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Calumet Specialty Products Partners, L.P. - Quarter Report: 2014 March (Form 10-Q)

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
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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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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
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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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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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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

 
(21.75
)
Fourth Quarter 2014
184,000

 
2,000

 
(21.50
)
Total
486,000

 
 
 
 
Average differential
 
 
 
 
$
(23.29
)

As of December 31, 2013, the Company had approximately 248,000 barrels of crude oil basis swaps related to future crude oil purchases and sales to mitigate the risk of future changes in pricing differentials between Brent and NYMEX WTI on the Company’s reselling of crude oil. The net impact of these derivative instruments, none of which are designated as hedges, was a net loss of $0.6 million that was recorded to realized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations for the three months ended March 31, 2014.

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Table of Contents

Diesel Swap Contracts
At March 31, 2014, the Company had the following derivatives related to diesel sales in its fuel products segment, all of which are designated as cash flow hedges.
Diesel Swap Contracts by Expiration Dates
Barrels Sold
 
BPD
 
Average Swap
($/Bbl)
Second Quarter 2014
922,000

 
10,132

 
$
115.85

Third Quarter 2014
1,104,000

 
12,000

 
116.43

Fourth Quarter 2014
1,104,000

 
12,000

 
116.39

Calendar Year 2015
4,781,500

 
13,100

 
115.81

Calendar Year 2016
1,830,000

 
5,000

 
112.00

Total
9,741,500

 
 
 
 
Average price
 
 
 
 
$
115.24

At March 31, 2014, the Company had the following derivatives related to diesel sales in its fuel products segment, none of which are designated as hedges.
Diesel Swap Contracts by Expiration Dates
Barrels Sold
 
BPD
 
Average Swap
($/Bbl)
Second Quarter 2014
261,000

 
2,868

 
$
120.07

Third Quarter 2014
414,000

 
4,500

 
120.60

Fourth Quarter 2014
368,000

 
4,000

 
121.70

Calendar Year 2015
1,004,000

 
2,751

 
117.15

Total
2,047,000

 
 
 
 
Average price
 
 
 
 
$
119.04

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

 
500

 
$
121.80

Third Quarter 2014
46,000

 
500

 
121.80

Fourth Quarter 2014
46,000

 
500

 
121.80

Total
137,500

 
 
 
 
Average price
 
 
 
 
$
121.80

At December 31, 2013, the Company had the following derivatives related to diesel sales in its fuel products segment, all of which are designated as cash flow hedges.
Diesel Swap Contracts by Expiration Dates
Barrels Sold
 
BPD
 
Average Swap
($/Bbl)
First Quarter 2014
1,125,000

 
12,500

 
$
117.54

Second Quarter 2014
1,183,000

 
13,000

 
116.78

Third Quarter 2014
1,288,000

 
14,000

 
116.82

Fourth Quarter 2014
1,288,000

 
14,000

 
116.96

Calendar Year 2015
4,781,500

 
13,100

 
115.81

Calendar Year 2016
1,830,000

 
5,000

 
112.00

Total
11,495,500

 
 
 
 
Average price
 
 
 
 
$
115.72


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Table of Contents

At December 31, 2013, the Company had the following derivatives related to diesel sales in its fuel products segment, none of which are designated as hedges.
Diesel Swap Contracts by Expiration Dates
Barrels Sold
 
BPD
 
Average Swap
($/Bbl)
First Quarter 2014
270,000

 
3,000

 
$
121.72

Second Quarter 2014
182,000

 
2,000

 
123.22

Third Quarter 2014
230,000

 
2,500

 
121.74

Fourth Quarter 2014
184,000

 
2,000

 
123.02

Calendar Year 2015
1,004,000

 
2,751

 
117.15

Total
1,870,000

 
 
 
 
Average price
 
 
 
 
$
119.54

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

 
500

 
$
121.80

Second Quarter 2014
45,500

 
500

 
121.80

Third Quarter 2014
46,000

 
500

 
121.80

Fourth Quarter 2014
46,000

 
500

 
121.80

Total
182,500

 
 
 
 
Average price
 
 
 
 
$
121.80

Diesel Crack Spread Collars
At March 31, 2014, the Company had the following diesel crack spread collars related to diesel sales and crude oil purchases in its fuel products segment, none of which are designated as hedges.
Diesel Crack Spread Collars by Expiration Dates
Barrels Purchased and Sold
 
BPD
 
Average Bought
Put ($/Bbl)
 
Average Sold
Call ($/Bbl)
Second Quarter 2014 (1)
91,000

 
1,000

 
$
26.00

 
$
35.00

Third Quarter 2014
92,000

 
1,000

 
26.00

 
35.00

Fourth Quarter 2014
92,000

 
1,000

 
26.00

 
35.00

Total
275,000

 
 
 
 
 
 
Average price
 
 
 
 
$
26.00

 
$
35.00

 
(1) 
During the first quarter 2014, the Company entered into diesel crack spread collars, none of which are designated as hedges, which is the reverse position of the diesel crack spread collars expiring in the second quarter 2014 noted above.
At December 31, 2013, the Company had the following diesel crack spread collars related to diesel sales and crude oil purchases in its fuel products segment, none of which are designated as hedges.
Diesel Crack Spread Collars by Expiration Dates
Barrels Purchased and Sold
 
BPD
 
Average Bought
Put ($/Bbl)
 
Average Sold
Call ($/Bbl)
First Quarter 2014
90,000

 
1,000

 
$
26.00

 
$
35.00

Second Quarter 2014
91,000

 
1,000

 
26.00

 
35.00

Third Quarter 2014
92,000

 
1,000

 
26.00

 
35.00

Fourth Quarter 2014
92,000

 
1,000

 
26.00

 
35.00

Total
365,000

 
 
 
 
 
 
Average price
 
 
 
 
$
26.00

 
$
35.00


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Table of Contents

Jet Fuel Swap Contracts
At March 31, 2014, the Company had the following derivatives related to jet fuel sales in its fuel products segment, all of which are designated as cash flow hedges.
Jet Fuel Swap Contracts by Expiration Dates
Barrels Sold
 
BPD
 
Average Swap
($/Bbl)
Second Quarter 2014
273,000

 
3,000

 
$
116.68

Third Quarter 2014
276,000

 
3,000

 
116.18

Fourth Quarter 2014
276,000

 
3,000

 
115.65

Calendar Year 2015
957,500

 
2,623

 
114.25

Total
1,782,500

 
 
 
 
Average price
 
 
 
 
$
115.14

At December 31, 2013, the Company had the following derivatives related to jet fuel sales in its fuel products segment, all of which are designated as cash flow hedges.
Jet Fuel Swap Contracts by Expiration Dates
Barrels Sold
 
BPD
 
Average Swap
($/Bbl)
First Quarter 2014
450,000

 
5,000

 
$
117.50

Second Quarter 2014
273,000

 
3,000

 
116.68

Third Quarter 2014
276,000

 
3,000

 
116.18

Fourth Quarter 2014
276,000

 
3,000

 
115.65

Calendar Year 2015
775,000

 
2,123

 
114.05

Total
2,050,000

 
 
 
 
Average price
 
 
 
 
$
115.66

At December 31, 2013, the Company had the following derivatives related to jet fuel purchases in its fuel products segment, none of which are designated as hedges.
Jet Fuel Swap Contracts by Expiration Dates
Barrels Purchased
 
BPD
 
Average Swap
($/Bbl)
First Quarter 2014
90,000

 
1,000

 
$
116.71

Total
90,000

 
 
 
 
Average price
 
 
 
 
$
116.71

Gasoline Swap Contracts
At March 31, 2014, the Company had the following derivatives related to gasoline sales in its fuel products segment, all of which are designated as cash flow hedges. 
Gasoline Swap Contracts by Expiration Dates
Barrels Sold
 
BPD
 
Average Swap
($/Bbl)
Second Quarter 2014
955,500

 
10,500

 
$
109.68

Third Quarter 2014
966,000

 
10,500

 
106.60

Fourth Quarter 2014
460,000

 
5,000

 
104.85

Calendar Year 2015
45,500

 
125

 
109.20

Total
2,427,000

 
 
 
 
Average price
 
 
 
 
$
107.53

At March 31, 2014, the Company had the following derivatives related to gasoline sales in its fuel products segment, none of which are designated as hedges. 

