) to develop, build and operate a diesel refinery in southwestern North Dakota. The joint venture is named Dakota Prairie Refining, LLC. The refinery’s total construction cost is estimated at approximately $300.0 million. The capitalization of the joint venture is expected to be funded through contributions of $150.0 million from MDU and a total of $150.0 million from the Company comprised of $75.0 million through contributions and proceeds of $75.0 million from an unsecured syndicated term loan facility with the joint venture as the borrower which is expected to be repaid by the Company through its allocation of profits from the joint venture. The term loan facility was funded in April 2013. Funding for the project will occur over the course of the construction period, with the majority of the direct funding by the Company expected to occur in 2014. The joint venture will allocate profits on a 50%/50% basis to the Company and MDU. The joint venture is governed by a board of managers comprised of representatives from both the Company and MDU. MDU will provide a portion of the crude oil supply to the refinery, as well as natural gas and electricity utility services. The Company is providing refinery operations, crude oil procurement and refined product marketing expertise to the joint venture.
The Company accounts for its ownership in its joint venture under the equity method of accounting. As of March 31, 2014 and December 31, 2013, the Company has an investment of $49.2 million and $33.4 million, respectively, in Dakota Prairie Refining, LLC primarily related to the development of the refinery.
6. Goodwill and Other Intangible Assets
Changes in goodwill balances are as follows (in millions):
 
March 31, 2014
 
December 31, 2013
 
Specialty
 
Fuel
 
 
 
Specialty
 
Fuel
 
 
 
Products
 
Products
 
Total
 
Products
 
Products
 
Total
Beginning balance:
$
168.5

 
$
38.5

 
$
207.0

 
$
159.4

 
$
27.6

 
$
187.0

Acquisitions
65.5

 
—

 
65.5

 
9.1

 
10.9

 
20.0

Accumulated impairment losses
—

 
—

 
—

 
—

 
—

 
—

Ending balance:
$
234.0

 
$
38.5

 
$
272.5

 
$
168.5

 
$
38.5

 
$
207.0

Other intangible assets consist of the following (in millions):
 
Weighted Average Life(Years) 
 
March 31, 2014
 
December 31, 2013
 
 
Gross Amount
 
Accumulated Amortization 
 
Gross Amount 
 
Accumulated Amortization 
Customer relationships
21
 
$
242.4

 
$
(45.4
)
 
$
182.9

 
$
(40.3
)
Supplier agreements
4
 
21.5

 
(21.5
)
 
21.5

 
(21.5
)
Tradenames
Indefinite
 
14.8

 
—

 
14.8

 
—

Tradenames
18
 
28.5

 
(2.0
)
 
10.6

 
(1.6
)
Trade secrets
13
 
52.7

 
(11.4
)
 
52.7

 
(9.6
)
Patents
12
 
1.6

 
(1.3
)
 
1.6

 
(1.2
)
Non-competition agreements
5
 
7.6

 
(5.8
)
 
5.9

 
(5.8
)
Distributor agreements
3
 
2.0

 
(2.0
)
 
2.0

 
(2.0
)
Royalty agreements
19
 
4.5

 
(1.6
)
 
4.5

 
(1.6
)
 
18
 
$
375.6

 
$
(91.0
)
 
$
296.5

 
$
(83.6
)
Supplier agreements, tradenames (other than indefinite lived), trade secrets, patents, non-competition agreements, distributor agreements and royalty agreements are being amortized to properly match expense with the discounted estimated future cash flows over the terms of the related agreements. Agreements with terms allowing for the potential extension of such agreements are being amortized based on the initial term only. Customer relationships are being amortized using discounted estimated future cash flows based upon assumed rates of annual customer attrition. For the three months ended March 31, 2014 and 2013, the Company recorded amortization expense of intangible assets of $7.4 million and $6.3 million, respectively.

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As of March 31, 2014, the Company estimates that amortization of intangible assets for the next five years will be as follows (in millions):
Year

Amortization Amount
2014

$
25.7

2015

$
40.8

2016

$
35.6

2017

$
30.7

2018

$
25.5


7. 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 EPA, various state environmental regulatory bodies, 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, blending and terminal operations, which are subject to stringent federal, state, regional and local laws and regulations governing worker health and safety, the discharge of materials into the environment and environmental protection. These laws and regulations impose obligations that are applicable to the Company’s operations, such as requiring the acquisition of permits to conduct regulated activities, restricting the manner in which the Company may release materials into the environment, requiring remedial activities or capital expenditures to mitigate pollution from former or current operations, requiring the application of specific health and safety criteria addressing worker protection and imposing substantial liabilities for pollution resulting from its operations. Certain of these laws impose joint and several, strict liability for costs required to remediate and restore sites where petroleum hydrocarbons, wastes or other materials have been released or disposed.
In addition, new laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement or other developments could require the Company to make additional unforeseen expenditures. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. For example, on September 12, 2012, the EPA published 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 its refinery operations.
Voluntary remediation of subsurface contamination is in process at certain of the Company’s refinery sites. The remedial projects are being overseen by the appropriate state agencies. Based on current investigative and remedial activities, the Company believes that the groundwater contamination at these refineries can be controlled or remedied without having a material adverse effect on the Company’s financial condition. However, such costs are often unpredictable and, therefore, there can be no assurance that the future costs will not become material.
San Antonio Refinery
In connection with the San Antonio Acquisition (see Note 3), the Company agreed to indemnify NuStar for an unlimited term and without consideration of a monetary cap from any environmental liabilities associated with the San Antonio refinery, except for any governmental penalties or fines that may result from NuStar’s actions or inactions during NuStar’s 20 month period of ownership of the San Antonio refinery. Anadarko Petroleum Corporation (“Anadarko”) and Age Refining, Inc. (“Age Refining”), a third party that has since entered bankruptcy, are subject to a 1995 Agreed Order from the Texas Natural Resource Conservation Commission, now known as the Texas Commission on Environmental Quality (“TCEQ”), pursuant to which Anadarko and Age Refining are obligated to assess and remediate certain contamination at the San Antonio refinery that pre-dates the Company’s acquisition of the facility. The Company is not a party to this Agreed Order. The Company is in discussions with both TCEQ and Anadarko over how best to address this pre-existing contamination at the San Antonio refinery.