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Table of Contents

Gasoline Swap Contracts by Expiration Dates
Barrels Sold
 
BPD
 
Average Swap
($/Bbl)
Second Quarter 2014
682,500

 
7,500

 
$
113.30

Third Quarter 2014
644,000

 
7,000

 
108.24

Total
1,326,500

 
 
 
 
Average price
 
 
 
 
$
110.84

At December 31, 2013, the Company had the following derivatives related to gasoline sales in its fuel products segment, all of which are designated as cash flow hedges. 
Gasoline Swap Contracts by Expiration Dates
Barrels Sold
 
BPD
 
Average Swap
($/Bbl)
First Quarter 2014
945,000

 
10,500

 
$
104.39

Second Quarter 2014
955,500

 
10,500

 
109.68

Third Quarter 2014
966,000

 
10,500

 
106.60

Fourth Quarter 2014
460,000

 
5,000

 
104.85

Total
3,326,500

 
 
 
 
Average price
 
 
 
 
$
106.61

At December 31, 2013, the Company had the following derivatives related to gasoline sales in its fuel products segment, none of which are designated as hedges. 
Gasoline Swap Contracts by Expiration Dates
Barrels Sold
 
BPD
 
Average Swap
($/Bbl)
First Quarter 2014
630,000

 
7,000

 
$
105.67

Second Quarter 2014
409,500

 
4,500

 
110.48

Third Quarter 2014
644,000

 
7,000

 
108.24

Total
1,683,500

 
 
 
 
Average price
 
 
 
 
$
107.82

Gasoline Crack Spread Collars
At March 31, 2014, the Company had the following gasoline crack spread collars related to gasoline sales and crude oil purchases in its fuel products segment, none of which are designated as hedges.
Gasoline Crack Spread Collars by Expiration Dates
Barrels Purchased and Sold
 
BPD
 
Average Bought
Put ($/Bbl)
 
Average Sold
Call ($/Bbl)
Second Quarter 2014
182,000

 
2,000

 
$
18.00

 
$
24.44

Third Quarter 2014
92,000

 
1,000

 
16.00

 
21.70

Total
274,000

 
 
 
 
 
 
Average price
 
 
 
 
$
17.33

 
$
23.52

At December 31, 2013, the Company did not have any gasoline crack spread collars related to gasoline sales and crude oil purchases.
10. Fair Value Measurements
The Company uses a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. Observable inputs are from sources independent of the Company. Unobservable inputs reflect the Company’s assumptions about the factors market participants would use in valuing the asset or liability developed based upon the best information available in the circumstances. These tiers include the following:
•Level 1—inputs include observable unadjusted quoted prices in active markets for identical assets or liabilities
•Level 2—inputs include other than quoted prices in active markets that are either directly or indirectly observable
•Level 3—inputs include unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions

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In determining fair value, the Company uses various valuation techniques and prioritizes the use of observable inputs. The availability of observable inputs varies from instrument to instrument and depends on a variety of factors including the type of instrument, whether the instrument is actively traded and other characteristics particular to the instrument. For many financial instruments, pricing inputs are readily observable in the market, the valuation methodology used is widely accepted by market participants and the valuation does not require significant management judgment. For other financial instruments, pricing inputs are less observable in the marketplace and may require management judgment.
Recurring Fair Value Measurements
Derivative Assets and Liabilities
Derivative instruments are reported in the accompanying unaudited condensed consolidated financial statements at fair value. The Company’s derivative instruments consist of over-the-counter (“OTC”) contracts, which are not traded on a public exchange. Substantially all of the Company’s derivative instruments are with counterparties that have long-term credit ratings of at least Baa2 and A- by Moody’s and S&P, respectively.
To estimate the fair values of the Company’s commodity derivative instruments, the Company uses the forward rate, the strike price, contractual notional amounts, the risk free rate of return and contract maturity. To estimate the fair value of the Company’s fixed-to-floating interest rate swap derivative instrument, the Company uses discounted cash flows, which use observable inputs, such as maturity and market interest rates. Various analytical tests are performed to validate the counterparty data. The fair values of the Company’s derivative instruments are adjusted for nonperformance risk and creditworthiness of the hedging entities through the Company’s credit valuation adjustment (“CVA”). The CVA is calculated at the counterparty level utilizing the fair value exposure at each payment date and applying a weighted probability of the appropriate survival and marginal default percentages. The Company uses the counterparty’s marginal default rate and the Company’s survival rate when the Company is in a net asset position at the payment date and uses the Company’s marginal default rate and the counterparty’s survival rate when the Company is in a net liability position at the payment date. As a result of applying the applicable CVA at March 31, 2014, the Company’s net asset was impacted by an immaterial amount and net liability was reduced by approximately $3.4 million. As a result of applying the CVA at December 31, 2013, the Company’s net liability was reduced by approximately $1.9 million.
Observable inputs utilized to estimate the fair values of the Company’s derivative instruments were primarily based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. Based on the use of various unobservable inputs, principally non-performance risk, creditworthiness of the hedging entities and unobservable inputs in the forward rate, the Company has categorized these derivative instruments as Level 3. Significant increases (decreases) in any of those unobservable inputs in isolation would result in a significantly lower (higher) fair value measurement. The Company believes it has obtained the most accurate information available for the types of derivative instruments it holds. See Note 9 for further information on derivative instruments.
Pension Assets
Pension assets are reported at fair value in the accompanying unaudited condensed consolidated financial statements. At March 31, 2014, the Company’s investments associated with its Pension Plan (as such term is hereinafter defined) primarily consist of (i) cash and cash equivalents and (ii) mutual funds. The mutual funds are categorized as Level 2 because inputs used in their valuation are not quoted prices in active markets that are indirectly observable and are valued at the net asset value (“NAV”) of shares in each fund held by the Pension Plan at quarter end as provided by the third party administrator. See Note 12 for further information on pension assets.
Liability Awards
Unit based compensation liability awards are awards that are expected to be settled in cash on their vesting dates, rather than in equity units (“Liability Awards”). The Liability Awards are categorized as Level 1 because the fair value of the Liability Awards is based on the Company’s quoted closing unit price as of each balance sheet date.
Renewable Identification Numbers Obligation
The Company’s RINs obligation (“RINs Obligation”) represents a liability for the purchase of RINs to satisfy the EPA requirement to blend biofuels into the fuel products it produces pursuant to the EPA’s Renewable Fuel Standard. RINs are assigned to biofuels produced in the U.S. as required by the EPA. The EPA sets annual quotas for the percentage of biofuels that must be blended into transportation fuels consumed in the U.S., and as a producer of motor fuels from petroleum, the Company is required to blend biofuels into the fuel products it produces at a rate that will meet the EPA’s annual quota. To the extent the Company is unable to blend biofuels at that rate, it must purchase RINs in the open market to satisfy the annual requirement. The Company’s RINs Obligation is based on the amount of RINs it must purchase and the price of those RINs as

33
Table of Contents

of the balance sheet date. The RINs Obligation is categorized as Level 2 and is measured at fair value using the market approach based on quoted prices from an independent pricing service.
Hierarchy of Recurring Fair Value Measurements
The Company’s recurring assets and liabilities measured at fair value at March 31, 2014 and December 31, 2013 were as follows (in millions):
 
 
March 31, 2014
 
December 31, 2013
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
Assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Derivative assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil swaps
$
—

 
$
—

 
$
43.6

 
$
43.6

 
$
—

 
$
—

 
$
—

 
$
—

Crude oil basis swaps
—

 
—

 
1.1

 
1.1

 
—

 
—

 
—

 
—

Gasoline swaps
—

 
—

 
(12.6
)
 
(12.6
)
 
—

 
—

 
—

 
—

Diesel swaps
—

 
—

 
(15.0
)
 
(15.0
)
 
—

 
—

 
—

 
—

Jet fuel swaps
—

 
—

 
(1.1
)
 
(1.1
)
 
—

 
—

 
—

 
—

Diesel crack spread collars
—

 
—

 
0.5

 
0.5

 
—

 
—

 
—

 
—

Gasoline crack spread collars
—

 
—

 
0.7

 
0.7

 
—

 
—

 
—

 
—

Total derivative assets
—

 
—

 
17.2

 
17.2

 
—

 
—

 
—

 
—

Pension plan investments
0.2

 
46.8

 
—

 
47.0

 
—

 
45.8

 
—

 
45.8

Total recurring assets at fair value
$
0.2

 
$
46.8

 
$
17.2

 
$
64.2

 
$
—

 
$
45.8

 
$
—

 
$
45.8

Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Derivative liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil swaps
$
—

 
$
—

 
$
15.5

 
$
15.5

 
$
—

 
$
—

 
$
37.0

 
$
37.0

Crude oil basis swaps
—

 
—

 
0.7

 
0.7

 
—

 
—

 
0.4

 
0.4

Gasoline swaps
—

 
—

 
(9.1
)
 
(9.1
)
 
—

 
—

 
(28.1
)
 
(28.1
)
Diesel swaps
—

 
—

 
(5.2
)
 
(5.2
)
 
—

 
—

 
(50.6
)
 
(50.6
)
Jet fuel swaps
—

 
—

 
(4.2
)
 
(4.2
)
 
—

 
—

 
(12.4
)
 
(12.4
)
Diesel crack spread collars
—

 
—

 
—

 
—

 
—

 
—

 
0.1

 
0.1

Natural gas swaps
—

 
—

 
(0.3
)
 
(0.3
)
 
—

 
—

 
(1.2
)
 
(1.2
)
Interest rate swaps
—

 
—

 
(1.6
)
 
(1.6
)
 
—

 
—

 
—

 
—

Total derivative liabilities
—

 
—

 
(4.2
)
 
(4.2
)
 
—

 
—

 
(54.8
)
 
(54.8
)
RINs Obligation
—

 
(6.9
)
 
—

 
(6.9
)
 
—

 
(5.3
)
 
—

 
(5.3
)
Liability Awards
(3.8
)
 
—

 
—

 
(3.8
)
 
(3.7
)
 
—

 
—

 
(3.7
)
Total recurring liabilities at fair value
$
(3.8
)
 
$
(6.9
)
 
$
(4.2
)
 
$
(14.9
)
 
$
(3.7
)
 
$
(5.3
)
 
$
(54.8
)
 
$
(63.8
)
The table below sets forth a summary of net changes in fair value of the Company’s Level 3 financial assets and liabilities for the three months ended March 31, 2014 and 2013 (in millions):
 

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Table of Contents

 
Three Months Ended March 31,
 
2014
 
2013
Fair value at January 1,
$
(54.8
)
 
$
(44.9
)
Realized (gain) loss on derivative instruments
(6.6
)
 
8.6

Unrealized gain on derivative instruments
24.6

 
24.5

Interest expense, net
(1.9
)
 
—

Change in fair value of cash flow hedges
42.4

 
(17.3
)
Settlements
9.3

 
4.3

Transfers in (out) of Level 3
—

 
—

Fair value at March 31,
$
13.0

 
$
(24.8
)
Total gain included in net income (loss) attributable to changes in unrealized gain relating to financial assets and liabilities held as of March 31,
$
24.6

 
$
24.5

All settlements from derivative instruments designated as cash flow hedges and deemed “effective” are included in sales for gasoline, diesel and jet fuel derivatives, and cost of sales for crude oil and natural gas derivatives in the unaudited condensed consolidated statements of operations in the period that the hedged cash flow occurs. Any “ineffectiveness” associated with these derivative instruments designated as cash flow hedges are recorded in earnings in realized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. All settlements from derivative instruments designated as fair value hedges are accrued and recorded as an adjustment to interest expense in the unaudited condensed consolidated statements of operations. All settlements from derivative instruments not designated as hedges are recorded in realized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. See Note 9 for further information on derivative instruments.
Nonrecurring Fair Value Measurements
Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances, such as when there is evidence of impairment. Assets and liabilities acquired in business combinations are recorded at their fair value as of the date of acquisition. Refer to Note 3 for the fair values of assets acquired and liabilities assumed in connection with the Company’s acquisitions.
The Company reviews for goodwill impairment annually on October 1 and whenever events or changes in circumstances indicate its carrying value may not be recoverable. The fair value of the reporting units is determined using the income approach. The income approach focuses on the income-producing capability of an asset, measuring the current value of the asset by calculating the present value of its future economic benefits such as cash earnings, cost savings, corporate tax structure and product offerings. Value indications are developed by discounting expected cash flows to their present value at a rate of return that incorporates the risk-free rate for the use of funds, the expected rate of inflation and risks associated with the reporting unit. These assets would generally be classified within Level 3, in the event that the Company were required to measure and record such assets at fair value within its unaudited condensed consolidated financial statements.
The Company periodically evaluates the carrying value of long-lived assets to be held and used, including indefinite-lived intangible assets and property plant and equipment, when events or circumstances warrant such a review. Fair value is determined primarily using anticipated cash flows assumed by a market participant discounted at a rate commensurate with the risk involved and these assets would generally be classified within Level 3, in the event that the Company was required to measure and record such assets at fair value within its unaudited condensed consolidated financial statements.
Estimated Fair Value of Financial Instruments
Cash
The carrying value of cash is considered to be representative of its fair value.
Debt
The estimated fair value of long-term debt at March 31, 2014 and December 31, 2013 consists primarily of the senior notes. The estimated aggregate fair value of the Company’s senior notes defined as Level 1 was based upon quoted market prices in an active market. The estimated aggregate fair value of the Company’s senior notes classified as Level 2 was based upon directly observable inputs. The carrying value of borrowings, if any, under the Company’s revolving credit facility and capital lease obligations approximate their fair values as determined by discounted cash flows and are classified as Level 3. See Note 8 for further information on long-term debt.

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The Company’s carrying and estimated fair value of the Company’s financial instruments, carried at adjusted historical cost, at March 31, 2014 and December 31, 2013 were as follows (in millions): 
 
 
 
March 31, 2014
 
December 31, 2013
 
Level
 
Fair Value
 
Carrying Value
 
Fair Value
 
Carrying Value
Financial Instrument:
 
 
 
 
 
 
 
 
 
Senior notes
1
 
$
694.6

 
$
614.2

 
$
863.6

 
$
761.2

Senior notes
2
 
$
903.4

 
$
900.0

 
$
353.9

 
$
344.8

Revolving credit facility
3
 
$
—

 
$
—

 
$
—

 
$
—

Capital lease and other obligations
3
 
$
4.6

 
$
4.6

 
$
4.8

 
$
4.8

11. Partners’ Capital
On March 10, 2014, the Company entered into an Equity Placement Agreement with various sales agents under which the Company may issue and sell, from time to time, common units representing limited partner interests, having an aggregate offering price of up to $300.0 million through one or more sales agents. The Equity Placement Agreement provides the Company the right, but not the obligation, to sell common units in the future, at prices the Company deems appropriate. These sales, if any, will be made pursuant to the terms of the Equity Placement Agreement between the Company and the sales agents. The net proceeds from any sales under this agreement will be used for general partnership purposes, which may include, among other things, repayment of indebtedness, working capital, capital expenditures and acquisitions. The Company’s general partner will contribute its proportionate capital contribution to retain its 2% general partner interest. For the three months ended March 31, 2014, the Company had no sales of common units under the Equity Placement Agreement.
The Company’s distribution policy is defined in its partnership agreement. For the three months ended March 31, 2014 and 2013, the Company made distributions of $52.6 million and $44.5 million, respectively, to its partners. For the three months ended March 31, 2014 and 2013, the general partner was allocated $3.8 million and $3.2 million, respectively, in incentive distribution rights.
12. Employee Benefit Plans
The components of net periodic pension benefit cost for the three months ended March 31, 2014 and 2013 were as follows (in millions):
 
Three Months Ended March 31,
 
2014
2013
Service cost
$
0.1

 
$
0.1

Interest cost
0.7

 
0.6

Expected return on assets
(0.8
)
 
(0.5
)
Amortization of net loss
0.2

 
0.2

Net periodic benefit cost
$
0.2

 
$
0.4

At March 31, 2014 and December 31, 2013, the Company’s investments associated with its Pension Plan primarily consist of (i) cash and cash equivalents and (ii) mutual funds. The mutual funds are categorized as Level 2 because inputs used in their valuation are not quoted prices in active markets that are indirectly observable and are valued at the NAV of shares in each fund held by the Pension Plan at quarter end as provided by the third party administrator.
See Note 10 for the definition of Levels 1, 2 and 3. The Company’s Pension Plan assets measured at fair value at March 31, 2014 and December 31, 2013 were as follows (in millions):
 
 
March 31, 2014
 
December 31, 2013
 
Level 1
 
Level 2
 
Level 1
 
Level 2
Cash and cash equivalents
$
0.2

 
$
—

 
$
—

 
$
—

Domestic equities
—

 
10.6

 
—

 
10.6

Foreign equities
—

 
10.5

 
—

 
10.6

Fixed income
—

 
25.7

 
—

 
24.6

 
$
0.2

 
$
46.8

 
$
—

 
$
45.8


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Investment Fund Strategies
Domestic equity funds include funds that invest in U.S. common and preferred stocks. Foreign equity funds invest in securities issued by companies listed on international stock exchanges. Certain funds have value and growth objectives and managers may attempt to profit from security mispricing in equity markets to meet these objectives. Short term investments (including commercial paper, certificates of deposits and government repurchase agreements) and derivatives may be used for hedging purposes to limit exposure to various risk factors.
Fixed income funds invest in U.S. dollar-denominated, investment grade bonds, including U.S. Treasury and government agency securities, corporate bonds and mortgage and asset-backed securities. These funds may also invest in any combination of non-investment grade bonds, non-U.S. dollar denominated bonds and bonds issued by issuers in emerging capital markets. Short term investments (including commercial paper, certificates of deposits and government repurchase agreements) and derivatives may be used for hedging purposes to limit exposure to various risk factors.