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Montana Refinery
In connection with the acquisition of the Montana refinery from Connacher Oil and Gas Limited (“Connacher”), the Company became a party to an existing 2002 Refinery Initiative consent decree (“Montana Consent Decree”) with the EPA and the Montana Department of Environmental Quality (“MDEQ”). The material obligations imposed by the Montana Consent Decree have been completed. Periodic reporting is the primary current obligation under the Montana Consent Decree. On September 27, 2012, Montana Refining Company, Inc. received a final Corrective Action Order on Consent, replacing the refinery’s previous hazardous waste permit. This Corrective Action Order on Consent governs the investigation and remediation of contamination at the Montana refinery. The Company believes the majority of damages related to such contamination at the Montana refinery are covered by a contractual indemnity provided by HollyFrontier Corporation (“Holly”), the owner and operator of the Montana refinery prior to its acquisition by Connacher, under an asset purchase agreement between Holly and Connacher, pursuant to which Connacher acquired the Montana refinery. Under this asset purchase agreement, Holly agreed to indemnify Connacher and Montana Refining Company, Inc., subject to a 5-year time limit following closing and certain monetary baskets and cap, for environmental conditions arising under Holly’s ownership and operation of the Montana refinery and existing as of the date of sale to Connacher. The Company expects that it may incur some expenses to remediate environmental conditions at the Montana refinery in connection with the expansion of that refinery; however, the Company believes at this time that the costs it may incur will not be material.
Superior Refinery
In connection with the Superior acquisition, the Company became a party to an existing Refinery Initiative consent decree (“Superior Consent Decree”) with the EPA and the Wisconsin Department of Natural Resources (“WDNR”) that applies, in part, to its Superior refinery. Under the Superior Consent Decree, the Company must complete certain reductions in air emissions at the Superior refinery as well as report upon certain emissions from the refinery to the EPA and the WDNR. The Company currently estimates costs of up to $1.0 million to make known equipment upgrades and conduct other discrete tasks in compliance with the Superior Consent Decree. Failure to perform required tasks under the Superior Consent Decree could result in the imposition of stipulated penalties, which could be material. In addition, the Company may have to pursue certain additional environmental and safety-related projects at the Superior refinery. Completion of these additional projects will result in the Company incurring additional costs, which could be substantial. For the three months ended March 31, 2014 and 2013, the Company incurred approximately $0.4 million and $0.1 million, respectively, of costs related to installing process equipment pursuant to the EPA fuel content regulations.
On June 29, 2012, the EPA issued a Finding of Violation/Notice of Violation to the Superior refinery, which included a proposed penalty amount of $0.1 million. This finding is in response to information provided to the EPA by the Company in response to an information request. The EPA alleges that the efficiency of the flares at the Superior refinery is lower than regulatory requirements. The Company is contesting the allegations and attended an informal conference with the EPA held September 12, 2012. The Company does not believe that the resolution of these allegations will have a material adverse effect on the Company’s financial results or operations.
The Company is contractually indemnified by Murphy Oil Corporation (“Murphy Oil”) under an asset purchase agreement between the Company and Murphy Oil for specified environmental liabilities arising from the operation of the Superior refinery including: (i) certain obligations arising out of the Superior Consent Decree (including payment of a civil penalty required under the Superior Consent Decree), (ii) certain liabilities arising in connection with Murphy Oil’s transport of certain wastes and other materials to specified offsite real properties for disposal or recycling prior to the Superior Acquisition and (iii) certain liabilities for certain third party actions, suits or proceedings alleging exposure, prior to the Superior Acquisition, of an individual to wastes or other materials at the specified on-site real property, which wastes or other materials were spilled, released, emitted or otherwise discharged by Murphy Oil. The Company believes contractual indemnity by Murphy Oil for such specified environmental liabilities is unlimited in duration and not subject to any monetary deductibles or maximums. The amount of any damages payable by Murphy Oil pursuant to the contractual indemnities under the asset purchase agreement are net of any amount recoverable under an environmental insurance policy that the Company obtained in connection with the Superior Acquisition, which named the Company and Murphy Oil as insureds and covers environmental conditions existing at the Superior refinery prior to the Superior Acquisition.
Shreveport, Cotton Valley and Princeton Refineries
On December 23, 2010, the Company entered into a settlement agreement with the Louisiana Department of Environmental Quality (“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 that arose prior to December 31, 2010. Among other things, the Company agreed to complete beneficial environmental programs and implement emissions reduction projects at the Company’s Shreveport, Cotton Valley