13. Accumulated Other Comprehensive Loss
The table below sets forth a summary of reclassification adjustments out of accumulated other comprehensive loss in the Company’s unaudited condensed consolidated statements of operations for the three months ended March 31, 2014 and 2013 (in millions):
Components of Accumulated Other Comprehensive Loss
 
Amount Reclassified From Accumulated Other Comprehensive Loss
 
Location of Gain (Loss)
 
Three Months Ended March 31,
 
 
2014
 
2013
 
Derivative gains (losses) on cash flow hedges:
 
 
 
 
 
 
$
(13.1
)
 
$
(7.6
)
 
Sales
 
 
9.2

 
(4.0
)
 
Cost of sales
 
 
$
(3.9
)
 
$
(11.6
)
 
Total
 
 
 
 
 
 
 
Amortization of defined benefit pension and postretirement health benefit plans:
 

Amortization of net loss
 
$
(0.2
)
 
$
(0.2
)
 
(1) 
 
 
$
(0.2
)
 
$
(0.2
)
 
Total
 
(1) 
This accumulated other comprehensive loss component is included in the computation of net periodic pension cost. See Note 12 for additional details.

14. Earnings Per Unit
The following table sets forth the computation of basic and diluted earnings per limited partner unit for the three months ended March 31, 2014 and 2013 (in millions, except unit and per unit data):
 

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Table of Contents

 
Three Months Ended
 
March 31,
 
2014
 
2013
 
 
Numerator for basic and diluted earnings per limited partner unit:
 
 
 
Net income (loss)
$
(49.8
)
 
$
46.0

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

Denominator for basic and diluted earnings per limited partner unit:
 
 
 
Basic weighted average limited partner units outstanding
69,622,884

 
62,831,155

Effect of dilutive securities:

 

Participating securities — phantom units
—

 
186,714

Diluted weighted average limited partner units outstanding (1)
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

 
(1) Total diluted weighted average limited partner units outstanding excludes 0.1 million dilutive phantom units for the three months ended March 31, 2014.

15. Segments and Related Information
a. Segment Reporting
The Company manages its business in multiple operating segments, which are grouped on the basis of similar product, market and operating factors into the following reportable segments:
•
Specialty Products. The Specialty Products segment produces a variety of lubricating oils, solvents, waxes, synthetic lubricants and other products which are sold to customers who purchase these products primarily as raw material components for basic automotive, industrial and consumer goods. Specialty products also include synthetic lubricants used in manufacturing, mining and automotive applications.
•
Fuel Products. The Fuel Products segment produces primarily gasoline, diesel, jet fuel and asphalt which are primarily sold to customers located in PADD 2, PADD 3 and PADD 4 areas within the U.S.
During the fourth quarter 2013, the Company realigned its reportable segments for financial reporting purposes as a result of significant growth in the Company. The change primarily represents reporting the operating results of asphalt produced at the Shreveport, Superior and Montana refineries within the fuel products segment. Prior to this change, asphalt was reported as part of the specialty products segment. While this reporting change did not impact the Company’s consolidated results, segment data for previous years has been restated and is consistent with the current year presentation throughout the unaudited condensed consolidated financial statements and the accompanying notes.
The accounting policies of the reporting segments are the same as those described in the summary of significant accounting policies as disclosed in Note 2 — “Summary of Significant Accounting Policies” in Part II, Item 8 “Financial Statements and Supplementary Data” of the Company’s 2013 Annual Report, except that the disaggregated financial results for the reporting segments have been prepared using a management approach, which is consistent with the basis and manner in which management internally disaggregates financial information for the purposes of assisting internal operating decisions. The Company evaluates performance based upon Adjusted EBITDA. The Company defines Adjusted EBITDA for any period as: (1) net income (loss) plus (2)(a) interest expense; (b) income taxes; (c) depreciation and amortization; (d) unrealized losses from mark to market accounting for hedging activities; (e) realized gains under derivative instruments excluded from the determination of net income (loss); (f) non-cash equity based compensation expense and other non-cash items (excluding items such as accruals of cash expenses in a future period or amortization of a prepaid cash expense) that were deducted in computing net income (loss); (g) debt refinancing fees, premiums and penalties and (h) all extraordinary, unusual or non-recurring items of gain or loss, or revenue or expense; minus (3)(a) unrealized gains from mark to market accounting for hedging activities; (b) realized losses under derivative instruments excluded from the determination of net income and (c) other non-recurring expenses and unrealized items that reduced net income (loss) for a prior period, but represent a cash item in the current period.

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The Company manages its assets on a total company basis, not by segment. Therefore, management does not review any asset information by segment and, accordingly, the Company does not report asset information by segment.
Reportable segment information is as follows (in millions):
Three months ended March 31, 2014
Specialty
Products
 
Fuel
Products
 
Combined
Segments
 
Eliminations
 
Consolidated
Total
Sales:
 
 
 
 
 
 
 
 
 
External customers
$
450.0

 
$
891.0

 
$
1,341.0

 
$
—

 
$
1,341.0

Intersegment sales
—

 
17.2

 
17.2

 
(17.2
)
 
—

Total sales
$
450.0

 
$
908.2

 
$
1,358.2

 
$
(17.2
)
 
$
1,341.0

Adjusted EBITDA
$
57.7

 
$
25.0

 
$
82.7

 
—

 
$
82.7

Reconciling items to net loss:
 
 
 
 
 
 
 
 
 
Depreciation and amortization
16.7

 
19.3

 
36.0

 
—

 
36.0

Realized gain on derivatives, not reflected in net loss
0.3

 
1.2

 
1.5

 
—

 
1.5

Unrealized gain on derivatives
 
 
 
 
 
 
 
 
(24.6
)
Interest expense
 
 
 
 
 
 
 
 
26.2

Debt extinguishment costs
 
 
 
 
 
 
 
 
89.6

Non-cash equity based compensation and other non-cash items
 
 
 
 
 
 
 
 
3.6

Income tax expense
 
 
 
 
 
 
 
 
0.2

Net loss
 
 
 
 
 
 
 
 
$
(49.8
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three months ended March 31, 2013
Specialty
Products
 
Fuel
Products
 
Combined
Segments
 
Eliminations
 
Consolidated
Total
Sales:
 
 
 
 
 
 
 
 
 
External customers
$
474.3

 
$
844.3

 
$
1,318.6

 
$
—

 
$
1,318.6

Intersegment sales
—

 
19.1

 
19.1

 
(19.1
)
 
—

Total sales
$
474.3

 
$
863.4

 
$
1,337.7

 
$
(19.1
)
 
$
1,318.6

Adjusted EBITDA
$
52.6

 
$
27.4

 
$
80.0

 
—

 
$
80.0

Reconciling items to net income:
 
 
 
 
 
 
 
 
 
Depreciation and amortization
16.1

 
15.8

 
31.9

 
—

 
31.9

Realized loss on derivatives, not reflected in net income
(0.3
)
 
(1.0
)
 
(1.3
)
 
—

 
(1.3
)
Unrealized gain on derivatives
 
 
 
 
 
 
 
 
(24.5
)
Interest expense
 
 
 
 
 
 
 
 
24.8

Non-cash equity based compensation and other non-cash items
 
 
 
 
 
 
 
 
2.9

Income tax expense
 
 
 
 
 
 
 
 
0.2

Net income
 
 
 
 
 
 
 
 
$
46.0


 b. Geographic Information
International sales accounted for less than 10% of consolidated sales in each of the three months ended March 31, 2014 and 2013. Substantially all of the Company’s long-lived assets are domestically located.
c. Product Information
The Company offers specialty products primarily in categories consisting of lubricating oils, solvents, waxes, packaged and synthetic specialty products and other. Fuel products categories primarily consist of gasoline, diesel, jet fuel, asphalt, heavy fuel oils and other. The following table sets forth the major product category sales for the three months ended March 31, 2014 and 2013 (in millions): 

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Table of Contents

 
Three Months Ended March 31,
 
2014
 
2013
Specialty products:
 
 
 
 
 
 
 
Lubricating oils
$
197.7

 
14.7
%
 
$
239.9

 
18.2
%
Solvents
131.4

 
9.8
%
 
131.7

 
10.0
%
Waxes
35.4

 
2.6
%
 
32.8

 
2.5
%
Packaged and synthetic specialty products
76.4

 
5.7
%
 
59.5

 
4.5
%
Other
9.1

 
0.7
%
 
10.4

 
0.8
%
Total
$
450.0

 
33.5
%
 
$
474.3

 
36.0
%
Fuel products:
 