15
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and Princeton refineries on an agreed-upon schedule. During the three months ended March 31, 2014 and 2013, the Company incurred approximately $0.1 million and $2.2 million, respectively, of such expenditures and estimates additional expenditures of approximately $6.0 million to $8.0 million of capital expenditures and expenditures related to additional personnel and environmental studies over the next two years as a result of the implementation of these requirements. 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 Company is contractually indemnified by Shell Oil Company (“Shell”), as successor to Pennzoil-Quaker State Company and Atlas Processing Company, under an asset purchase agreement between the Company and Shell, for specified environmental liabilities arising from the operations of the Shreveport refinery prior to the Company’s acquisition of the facility. The contractual indemnity is believed by the Company to be unlimited in amount and duration, but requires the Company to contribute up to $1.0 million of the first $5.0 million of indemnified costs for certain of the specified environmental liabilities.
Current and former owners of a property in Bossier Parish, Louisiana, filed a lawsuit in March 2006 against the Company and other defendants, including Chevron USA, Inc. (“Chevron”), Legacy Resources Co., L.P. (“Legacy”) and Exxon Mobil Corporation (“Exxon Mobil”), alleging damage from salt water and other environmental contamination on the property arising from historical oil field production on the property. Oil field exploration and production on the property began in the 1920’s by predecessors of Exxon Mobil. The Company received an assignment of certain mineral leases for portions of the property in 1993 from an affiliate of Texaco, prior to Texaco’s merger with Chevron. The Company then assigned those mineral leases to Legacy. The mineral lease assignments include indemnity provisions obligating the assignees to provide certain indemnities for an unlimited term and without consideration of a monetary cap for the benefit of the assignors. The Company, Chevron, Legacy and the plaintiffs are participating in mediation in an attempt to settle the litigation. The Company believes any obligation will be covered under the indemnification.
Bel-Ray Facility
Bel-Ray executed an Administrative Consent Order (“ACO”) with the New Jersey Department of Environmental Protection, effective January 4, 1994, which required investigation and remediation of contamination at or emanating from the Bel-Ray facility. In 2000, Bel-Ray entered into a fixed price remediation contract with Weston Solutions (“Weston”) (a large remediation contractor) whereby Weston agreed to be fully liable for the remediation of the soil and groundwater issues at the facility, including an offsite groundwater plume pursuant to the ACO (“Weston Agreement”). The Weston Agreement set up a trust fund to reimburse Weston, administered by Bel-Ray’s environmental counsel. As of March 31, 2014, the trust fund contained approximately $0.7 million. In addition, there is remediation cost containment insurance, should Weston be unable to complete the work required under the Weston Agreement. In connection with the Bel-Ray Acquisition, the Company became a party to the Weston Agreement.
Weston has been addressing the environmental issues at the Bel-Ray facility over time, and the next phase will address the groundwater issues, which extend offsite.
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 conducts periodic audits of Process Safety Management (“PSM”) systems at each of its locations subject to the PSM standard. The Company’s compliance with applicable health and safety laws and regulations has required, and continues to require, substantial expenditures. Changes in occupational safety and health laws and regulations or a finding of non-compliance with current laws and regulations could result in additional capital expenditures or operating expenses, as well as civil penalties and, in the event of a serious injury or fatality, criminal charges.
The Company has completed studies to assess the adequacy of its PSM practices at its Shreveport refinery with respect to certain consensus codes and standards. During the three months ended March 31, 2014 and 2013, the Company incurred approximately $0.2 million and $0.1 million, respectively, of related capital expenditures and expects to incur up to $1.0 million during 2014 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.

16
Table of Contents

In the first quarter of 2011, OSHA conducted an inspection of the Cotton Valley refinery’s PSM program under this OSHA initiative. On March 14, 2011, OSHA issued a Citation and Notification of Penalty (the “Cotton Valley Citation”) to the Company as a result of the Cotton Valley inspection, which included a proposed penalty amount of $0.2 million. The Company has contested the Cotton Valley Citation and has reached a tentative settlement with OSHA on the matter, which the Company does not believe will have a material adverse effect on its results of operations or financial condition.
Labor Matters
The Company has employees covered by various collective bargaining agreements. The Missouri collective bargaining agreement was ratified on February 21, 2014 and will expire on April 30, 2015.
Standby Letters of Credit
The Company has agreements with various financial institutions for standby letters of credit which have been issued to vendors. As of March 31, 2014 and December 31, 2013, the Company had outstanding standby letters of credit of $171.8 million and $95.2 million, respectively, under its senior secured revolving credit facility (the “revolving credit facility”). Refer to Note 8 for additional information regarding the Company’s revolving credit facility. The maximum amount of letters of credit the Company could issue at March 31, 2014 and December 31, 2013 under its revolving credit facility is subject to borrowing base limitations, with a maximum letter of credit sublimit equal to $680.0 million, which is the greater of (i) $400.0 million and (ii) 80% of revolver commitments in effect ($850.0 million at March 31, 2014 and December 31, 2013).
As of March 31, 2014 and December 31, 2013, the Company had availability to issue letters of credit of $533.6 million and $472.4 million, respectively, under its revolving credit facility.

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8. Long-Term Debt
Long-term debt consisted of the following (in millions):
 
March 31,
2014
 
December 31,
2013
Borrowings under amended and restated senior secured revolving credit agreement with third-party lenders, interest payments monthly, borrowings due June 2016
$
—

 
$
—

Borrowings under 2019 Notes, interest at a fixed rate of 9.375%, interest payments semiannually, borrowings due May 2019, effective interest rate of 10.0% for the three months ended March 31, 2014
—

 
500.0

Borrowings under 2020 Notes, interest at a fixed rate of 9.625%, interest payments semiannually, borrowings due August 2020, effective interest rate of 10.1% for the three months ended March 31, 2014
275.0

 
275.0

Borrowings under 2021 Notes, interest at a fixed rate of 6.50%, interest payments semiannually, borrowings due April 2021, effective interest rate of 6.50% for the three months ended March, 31, 2014
900.0


—

Borrowings under 2022 Notes, interest at a fixed rate of 7.625%, interest payments semiannually, borrowings due January 2022, effective interest rate of 7.9% for the three months ended March, 31, 2014 (1)
348.4

 
350.0

Capital lease obligations, at various interest rates, interest and principal payments monthly through January 2027
4.6

 
4.8

Less unamortized discounts
(9.2
)
 
(19.0
)
Total long-term debt
1,518.8

 
1,110.8

Less current portion of long-term debt
0.4

 
0.4

 
$
1,518.4

 
$
1,110.4

 
(1) 
The balance includes a fair value interest rate hedge adjustment, which decreased the debt balance by $1.6 million as of March 31, 2014 (refer to Note 9 for additional information on the interest rate swap designated as a fair value hedge).
Senior Notes
6.50% Senior Notes (the “2021 Notes”)
On March 31, 2014, the Company issued and sold $900.0 million in aggregate principal amount of 6.50% senior notes due April 15, 2021 at par. The Company received net proceeds of $884.1 million net of initial purchasers’ fees and expenses, which the Company used to fund the purchase price of the Anchor Acquisition (refer to Note 3 for additional information), the redemption of $500.0 million in aggregate principal amount outstanding of 2019 Notes (defined below) and for general partnership purposes, including planned capital expenditures at the Company’s facilities. Interest on the 2021 Notes is paid semiannually in arrears on April 15 and October 15 of each year, beginning on October 15, 2014.
At any time prior to April 15, 2017, the Company may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2021 Notes with the net proceeds of a public or private equity offering at a redemption price of 106.5% 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 2021 Notes issued remains outstanding immediately after the occurrence of such redemption and (2) the redemption occurs within 180 days of the date of the closing of such public or private equity offering.
On and after April 15, 2017, the Company may on any one or more occasions redeem all or a part of the 2021 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 2021 Notes, if redeemed during the twelve-month period beginning on April 15 of the years indicated below: 
Year
 
Percentage
2017
 
103.250
%
2018
 
101.625
%
2019 and thereafter
 
100.000
%
Prior to April 15, 2017, the Company may on any one or more occasions redeem all or part of the 2021 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 2021 Notes) at the redemption date, plus any accrued and unpaid interest to the applicable redemption date.

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7.625% Senior Notes (the “2022 Notes”)
On November 26, 2013, the Company issued and sold $350.0 million in aggregate principal amount of 7.625% senior notes due January 15, 2022 at a discounted price of 98.494 percent of par. The Company received net proceeds of $337.4 million, net of discount, initial purchasers’ fees and expenses, which the Company used to fund the purchase price of the Bel-Ray Acquisition, the redemption of $100.0 million in aggregate principal amount outstanding of 2019 Notes (defined below) and for general partnership purposes, including planned capital expenditures at the Company’s facilities.
9.625% Senior Notes (the “2020 Notes”)
On June 29, 2012, in connection with the Royal Purple Acquisition, the Company issued and sold $275.0 million in aggregate principal amount of 9.625% senior notes due August 1, 2020 at a discounted price of 98.25 percent of par. The Company received net proceeds of $262.5 million, net of discount, initial purchasers’ fees and expenses, which the Company used to fund a portion of the purchase price of the Royal Purple Acquisition.
9.375% Senior Notes (the “2019 Notes”)
On April 21, 2011, in connection with the restructuring of the majority of its outstanding long-term debt, the Company issued and sold $400.0 million in aggregate principal amount of 9.375% senior notes due May 1, 2019 (the “2019 Notes issued in April 2011”) at par. The Company received net proceeds of $389.0 million net of initial purchasers’ 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 acquisition of the Superior refinery, the Company issued and sold $200.0 million in aggregate principal amount of 9.375% senior notes due May 1, 2019 (the “2019 Notes issued in September 2011”) at a discounted price of 93.0 percent of par. The Company received net proceeds of $180.3 million net of discount, initial purchasers’ fees and expenses, which the Company used to fund a portion of the purchase price of the Superior refinery. 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.”
On March 31, 2014, the Company redeemed approximately $326.0 million and $174.0 million in aggregate principal amount outstanding of the remaining 2019 issued in April 2011 and 2019 Notes issued in September 2011, respectively, with the net proceeds from the issuance of the 2021 Notes at a redemption price of $570.9 million. In conjunction with the early redemption, the Company recognized a loss of $89.6 million recorded in debt extinguishment costs in the unaudited condensed consolidated statements of operations for the three months ended March 31, 2014.
The 2020, 2021 and 2022 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 the Company’s immaterial subsidiaries and Calumet Finance Corp. (100%-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, 2021 and 2022 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 2020, 2021 and 2022 Notes. Since all Company’s operating subsidiaries, with the exception of the Company’s immaterial subsidiaries and Calumet Finance Corp., guarantee the 2020, 2021 and 2022 Notes, condensed consolidating financial statements of non-guarantors are not required in accordance with Rule 3-10 of Regulation S-X.
The indentures governing the 2020, 2021 and 2022 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 2020, 2021 and 2022 Notes are rated investment grade by either Moody’s Investors Service, Inc. (“Moody’s”) or Standard & Poor’s Ratings Services (“S&P”) and no Default or Event of Default, each as defined in the indentures governing the 2020, 2021 and 2022 Notes, has occurred and is continuing, many of these covenants will be suspended, except in the case of the 2020 Notes, an investment grade rating is required from both Moody’s and S&P. As of March 31, 2014, the Company’s Fixed Charge Coverage Ratio (as defined in the indentures governing the 2020, 2021 and 2022 Notes) was 2.3 to 1.0.

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Amended and Restated Senior Secured Revolving Credit Facility
The Company has an $850.0 million senior secured revolving credit facility, which is its primary source of liquidity for cash needs in excess of cash generated from operations. The revolving credit facility matures in June 2016 and currently bears interest at a rate equal to prime plus a basis points margin or LIBOR plus a basis points margin, at the Company’s option. As of March 31, 2014, the margin was 100 basis points for prime and 225 basis points for LIBOR; however, the margin can fluctuate quarterly based on the Company’s average availability for additional borrowings under the revolving credit facility in the preceding calendar quarter.
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% or 0.50% per annum depending on the average daily available unused borrowing capacity for the preceding month. The Company also pays a customary letter of credit fee, including a fronting fee of 0.125% of the stated amount of each outstanding letter of credit, and customary agency fees.
The borrowing capacity at March 31, 2014 under the revolving credit facility was $705.4 million. As of March 31, 2014, the Company had no outstanding borrowings under the revolving credit facility and outstanding standby letters of credit of $171.8 million, leaving $533.6 million 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) $46.4 million, (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.
As of March 31, 2014, the Company was in compliance with all covenants under the revolving credit facility.
Maturities of Long-Term Debt
As of March 31, 2014, principal payments on debt obligations and future minimum rentals on capital lease obligations are as follows (in millions):
Year
Maturity
2014
$
0.3