 
 
 
 
 
 
Gasoline
$
359.6

 
26.8
%
 
$
327.3

 
24.8
%
Diesel
317.4

 
23.7
%
 
305.3

 
23.2
%
Jet fuel
44.0

 
3.3
%
 
50.2

 
3.8
%
Asphalt, heavy fuel oils and other
170.0

 
12.7
%
 
161.5

 
12.2
%
Total
$
891.0

 
66.5
%
 
$
844.3

 
64.0
%
Consolidated sales
$
1,341.0

 
100.0
%
 
$
1,318.6

 
100.0
%
d. Major Customers
During the three months ended March 31, 2014 and 2013, the Company had no customer that represented 10% or greater of consolidated sales.
e. Major Suppliers
During the three months ended March 31, 2014 and 2013, the Company had two suppliers that supplied approximately 47.8%, and 53.4%, respectively, of its crude oil supply.
16. Subsequent Events
On April 22, 2014, the Company declared a quarterly cash distribution of $0.685 per unit on all outstanding common units, or approximately $52.5 million (including the general partner’s incentive distribution rights) in aggregate, for the quarter ended March 31, 2014. The distribution will be paid on May 15, 2014 to unitholders of record as of the close of business on May 5, 2014. This quarterly distribution of $0.685 per unit equates to $2.74 per unit per year, or approximately $210.0 million (including the general partner’s incentive distribution rights) in aggregate on an annualized basis.
The fair value of the Company’s derivatives decreased by approximately $5.0 million subsequent to March 31, 2014 to a net asset of approximately $8.0 million. The fair value of the Company’s long-term debt, excluding capital leases, has decreased by approximately $6.0 million subsequent to March 31, 2014.


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


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

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


43
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Key Performance Measures
Our sales and net income are principally affected by the price of crude oil, demand for specialty and fuel products, prevailing crack spreads for fuel products, the price of natural gas used as fuel in our operations and our results from derivative instrument activities.
Our primary raw materials are crude oil and other specialty feedstocks and our primary outputs are specialty petroleum products and fuel products. The prices of crude oil, specialty products and fuel products are subject to fluctuations in response to changes in supply, demand, market uncertainties and a variety of additional factors beyond our control. We monitor these risks and enter into derivative instruments designed to help mitigate the impact of commodity price fluctuations on our business. The primary purpose of our commodity risk management activities is to economically hedge our cash flow exposure to commodity price risk so that we can meet our cash distribution, debt service and capital expenditure requirements despite fluctuations in crude oil and fuel products prices. We enter into derivative contracts for future periods in quantities that do not exceed our projected purchases of crude oil and natural gas and sales of fuel products. Please read Part I, Item 3 “Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk.” As of March 31, 2014, we had hedged refining margins, or crack spreads, on approximately 17.2 million barrels of fuel products through December 2016 at an average refining margin of $24.27 per barrel with average refining margins ranging from a low of $20.86 per barrel in the third quarter 2014 to a high of $27.27 per barrel in 2016. Please refer to Note 9 — “Derivatives” under Part I, Item 1 “Financial Statements—Notes to Unaudited Condensed Consolidated Financial Statements” and Part I, Item 3 “Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk” for detailed information regarding our derivative instruments and our commodity price risk.
Our management uses several financial and operational measurements to analyze our performance. These measurements include the following:
•sales volumes;
•production yields;
•specialty products and fuel products segment gross profit; and
•specialty products and fuel products segment Adjusted EBITDA.
Sales volumes. We view the volumes of specialty products and fuel products sold as an important measure of our ability to effectively utilize our operating assets. Our ability to meet the demands of our customers is driven by the volumes of crude oil and feedstocks that we run at our facilities. Higher volumes improve profitability both through the spreading of fixed costs over greater volumes and the additional gross profit achieved on the incremental volumes.
Production yields. In order to maximize our gross profit and minimize lower margin by-products, we seek the optimal product mix for each barrel of crude oil we refine, or feedstocks we, or third parties, process, which we refer to as production yield.
Specialty products and fuel products segment gross profit. Specialty products and fuel products gross profit are important measures of our ability to maximize the profitability of our specialty products and fuel products segments. We define specialty products and fuel products gross profit as sales less the cost of crude oil and other feedstocks and other production-related expenses, the most significant portion of which includes labor, plant fuel, utilities, contract services, maintenance, depreciation and processing materials. We use specialty products and fuel products gross profit as indicators of our ability to manage our business during periods of crude oil and natural gas price fluctuations, as the prices of our specialty products and fuel products generally do not change immediately with changes in the price of crude oil and natural gas. The increase in selling prices typically lags behind the rising costs of crude oil feedstocks for specialty products. Other than plant fuel, production-related expenses generally remain stable across broad ranges of throughput volumes, but can fluctuate depending on maintenance activities performed during a specific period.
Our fuel products segment gross profit may differ from standard U.S. Gulf Coast, Group 3, PADD 4 Billings, Montana or 3/2/1 and 2/1/1 market crack spreads due to many factors, including derivative activities to hedge both our fuel products segment sales and the cost of crude oil reflected in gross profit, our fuel products mix as shown in our production table being different than the ratios used to calculate such market crack spreads, operating costs including fixed costs and actual crude oil costs differing from market indices and our local market pricing differentials for fuel products in the Shreveport, Louisiana, San Antonio, Texas, Superior, Wisconsin and Great Falls, Montana vicinities as compared to U.S. Gulf Coast, Group 3 and PADD 4 Billings, Montana postings.

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

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Results of Operations for the Three Months Ended March 31, 2014 and 2013
Production Volume. The following table sets forth information about our combined operations. Facility production volume differs from sales volume due to changes in inventories and the sale of purchased fuel product blendstocks such as ethanol and biodiesel and the resale of crude oil in our fuel products segment. The table includes the results of operations at our San Antonio refinery commencing January 2, 2013, Bel-Ray facility commencing December 10, 2013 and United Petroleum assets commencing February 28, 2014.
 
Three Months Ended March 31,
 
2014
 
2013
 
% Change
 
(In bpd)
 
 
Total sales volume (1)
117,478


111,789

 
5.1
 %
Total feedstock runs (2)
118,359


110,465

 
7.1
 %
Facility production: (3)
 
 
 
 
 
Specialty products:
 
 
 
 
 
Lubricating oils
10,617


12,127

 
(12.5
)%
Solvents
8,595


8,561

 
0.4
 %
Waxes
1,321


1,234

 
7.1
 %
Packaged and synthetic specialty products (4)
1,554


1,950

 
(20.3
)%
Other
2,507


3,077

 
(18.5
)%
Total
24,594

 
26,949

 
(8.7
)%
Fuel products:
 
 
 
 
 
Gasoline
32,987


29,881

 
10.4
 %
Diesel
26,795


23,843

 
12.4
 %
Jet fuel
4,428


4,794

 
(7.6
)%
Asphalt, heavy fuels and other
22,368


22,518

 
(0.7
)%
Total
86,578

 
81,036

 
6.8
 %
Total facility production (3)
111,172

 
107,985

 
3.0
 %
_____________
(1) 
Total sales volume includes sales from the production at our facilities and certain third-party facilities pursuant to supply and/or processing agreements, sales of inventories and the resale of crude oil to third party customers. Total sales volume includes the sale of purchased fuel product blendstocks, such as ethanol and biodiesel, as components of finished fuel products in our fuel products segment sales.
The increase in total sales volume for the three months ended March 31, 2014 compared to the same period in 2013 is due primarily to increased fuel products sales volume, partially offset by decreased sales of lubricating oils.
(2) 
Total feedstock runs represent the barrels per day of crude oil and other feedstocks processed at our facilities and at certain third-party facilities pursuant to supply and/or processing agreements.
The increase in total feedstock runs for the three months ended March 31, 2014 compared to the same period in 2013 is due primarily to decreased feedstock runs at the Superior refinery in 2013 as a result of preparation for the April 2013 turnaround and incremental feedstock runs in 2014 as a result of the San Antonio crude oil unit expansion completed in December 2013.
(3) 
Total facility production represents the barrels per day of specialty products and fuel products yielded from processing crude oil and other feedstocks at our facilities and at certain third-party facilities pursuant to supply and/or processing agreements. The difference between total facility production and total feedstock runs is primarily a result of the time lag between the input of feedstocks and production of finished products and volume loss.
The increase in total facility production for the three months ended March 31, 2014 compared to the same period in 2013 is due primarily to the operational items discussed above in footnote 2 of this table.
(4) 
Represents production of packaged and synthetic specialty products at our Royal Purple, Bel-Ray, Calumet Packaging and Missouri facilities.