2015
0.3

2016
0.3

2017
0.4

2018
0.4

Thereafter
1,527.9

Total
$
1,529.6

9. Derivatives
The Company is exposed to price risks due to fluctuations in the price of crude oil, refined products (primarily in the Company’s fuel products segment) and natural gas. The Company uses various strategies to reduce its exposure to commodity price risk. The strategies to reduce the Company’s risk utilize both physical forward contracts and financially settled derivative instruments, such as swaps, collars and options, to attempt to reduce the Company’s exposure with respect to:
•
crude oil purchases and sales;
•
fuel product sales and purchases;
•
natural gas purchases; and

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•
fluctuations in the value of crude oil between geographic regions and between the different types of crude oil such as NYMEX WTI, Light Louisiana Sweet (“LLS”), Western Canadian Select (“WCS”), Mixed Sweet Blend (“MSW”) and ICE Brent (“Brent”).
The Company uses various strategies to reduce its exposure to interest rate risk, including the use of financially settled derivative instruments, such as interest rate swaps and options, to minimize significant unplanned fluctuations in earnings that are caused by interest rate volatility. The Company’s goal is to manage interest rate sensitivity by modifying the pricing characteristics of certain balance sheet liabilities so that earnings are not adversely affected by movement in interest rates.
The Company does not attempt to eliminate all of the Company’s risk as the costs of such actions are believed to be too high in relation to the risk posed to the Company’s future cash flows, earnings and liquidity. The Company does not hold or issue derivative instruments for trading purposes.
The Company recognizes all derivative instruments at their fair values (see Note 10) as either current assets or current liabilities in 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 following tables summarize the Company’s gross fair values of its derivative instruments, presenting the impact of offsetting derivative assets in the Company’s condensed consolidated balance sheets as of March 31, 2014 and December 31, 2013 (in millions):
 
 
March 31, 2014
 
December 31, 2013
 
 
Gross Amounts of Recognized Assets
 
Gross Amounts Offset in the Condensed Consolidated Balance Sheets
 
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets
 
Gross Amounts of Recognized Assets
 
Gross Amounts Offset in the Condensed Consolidated Balance Sheets
 
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets
 
 
 
Derivative instruments designated as hedges:
 
 
 
 
 
 
 
 
 
 
Fuel products segment:
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil swaps
 
$
57.4

 
$
(19.5
)
 
$
37.9

 
$
45.4

 
$
(45.4
)
 
$
—

Gasoline swaps
 
0.7

 
(8.9
)
 
(8.2
)
 
1.0

 
(1.0
)
 
—

Diesel swaps
 
4.1

 
(19.0
)
 
(14.9
)
 
3.5

 
(3.5
)
 
—

Jet fuel swaps
 
0.5

 
(1.6
)
 
(1.1
)
 
0.1

 
(0.1
)
 
—

Swaps not allocated to a specific segment:
 
 
 
 
 
 
 
 
 
 
Interest rate swap
 
—

 
—

 
—

 
—

 
—

 
—

Total derivative instruments designated as hedges
 
62.7

 
(49.0
)
 
13.7

 
50.0

 
(50.0
)
 
—

Derivative instruments not designated as hedges:
 
 
 
 
 
 
 
 
 
 
Fuel products segment:
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil swaps
 
8.7

 
(3.0
)
 
5.7

 
6.3

 
(6.3
)
 
—

Crude oil basis swaps
 
1.8

 
(0.7
)
 
1.1

 
1.0

 
(1.0
)
 
—

Gasoline swaps
 
0.1

 
(4.5
)
 
(4.4
)
 
—

 
—

 
—

Diesel swaps
 
1.8

 
(1.9
)
 
(0.1
)
 
0.7

 
(0.7
)
 
—

Jet fuel swaps
 
—

 
—

 
—

 
0.9

 
(0.9
)
 
—

Diesel crack spread collars
 
1.0

 
(0.5
)
 
0.5

 
0.3

 
(0.3
)
 
—

Gasoline crack spread collars
 
0.7

 
—

 
0.7

 
—

 
—

 
—

Specialty products segment:
 
 
 
 
 

 
 
 
 
 
 
Natural gas swaps
 
1.2

 
(1.2
)
 
—

 
0.4

 
(0.4
)
 
—

Total derivative instruments not designated as hedges
 
15.3

 
(11.8
)
 
3.5

 
9.6

 
(9.6
)
 
—

Total derivative instruments
 
$
78.0

 
$
(60.8
)
 
$
17.2

 
$
59.6

 
$
(59.6
)
 
$
—


21
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The following tables summarize the Company’s gross fair values of its derivative instruments, presenting the impact of offsetting derivative liabilities in the Company’s condensed consolidated balance sheets as of March 31, 2014 and December 31, 2013 (in millions):
 
 
March 31, 2014
 
December 31, 2013
 
 
Gross Amounts of Recognized Liabilities
 
Gross Amounts Offset in the Condensed Consolidated Balance Sheets
 
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets
 
Gross Amounts of Recognized Liabilities
 
Gross Amounts Offset in the Condensed Consolidated Balance Sheets
 
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets
 
 
 
Derivative instruments designated as hedges:
 
 
 
 
 
 
 
 
 
 
Fuel products segment:
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil swaps
 
$
(6.4
)
 
$
19.5

 
$
13.1

 
$
(13.0
)
 
$
45.4

 
$
32.4

Gasoline swaps
 
(15.5
)
 
8.9

 
(6.6
)
 
(19.7
)
 
1.0

 
(18.7
)
Diesel swaps
 
(24.4
)
 
19.0

 
(5.4
)
 
(51.3
)
 
3.5

 
(47.8
)
Jet fuel swaps
 
(5.8
)
 
1.6

 
(4.2
)
 
(13.4
)
 
0.1

 
(13.3
)
Swaps not allocated to a specific segment:
 
 
 
 
 
 
 
 
 
 
Interest rate swap
 
(1.6
)
 
—

 
(1.6
)
 
—

 
—

 
—

Total derivative instruments designated as hedges
(53.7
)
 
49.0

 
(4.7
)
 
(97.4
)
 
50.0

 
(47.4
)
Derivative instruments not designated as hedges:
 
 
 
 
 
 
 
 
 
 
Fuel products segment:
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil swaps
 
(0.6
)
 
3.0

 
2.4

 
(1.7
)
 
6.3

 
4.6

Crude oil basis swaps
 
—

 
0.7

 
0.7

 
(0.6
)
 
1.0

 
0.4

Gasoline swaps
 
(7.0
)
 
4.5

 
(2.5
)
 
(9.4
)
 
—

 
(9.4
)
Diesel swaps
 
(1.7
)
 
1.9

 
0.2

 
(3.5
)
 
0.7

 
(2.8
)
Jet fuel swaps
 
—

 
—

 
—

 
—

 
0.9

 
0.9

Diesel crack spread collars
 
(0.5
)
 
0.5

 
—

 
(0.2
)
 
0.3

 
0.1

Specialty products segment:
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas swaps
 
(1.5
)
 
1.2

 
(0.3
)
 
(1.6
)
 
0.4

 
(1.2
)
Total derivative instruments not designated as hedges
(11.3
)
 
11.8

 
0.5

 
(17.0
)
 
9.6

 
(7.4
)
Total derivative instruments
$
(65.0
)
 
$
60.8

 
$
(4.2
)
 
$
(114.4
)
 
$
59.6

 
$
(54.8
)
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 March 31, 2014, the Company had six counterparties, in which derivatives held were net assets, totaling $17.2 million. As of December 31, 2013, the Company had no counterparties, in which the derivatives held were net assets. To manage credit risk, the Company selects and periodically reviews counterparties based on credit ratings. The Company primarily executes its derivative instruments with large financial institutions that have ratings of at least Baa2 and A- by Moody’s and S&P, respectively. In the event of default, the Company 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 March 31, 2014 or December 31, 2013. 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 March 31, 2014 and December 31, 2013, the Company had provided its counterparties with no collateral. 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

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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. 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 cash flow impact of the Company’s derivative activities is classified primarily as a change in derivative activity in the operating activities section in the unaudited condensed consolidated statements of cash flows.
Derivative Instruments Designated as Cash Flow Hedges
The Company accounts for certain derivatives hedging purchases of crude oil and sales of gasoline, diesel and jet fuel swaps as cash flow hedges. The derivative instruments designated as cash flow hedges that are 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 Company assesses, both at inception of the cash flow hedge and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. Periodically, the Company may enter into crude oil and fuel product basis swaps to more effectively hedge its crude oil purchases, crude oil sales and fuel products sales. These derivatives can be combined with a swap contract in order to create a more effective cash flow hedge. 
To the extent a derivative instrument designated as a cash flow 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.
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, determined on a derivative by derivative basis or in the aggregate for a specific commodity, and has the potential for the future loss of cash flow hedge accounting. Ineffectiveness has resulted and the loss of cash flow hedge accounting has resulted in increased volatility in the Company’s financial results. However, even though certain derivative instruments may not qualify for cash flow 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.
Cash flow 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 cash flow 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 deferred 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.
The Company recorded the following amounts in its condensed consolidated balance sheets, unaudited condensed consolidated statements of operations, unaudited condensed consolidated statements of comprehensive income (loss) and unaudited condensed consolidated statements of partners’ capital as of, and for the three months ended March 31, 2014 and 2013 related to its derivative instruments that were designated as cash flow hedges (in millions):
 

23
Table of Contents

 
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Loss on Derivatives (Effective Portion)
 
Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Income (Loss) (Effective Portion)
 
Amount of Gain (Loss) Recognized in Net Income (Loss) on Derivatives (Ineffective Portion)
Three Months Ended
 
Location of Gain (Loss)
 
Three Months Ended
 
Location of Gain (Loss)
 
Three Months Ended
March 31,
 
 
March 31,
 
 
March 31,
2014
 
2013
 
 
2014
 
2013
 
 
2014
 
2013
Fuel products segment:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil swaps
$
17.7

 
$
13.8

 
Cost of sales
 
$
9.5

 
$
(4.3
)
 
Unrealized/ Realized
 
$
17.4

 
$
(24.2
)
Gasoline swaps
(1.8
)
 
(9.7
)
 
Sales
 
(5.7
)
 
(3.8
)
 
Unrealized/ Realized
 
(0.9
)
 
(0.1
)
Diesel swaps
20.0

 
(17.1
)
 
Sales
 
(6.2
)
 
—

 
Unrealized/ Realized
 
1.5

 
(1.6
)
Jet fuel swaps
6.5

 
(4.3
)
 
Sales
 
(1.2
)
 
(3.8
)
 
Unrealized/ Realized
 
0.1

 
0.5

Specialty products segment:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil swaps
—

 
—

 
Cost of sales
 
(0.3
)
 
0.3

 
Unrealized/ Realized
 
—

 
—

Total
$
42.4

 
$
(17.3
)
 
 
 
$
(3.9
)
 
$
(11.6
)
 
 
 
$
18.1

 
$
(25.4
)
The effective portion of the cash flow hedges classified in accumulated other comprehensive loss was $5.1 million and$51.4 million as of March 31, 2014 and December 31, 2013, respectively. Absent a change in the fair market value of the underlying transactions, except for any underlying transactions pertaining to the payment of interest on existing financial instruments, the following other comprehensive income (loss) at March 31, 2014 will be reclassified to earnings by December 31, 2016 with balances being recognized as follows (in millions):
Year
Accumulated Other Comprehensive Income (Loss)
2014
$
7.8