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The following table reflects our consolidated results of operations and includes the non-GAAP financial measures EBITDA, Adjusted EBITDA and Distributable Cash Flow. For a reconciliation of EBITDA, Adjusted EBITDA and Distributable Cash Flow to net income (loss) and net cash provided by (used in) operating activities, our most directly comparable financial performance and liquidity measures calculated and presented in accordance with GAAP, please read “—Non-GAAP Financial Measures.”
 
Three Months Ended March 31,
 
2014
 
2013
 
(In millions)
Sales
$
1,341.0

 
$
1,318.6

Cost of sales
1,216.2

 
1,184.2

Gross profit
124.8

 
134.4

Operating costs and expenses:
 
 
 
Selling
19.0

 
15.9

General and administrative
25.9

 
25.1

Transportation
40.4

 
35.4

Taxes other than income taxes
2.1

 
3.0

Other
2.1

 
0.6

Operating income
35.3

 
54.4

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

Realized gain (loss) on derivative instruments
6.6

 
(8.6
)
Unrealized gain on derivative instruments
24.6

 
24.5

Other
(0.3
)
 
0.7

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

Income tax expense
0.2

 
0.2

Net income (loss)
$
(49.8
)
 
$
46.0

EBITDA
$
96.4

 
$
100.3

Adjusted EBITDA
$
82.7

 
$
80.0

Distributable Cash Flow
$
49.4

 
$
26.4

Non-GAAP Financial Measures
We include in this Quarterly Report the non-GAAP financial measures EBITDA, Adjusted EBITDA and Distributable Cash Flow, and provide reconciliations of EBITDA, Adjusted EBITDA and Distributable Cash Flow to net income (loss) and net cash provided by (used in) operating activities, our most directly comparable financial performance and liquidity measures calculated and presented in accordance with GAAP.
EBITDA, Adjusted EBITDA and Distributable Cash Flow are used as supplemental financial measures by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:
•the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
•the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness;
•our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure; and
•the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

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We believe that these non-GAAP measures are useful to analysts and investors as they exclude transactions not related to our core cash operating activities and provide metrics to analyze our ability to pay distributions. We believe that excluding these transactions allows investors to meaningfully analyze trends and performance of our core cash operations.
We define EBITDA for any period as net income (loss) plus interest expense (including debt issuance and extinguishment costs), income taxes and depreciation and amortization.
We define Adjusted EBITDA for any period as: (1) net income (loss) plus (2)(a) interest expense; (b) income taxes; (c) depreciation and amortization; (d) unrealized losses from mark to market accounting for hedging activities; (e) realized gains under derivative instruments excluded from the determination of net income (loss); (f) non-cash equity based compensation expense and other non-cash items (excluding items such as accruals of cash expenses in a future period or amortization of a prepaid cash expense) that were deducted in computing net income (loss); (g) debt refinancing fees, premiums and penalties and (h) all extraordinary, unusual or non-recurring items of gain or loss, or revenue or expense; minus (3)(a) unrealized gains from mark to market accounting for hedging activities; (b) realized losses under derivative instruments excluded from the determination of net income and (c) other non-recurring expenses and unrealized items that reduced net income (loss) for a prior period, but represent a cash item in the current period.
We define Distributable Cash Flow for any period as Adjusted EBITDA less replacement and environmental capital expenditures, turnaround costs, cash interest expense (consolidated interest expense less non-cash interest expense) and income tax expense. Distributable Cash Flow is used by us and our investors and analysts to analyze our ability to pay distributions.
The definitions of Adjusted EBITDA and Distributable Cash Flow that are presented in this Quarterly Report reflect the calculation of “Consolidated Cash Flow” contained in the indentures governing our 2020 Notes, 2021 Notes and 2022 Notes (as defined in this Quarterly Report). We are required to report Consolidated Cash Flow to the holders of our 2020 Notes, 2021 Notes and 2022 Notes and Adjusted EBITDA to the lenders under our revolving credit facility, and these measures are used by them to determine our compliance with certain covenants governing those debt instruments. Adjusted EBITDA and Distributable Cash Flow that are presented in this Quarterly Report have been updated to reflect the use of new calculations. Please refer to “Liquidity and Capital Resources” within this item for additional details regarding the covenants governing our debt instruments.
EBITDA, Adjusted EBITDA and Distributable Cash Flow should not be considered alternatives to net income (loss), operating income, net cash provided by (used in) operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. In evaluating our performance as measured by EBITDA, Adjusted EBITDA and Distributable Cash Flow, management recognizes and considers the limitations of these measurements. EBITDA, Adjusted EBITDA and Distributable Cash Flow do not reflect our obligations for the payment of income taxes, interest expense or other obligations such as capital expenditures. Accordingly, EBITDA, Adjusted EBITDA and Distributable Cash Flow are only three of the measurements that management utilizes. Moreover, our EBITDA, Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of another company because all companies may not calculate EBITDA, Adjusted EBITDA and Distributable Cash Flow in the same manner.
The following tables present a reconciliation of both net income (loss) to EBITDA, Adjusted EBITDA and Distributable Cash Flow, and Distributable Cash Flow, Adjusted EBITDA and EBITDA to net cash provided by (used in) operating activities, our most directly comparable GAAP financial performance and liquidity measures, for each of the periods indicated.
 

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Table of Contents

 
Three Months Ended March 31,
 
2014
 
2013
 
(In millions)
Reconciliation of Net income (loss) to EBITDA, Adjusted EBITDA and Distributable Cash Flow:
 
 
 
Net income (loss)
$
(49.8
)
 
$
46.0

Add:

 

Interest expense
26.2

 
24.8

Debt extinguishment costs
89.6

 
—

Depreciation and amortization
30.2

 
29.3

Income tax expense
0.2

 
0.2

EBITDA
$
96.4

 
$
100.3

Add:
 
 
 
Unrealized gain on derivatives
$
(24.6
)
 
$
(24.5
)
Realized gain (loss) on derivatives, not included in net income (loss)
1.5

 
(1.3
)
Amortization of turnaround costs
5.8

 
2.6

Non-cash equity based compensation and other non-cash items
3.6

 
2.9

Adjusted EBITDA
$
82.7

 
$
80.0

Less:
 
 
 
Replacement and environmental capital expenditures (1)
$
5.8

 
$
16.4

Cash interest expense (2)
24.3

 
23.1

Turnaround costs
3.0

 
13.9

Income tax expense
0.2

 
0.2

Distributable Cash Flow
$
49.4

 
$
26.4

 
(1) 
Replacement capital expenditures are defined as those capital expenditures which do not increase operating capacity or reduce operating costs and exclude turnaround costs. Environmental capital expenditures include asset additions to meet or exceed environmental and operating regulations.

(2) 
Represents consolidated interest expense less non-cash interest expense.

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Table of Contents

 
Three Months Ended March 31,
 
2014
 
2013
 
(In millions)
Reconciliation of Distributable Cash Flow, Adjusted EBITDA and EBITDA to Net cash provided by (used in) operating activities:
 
 
 
Distributable Cash Flow
$
49.4

 
$
26.4

Add:
 
 
 
Replacement and environmental capital expenditures (1)
5.8

 
16.4

Cash interest expense (2)
24.3

 
23.1

Turnaround costs
3.0

 
13.9

Income tax expense
0.2

 
0.2

Adjusted EBITDA
$
82.7

 
$
80.0

Less:



Unrealized gain on derivative instruments
(24.6
)

(24.5
)
Realized gain (loss) on derivatives, not included in net income (loss)
1.5


(1.3
)
Amortization of turnaround costs
5.8


2.6

Non-cash equity based compensation and other non-cash items
3.6


2.9

EBITDA
$
96.4

 
$
100.3

Add:
 
 
 
Unrealized gain on derivative instruments
(24.6
)

(24.5
)
Cash interest expense (2)
(24.3
)

(23.1
)
Non-cash equity based compensation
3.6


2.9

Amortization of turnaround costs
5.8


2.6

Income tax expense
(0.2
)

(0.2
)
Provision for doubtful accounts
0.6


0.3

Debt extinguishment costs
(70.9
)
 
—

Changes in assets and liabilities:
 
 
 
Accounts receivable
(54.1
)

(85.9
)
Inventories
(51.3
)

(51.4
)
Other current assets
5.8


(1.7
)
Turnaround costs
(3.0
)

(13.9
)
Derivative activity
1.5


(1.3
)
Accounts payable
163.2


82.6

Accrued interest payable
(7.4
)

5.3

Accrued income taxes payable
—


(27.6
)
Other current liabilities
(2.0
)

1.9

Other, including changes in noncurrent liabilities
0.5


(0.1
)
Net cash provided by (used in) operating activities
$
39.6

 
$
(33.8
)
 
(1) 
Replacement capital expenditures are defined as those capital expenditures which do not increase operating capacity or reduce operating costs and exclude turnaround costs. Environmental capital expenditures include asset additions to meet or exceed environmental and operating regulations.