2015
(11.0
)
2016
(1.9
)
Total
$
(5.1
)
Based on fair values as of March 31, 2014, the Company expects to reclassify $5.2 million of net gains on derivative instruments from accumulated other comprehensive loss to earnings during the next twelve months due to actual crude oil purchases, diesel, gasoline and jet fuel sales. However, the amounts actually realized will be dependent on the fair values as of the dates of settlement.
Derivative Instruments Designated as Fair Value Hedges
For derivative instruments that are designated and qualify as a fair value hedge, the effective gain or loss on the derivative instrument, as well as the offsetting gain or loss on the hedged item attributable to the hedged risk are recognized as interest expense in the unaudited condensed consolidated statements of operations. No hedge ineffectiveness was recognized as the interest rate swap qualifies for the “shortcut” method, and as a result, changes in the fair value of the derivative instrument offset the changes in the fair value of the underlying hedged debt. In addition, the differential to be paid or received on the interest rate swap arrangement is accrued and recognized as an adjustment to interest expense in the unaudited condensed consolidated statements of operations. The Company assesses at the inception of the fair value hedge whether the derivatives that are used in the hedging transactions are highly effective in offsetting changes in fair values of hedged items.
Fair value 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 fair value hedge accounting is discontinued because the derivative instrument no longer qualifies as effective fair value hedge, the derivative instrument is still subject to mark-to-market method of accounting, however the Company will cease to adjust the hedged asset or liability for changes in fair value.
In 2014, the Company entered into an interest rate swap agreement which converts a portion of the Company’s fixed rate debt to a floating rate. This agreement involves the receipt of fixed rate amounts in exchange for floating rate interest payments over the life of the agreement without an exchange of the underlying principal amount. Also, in connection with the interest rate swap agreement, the Company entered into an option that permits the counterparty to cancel the interest rate swap for a specified premium. The Company designated this interest rate swap and option as a fair value hedge.

24
Table of Contents

The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations for the three months ended March 31, 2014 and 2013 related to its derivative instrument designated as a fair value hedge (in millions):
 
Location of Gain (Loss) of Derivative
 
Amount of Loss Recognized in Net Income (Loss)
 
Hedged Item
Location of Gain (Loss) on Hedged Item
 
Amount of Gain Recognized in Net Income (Loss)
 
Three Months Ended
 
 
Three Months Ended
 
March 31,
 
 
March 31,
 
2014
 
2013
 
 
2014
 
2013
Swaps not allocated to a specific segment:
 
 
 
 
 
 
 
 
 
Interest rate swap
Interest expense
 
$
(1.6
)
 
$
—

 
2022 Notes (1)
Interest expense
 
$
1.6

 
$
—

Total
 
 
$
(1.6
)
 
$
—

 
 
 
 
$
1.6

 
$
—

 
(1) 
As of March 31, 2014, the total notional amount of the Company’s receive-fixed/pay-variable interest rate swap was $200.0 million with a maturity date of January 15, 2022. As of December 31, 2013, the Company did not have any interest rate swap agreements.
Derivative Instruments Not Designated as Hedges
For derivative instruments not designated as hedges, 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 hedge, the gain or loss at settlement is recorded to realized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. The Company has entered into crude oil basis swaps 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.
Effective January 1, 2012, cash flow 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, cash flow 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 cash flow hedge accounting on these existing derivative instruments has caused the Company to recognize losses of approximately $0.6 million and $2.6 million in realized gain (loss) on derivative instruments and unrealized gain on derivative instruments, respectively, in the unaudited condensed consolidated statements of operations for the three months ended March 31, 2013.
The amount reclassified from accumulated other comprehensive income (loss) into earnings, as a result of the discontinuance of cash flow hedge accounting for certain jet fuel and diesel derivative instruments at the Shreveport refinery because it was no longer probable that the original forecasted transaction would occur by the end of the originally specified time period, caused the Company to recognize derivative losses of approximately $1.1 million and $0.6 million in realized gain (loss) on derivative instruments and unrealized gain on derivative instruments, respectively, in the unaudited condensed consolidated statements of operations for the three months ended March 31, 2014.
The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations for the three months ended March 31, 2014 and 2013 related to its derivative instruments not designated as hedges (in millions):
 

25
Table of Contents

 
Amount of Gain (Loss) Recognized in Realized Gain (Loss) on Derivative Instruments
 
Amount of Gain (Loss) Recognized in Unrealized Gain on Derivative Instruments
Three Months Ended
 
Three Months Ended
March 31,
 
March 31,
2014
 
2013
 
2014
 
2013
Fuel products segment:
 
 
 
 
 
 
 
Crude oil swaps
$
3.9

 
$
(5.5
)
 
$
3.4

 
$
39.7

Crude oil basis swaps
0.6

 
0.2

 
1.3

 
11.6

Gasoline swaps
(3.6
)
 
0.3

 
2.5

 
(1.3
)
Diesel swaps
—

 
1.6

 
3.0

 
(5.4
)
Jet fuel swaps
(0.4
)
 
—

 
(0.9
)
 
—

Diesel crack spread collars
0.4

 
—

 
0.4

 
—

Gasoline crack spread collars
—

 
—

 
0.7

 
—

Specialty products segment:
 
 
 
 
 
 
 
Crude oil swaps
—

 
1.7

 
—

 
(1.6
)
Natural gas swaps
0.9

 
—

 
0.9

 
—

Total
$
1.8

 
$
(1.7
)
 
$
11.3

 
$
43.0

Derivative Positions - Specialty Products Segment
Natural Gas Swap Contracts
At March 31, 2014, the Company had the following derivatives related to natural gas purchases in its specialty products segment, none of which are designated as hedges.
Natural Gas Swap Contracts by Expiration Dates
MMBtu
 
$/MMBtu
Second Quarter 2014
750,000

 
$
4.14

Third Quarter 2014
750,000

 
4.14

Fourth Quarter 2014
850,000

 
4.21

Calendar Year 2015
3,720,000

 
4.26

Calendar Year 2016
3,860,000

 
4.33

Calendar Year 2017
1,300,000

 
4.28

Total
11,230,000

 

Average price
 
 
$
4.27

At December 31, 2013, the Company had the following derivatives related to natural gas purchases in its specialty products segment, none of which are designated as hedges.
Natural Gas Swap Contracts by Expiration Dates
MMBtu
 
$/MMBtu
First Quarter 2014
750,000

 
$
4.14

Second Quarter 2014
750,000

 
4.14

Third Quarter 2014
750,000

 
4.14

Fourth Quarter 2014
850,000

 
4.21

Calendar Year 2015
3,500,000

 
4.27

Calendar Year 2016
2,700,000

 
4.42

Calendar Year 2017
1,000,000

 
4.29

Total
10,300,000

 
 
Average price
 
 
$
4.28



26
Table of Contents

Derivative Positions - Fuel Products Segment
Crude Oil Swap Contracts
At March 31, 2014, 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)
Second Quarter 2014
2,411,500

 
26,500

 
$
91.97

Third Quarter 2014
2,530,000

 
27,500

 
91.23

Fourth Quarter 2014
2,024,000

 
22,000

 
90.61

Calendar Year 2015
5,784,500

 
15,848

 
88.95

Calendar Year 2016
1,830,000

 
5,000

 
84.73

Total
14,580,000

 
 
 
 
Average price
 
 
 
 
$
89.54

At March 31, 2014, the Company had the following derivatives related to crude oil purchases in its fuel products segment, none of which are designated as hedges.
Crude Oil Swap Contracts by Expiration Dates
Barrels Purchased
 
BPD
 
Average Swap
($/Bbl)
Second Quarter 2014
682,500

 
7,500

 
$
95.42

Third Quarter 2014
874,000

 
9,500

 
92.92

Fourth Quarter 2014
184,000

 
2,000

 
94.62

Calendar Year 2015
1,004,000

 
2,751

 
89.28

Total
2,744,500

 
 
 
 
Average price
 
 
 
 
$
92.33

At March 31, 2014, the Company had the following derivatives related to crude oil sales in its fuel products segment, none of which are designated as hedges.
Crude Oil Swap Contracts by Expiration Dates
Barrels Sold
 
BPD
 
Average Swap
($/Bbl)
Second Quarter 2014
45,500

 
500

 
$
96.90

Third Quarter 2014
46,000

 
500

 
96.90

Fourth Quarter 2014
46,000

 
500

 
96.90

Total
137,500

 
 
 
 
Average price
 
 
 
 
$
96.90

At December 31, 2013, 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 2014
2,520,000

 
28,000

 
$
92.06

Second Quarter 2014
2,411,500

 
26,500

 
91.97

Third Quarter 2014
2,530,000

 
27,500

 
91.23

Fourth Quarter 2014
2,024,000

 
22,000

 
90.61

Calendar Year 2015
5,556,500

 
15,223

 
89.08

Calendar Year 2016
1,830,000

 
5,000

 
84.73

Total
16,872,000

 
 
 
 
Average price
 
 
 
 
$
89.97

At December 31, 2013, the Company had the following derivatives related to crude oil purchases in its fuel products segment, none of which are designated as hedges.

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Table of Contents

Crude Oil Swap Contracts by Expiration Dates
Barrels Purchased
 
BPD
 
Average Swap
($/Bbl)
First Quarter 2014
810,000

 
9,000

 
$
94.56

Second Quarter 2014
591,500

 
6,500

 
94.37

Third Quarter 2014
874,000

 
9,500

 
92.92

Fourth Quarter 2014
184,000

 
2,000

 
94.62

Calendar Year 2015
1,004,000

 
2,751

 
89.28

Total
3,463,500

 
 
 
 
Average price
 
 
 
 
$
92.59

At December 31, 2013, the Company had the following derivatives related to crude oil sales in its fuel products segment, none of which are designated as hedges.
Crude Oil Swap Contracts by Expiration Dates
Barrels Sold
 
BPD
 
Average Swap
($/Bbl)
First Quarter 2014
45,000

 
500

 
$
96.90

Second Quarter 2014
45,500

 
500

 
96.90

Third Quarter 2014
46,000

 
500

 
96.90

Fourth Quarter 2014
46,000

 
500

 
96.90

Total
182,500

 
 
 
 
Average price
 
 
 
 
$
96.90

Crude Oil Basis Swap Contracts
The Company has 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, pricing differentials between LLS and NYMEX WTI and pricing differentials between MSW and NYMEX WTI. At March 31, 2014, the Company had the following derivatives related to crude oil basis swaps in its fuel products segment, none of which are designated as hedges.
Crude Oil Basis Swap Contracts by Expiration Dates
Barrels Purchased
 
BPD
 
Average Differential to NYMEX WTI
($/Bbl)
Second Quarter 2014
182,000

 
2,000

 
$
(23.00
)
Third Quarter 2014
184,000

 
2,000

 
(21.75
)
Fourth Quarter 2014
368,000

 
4,000

 
(21.63
)
Total
734,000

 
 
 
 
Average differential
 
 
 
 
$
(22.00
)
At December 31, 2013, the Company had the following derivatives related to crude oil basis swaps in its fuel products segment, none of which are designated as hedges.
Crude Oil Basis Swap Contracts by Expiration Dates
Barrels Purchased
 
BPD
 
Average Differential to NYMEX WTI
($/Bbl)
First Quarter 2014
118,000

 
1,311

 
$
(28.50
)
Third Quarter 2014
184,000

 
2,000