(2) 
Represents consolidated interest expense less non-cash interest expense.


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Table of Contents

Changes in Results of Operations for the Three Months Ended March 31, 2014 and 2013
Sales. Sales increased $22.4 million, or 1.7%, to $1,341.0 million in the three months ended March 31, 2014 from $1,318.6 million in the same period in 2013. The results of operations related to the San Antonio and Crude Oil Logistics Acquisitions have been included in the fuel products segment since their dates of acquisition, January 2, 2013 and August 9, 2013, respectively. The results of operations related to the Bel-Ray and United Petroleum Acquisitions have been included in the specialty products segment since their dates of acquisition, December 10, 2013 and February 28, 2014, respectively. Sales for each of our principal product categories in these periods were as follows: 
 
Three Months Ended March 31,
 
2014

2013

% Change
 
(Dollars in millions, except barrel and per barrel data)
Sales by segment:





Specialty products:





Lubricating oils
$
197.7

 
$
239.9

 
(17.6
)%
Solvents
131.4


131.7


(0.2
)%
Waxes
35.4


32.8


7.9
 %
Packaged and synthetic specialty products (1)
76.4


59.5


28.4
 %
Other (2)
9.1


10.4


(12.5
)%
Total specialty products
$
450.0


$
474.3


(5.1
)%
Total specialty products sales volume (in barrels)
2,326,000


2,610,000


(10.9
)%
Average specialty products sales price per barrel
$
193.47


$
181.72


6.5
 %
 
 
 
 
 
 
Fuel products:





Gasoline
$
365.3


$
331.1


10.3
 %
Diesel
324.6


308.5


5.2
 %
Jet fuel
44.2


50.8


(13.0
)%
Asphalt, heavy fuel oils and other (3)
170.0


161.5


5.3
 %
Hedging activities gain (loss)
(13.1
)
 
(7.6
)

72.4
 %
Total fuel products
$
891.0


$
844.3


5.5
 %
Total fuel products sales volume (in barrels)
8,247,000


7,451,000


10.7
 %
Average fuel products sales price per barrel (excluding hedging activities)
$
109.63


$
114.33


(4.1
)%
Average fuel products sales price per barrel (including hedging activities)
$
108.04


$
113.31


(4.7
)%
 
 
 
 
 
 
Total sales
$
1,341.0


$
1,318.6


1.7
 %
Total sales volume (in barrels)
10,573,000


10,061,000


5.1
 %
 
(1) 
Represents production of packaged and synthetic specialty products at the Royal Purple, Bel-Ray, Calumet Packaging and Missouri facilities.
(2) 
Represents by-products, including fuels and asphalt, produced in connection with the production of specialty products at the Princeton and Cotton Valley refineries and Dickinson and Karns City facilities.
(3) 
Represents asphalt, heavy fuel oils and other products produced in connection with the production of fuels at the Shreveport, Superior, San Antonio and Montana refineries and purchased crude oil sales from the Superior, Shreveport and San Antonio refineries to third party customers.
The components of the $24.3 million specialty products segment sales decrease in the three months ended March 31, 2014 were as follows:

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Table of Contents

 
Dollar Change
 
(In millions)
Volume
$
(54.1
)
Sales price
19.5

Acquisitions
10.3

Total specialty products segment sales decrease
$
(24.3
)
Specialty products segment sales decreased $24.3 million quarter over quarter, or 5.1%, primarily as a result of lower sales volumes, partially offset by increased average selling prices per barrel and incremental sales from the Bel-Ray Acquisition. Legacy operations’ sales volumes decreased 11.4% as compared to the same period in 2013, which resulted in a $54.1 million decrease in sales. The decrease in sales volume is due primarily to lower sales volumes of lubricating oils at the Shreveport refinery and third party processing sites due to various reliability and operational issues, partially offset by increased sales volumes of packaged and synthetic specialty products and solvents. Legacy operations’ sales increased $19.5 million compared to the first quarter of 2013 due to a 4.6% increase in average selling prices per barrel primarily as a result of product mix.
The components of the $46.7 million fuel products segment sales increase for the three months ended March 31, 2014 were as follows:
 
Dollar Change
 
(In millions)
Volume
$
91.0

Sales price
(38.8
)
Hedging activities
(5.5
)
Total fuel products segment sales increase
$
46.7

Fuel products segment sales increased $46.7 million quarter over quarter, or 5.5%, primarily due to increased sales volume, partially offset by decreased average selling prices per barrel and a $5.5 million increase in realized derivative losses recorded in sales on our fuel products cash flow hedges. Sales volumes increased 10.7% primarily due to increased sales volume of gasoline and diesel as a result of market conditions, increased production at the San Antonio refinery as a result of the crude oil unit expansion completed in December 2013 and increased crude oil sales to third party customers as we continued to grow our crude oil gathering business. Average selling prices per barrel (excluding the impact of hedging activities reflected in sales) decreased $4.70, or 4.1%, resulting in a $38.8 million decrease in sales, compared to a 4.2% increase in the average price of crude oil per barrel. The decrease in average selling prices per barrel is primarily due to gasoline and diesel average selling prices per barrel as a result of decreased crack spreads.



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Table of Contents

Gross Profit. Gross profit decreased $9.6 million, or 7.1%, to $124.8 million in the three months ended March 31, 2014 from $134.4 million in the same period in 2013. Gross profit for our specialty products and fuel products segments were as follows:
 
 
Three Months Ended March 31,
 
2014
 
2013
 
% Change
 
(Dollars in millions, except per barrel data)
Gross profit by segment:
 
 
 
 
 
Specialty products:
 
 
 
 
 
Gross profit
$
98.2

 
$
84.8

 
15.8
 %
Percentage of sales
21.8
%
 
17.9
%
 
 
Specialty products gross profit per barrel
$
42.22

 
$
32.49

 
29.9
 %
Fuel products:
 
 
 
 
 
Gross profit excluding hedging activities
$
30.2

 
$
61.5

 
(50.9
)%
Hedging activities
(3.6
)
 
(11.9
)
 
(69.7
)%
Gross profit
$
26.6

 
$
49.6

 
(46.4
)%
Percentage of sales
3.0
%
 
5.9
%
 
 
Fuel products gross profit per barrel (excluding hedging activities)
$
3.66

 
$
8.25

 
(55.6
)%
Fuel products gross profit per barrel (including hedging activities)
$
3.23

 
$
6.66

 
(51.5
)%
Total gross profit
$
124.8

 
$
134.4

 
(7.1
)%
Percentage of sales
9.3
%
 
10.2
%
 
 
The components of the $13.4 million specialty products segment gross profit increase for the three months ended March 31, 2014 were as follows:
 
Dollar Change
 
(In millions)
Quarter ended March 31, 2013 reported gross profit
$
84.8

Sales price
19.5

Cost of materials
9.4

Acquisitions
3.2

Volume
(14.6
)
Operating costs
(4.1
)
Quarter ended March 31, 2014 reported gross profit
$
98.2

The increase in specialty products segment gross profit of $13.4 million quarter over quarter was due primarily to increased average selling prices per barrel and incremental gross profit of $3.2 million generated from the Bel-Ray Acquisition, partially offset by decreased sales volume and higher operating costs. Sales price and cost of materials, net, from our legacy operations increased gross profit by $28.9 million, as the average selling price per barrel increased 4.6%, while the average cost of crude oil per barrel decreased by 2.3%. As discussed above, the majority of this variance is due to product mix as a result of increased packaged and synthetic specialty products sales. Further reducing gross profit were increased operating costs of $4.1 million primarily as a result of higher natural gas costs.
The components of the $23.0 million fuel products segment gross profit decrease for the three months ended March 31, 2014 were as follows:

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Table of Contents

 
Dollar Change
 
(In millions)
Quarter ended March 31, 2013 reported gross profit
$
49.6

Sales price
(38.8
)
Cost of materials
(4.3
)
Operating costs
(3.5
)
Volume
15.3

Hedging activities
8.3

Quarter ended March 31, 2014 reported gross profit
$
26.6

The decrease in fuel products segment gross profit of $23.0 million quarter over quarter was due primarily to decreased gross profit as a result of narrowing crack spreads as the average cost of crude oil per barrel increased and average selling prices per barrel decreased. Further reducing gross profit were higher operating costs of $3.5 million due primarily to higher natural gas prices and higher repair and maintenance costs. These decreases were partially offset by decreased realized losses on derivatives of $8.3 million.
Selling. Selling expenses increased $3.1 million, or 19.5%, to $19.0 million in the three months ended March 31, 2014 from $15.9 million in the same period in 2013. The increase was due primarily to incremental selling expenses related to the Bel-Ray Acquisition.
General and administrative. General and administrative expenses increased $0.8 million, or 3.2%, to $25.9 million in the three months ended March 31, 2014 from $25.1 million in the same period in 2013. The increase was due primarily to incremental general and administrative expenses related to the Bel-Ray Acquisition and increased incentive compensation costs.
Transportation. Transportation expenses increased $5.0 million, or 14.1%, to $40.4 million in the three months ended March 31, 2014 from $35.4 million in the same period in 2013. This increase was due primarily to increased crude oil sales to third parties, partially offset by decreased lubricating oil sales.
Interest expense. Interest expense increased $1.4 million, or 5.6%, to $26.2 million in the three months ended March 31, 2014 from $24.8 million in the same period in 2013, due primarily to additional outstanding long-term debt in the form of 2022 Notes.
Debt extinguishment costs. Debt extinguishment costs were $89.6 million in three months ended March 31, 2014. Debt extinguishment costs were due to the redemption of the remaining 2019 Notes with a portion of the net proceeds from the issuance of the 2021 Notes.
Derivative activity. The following table details the impact of our derivative instruments on the unaudited condensed consolidated statements of operations for the three months ended March 31, 2014 and 2013.
 
 
Three Months Ended March 31,
 
2014
 
2013
 
(In millions)
Derivative loss reflected in sales
$
(13.1
)
 
$
(7.6
)
Derivative gain (loss) reflected in cost of sales
9.2

 
(4.0
)
Derivative losses reflected in gross profit
$
(3.9
)
 
$
(11.6
)
 
 
 
 
Realized gain (loss) on derivative instruments
$
6.6

 
$
(8.6
)
Unrealized gain on derivative instruments
24.6

 
24.5

Derivative gain reflected in interest expense
0.3

 
—

Total derivative gain reflected in the unaudited condensed consolidated statements of operations
$
27.6

 
$
4.3

Total gain (loss) on commodity derivative settlements
$
4.2

 
$
(21.5
)
Realized gain (loss) on derivative instruments. Realized gain (loss) on derivative instruments increased $15.2 million to a $6.6 million gain in the three months ended March 31, 2014 from an $8.6 million loss in the prior period. The change was due primarily to approximately $9.9 million in increased hedging ineffectiveness related to settlements of cash flow hedges and

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approximately $3.5 million in increased realized gains on settlements of derivative instruments used to economically hedge crack spreads that are not classified as hedges for accounting purposes.
Unrealized gain on derivative instruments. Unrealized gain on derivative instruments increased $0.1 million to $24.6 million in the three months ended March 31, 2014 from $24.5 million in the prior period. The change is due primarily to increased unrealized gains of approximately $2.8 million of gain ineffectiveness, partially offset decreased unrealized gains of approximately $2.3 million related to derivative instruments used to economically hedge crack spreads that are not accounted for as hedges for accounting purposes.



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Liquidity and Capital Resources
General
The following should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” included under Part II, Item 7 in our 2013 Annual Report. There have been no material changes in that information other than as discussed below. Also, see Note 8 — “Long-Term Debt” and Note 5— “Investment in Unconsolidated Affiliates” under Part I, Item 1 “Financial Statements—Notes to Unaudited Condensed Consolidated Financial Statements” in this Quarterly Report for additional discussion related to our long-term debt and our investment in our joint venture with MDU.
Our principal sources of cash have historically included cash flow from operations, proceeds from public equity offerings, proceeds from notes offerings and bank borrowings. Principal uses of cash have included capital expenditures, acquisitions, distributions to our limited partners and general partner and debt service. We expect that our principal uses of cash in the future will be for distributions to our unitholders and general partner, debt service, replacement and environmental capital expenditures, capital expenditures related to internal growth projects, and acquisitions from third parties or affiliates.
We expect to fund future capital expenditures with current cash flow from operations and borrowings under our revolving credit facility. Future internal growth projects or acquisitions may require expenditures in excess of our then-current cash flow from operations and borrowing availability under our existing revolving credit facility and may require us to issue debt or equity securities in public or private offerings or incur additional borrowings under bank credit facilities to meet those costs.
Cash Flows from Operating, Investing and Financing Activities
We believe that we have sufficient liquid assets, cash flow from operations and borrowing capacity to meet our financial commitments, debt service obligations and anticipated capital expenditures. However, we are subject to business and operational risks that could materially adversely affect our cash flows. A material decrease in our cash flow from operations including a significant, sudden decrease in crude oil prices would likely produce a corollary material adverse effect on our borrowing capacity under our revolving credit facility and potentially our ability to comply with the covenants under our revolving credit facility. A significant, sudden increase in crude oil prices, if sustained, would likely result in increased working capital requirements which would be funded by borrowings under our revolving credit facility. In addition, our cash flow from operations may be impacted by the timing of settlement of our derivative activities. Gains and losses from derivative instruments that qualify as effective cash flow hedges are deferred in accumulated other comprehensive income (loss), but may impact operating cash flow in the period settled. Gains and losses from derivative instruments that do not qualify as hedges are recorded in unrealized gain (loss) until settlement and will impact operating cash flow in the period settled.
The following table summarizes our primary sources and uses of cash in each of the periods presented:
 
 
Three Months Ended March 31,
 
2014
 
2013
 
(In millions)
Net cash provided by (used in) operating activities
$
39.6

 
$
(33.8
)
Net cash used in investing activities
(309.3
)
 
(148.0
)
Net cash provided by financing activities
328.2

 
160.1

Net increase (decrease) in cash and cash equivalents
$
58.5

 
$
(21.7
)
Operating Activities. Operating activities provided cash of $39.6 million during the three months ended March 31, 2014 compared to using cash of $33.8 million during the same period in 2013. The change is due primarily to decreased working capital requirements, primarily accounts payable, for the three months ended March 31, 2014 compared to the same period in 2013.
Investing Activities. Cash used in investing activities increased to $309.3 million during the three months ended March 31, 2014 compared to $148.0 million during the prior year period. The increase is due primarily to the higher combined purchase price of $247.0 million for the Anchor and United Petroleum Acquisitions, which closed in 2014, compared to a purchase price of $117.7 million for the San Antonio Acquisition which closed in 2013, an increase in capital expenditures of $25.2 million due primarily to the capital improvement projects discussed below and an increase of $6.8 million related to contributions to the Dakota Prairie Refining, LLC joint venture.

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Financing Activities. Financing activities provided cash of $328.2 million in the three months ended March 31, 2014 compared to $160.1 million during the prior year period. This change is due primarily to net proceeds from the private placement of senior notes of $884.1 million in the three months ended March 31, 2014 with no such proceeds in the 2013 period. Partially offsetting this increase is the redemption of the remaining 2019 Notes of $500.0 million, net proceeds from a public offering of common units (including our general partner’s contributions) of $179.2 million with no such proceeds in the 2014 period, decreased revolving credit facility borrowings of $29.2 million and increased distributions to our unitholders of $8.1 million.
Acquisitions
Acquisitions impact our results of operations commencing on the closing date of each acquisition. Our acquisitions are discussed further in Note 3 of Part I, Item 1 “Financial Statements—Acquisitions” for additional information. Information regarding acquisitions completed during the three months ended March 31, 2014 and 2013 is set forth in the table below (in millions):
Acquisition
 
Closing Date
 
Purchase Price
 
Funding Method
 
Segment
Anchor
 
March 31, 2014
 
$
236.6

 
Net proceeds from our March 2014 private placement of 2021 Notes
 
Specialty Products
United Petroleum
 
February 28, 2014
 
10.4

 
Cash on hand
 
Specialty Products
2014 Total
 
 
 
$
247.0

 
 
 
 
 
 
 
 
 
 
 
 
 
San Antonio
 
January 2, 2013
 
$
117.9

 
Borrowings under our revolving credit facility and cash on hand
 
Fuel Products
Bel-Ray
 
December 10, 2013
 
53.6

 
Net proceeds from our November 2013 private placement of 2022 Notes
 
Specialty Products
2013 Total
 
 
 
$
171.5

 
 
 
 
Joint Venture
On February 7, 2013, we entered into a joint venture agreement with MDU to develop, build and operate a diesel refinery in southwestern North Dakota. The joint venture is named Dakota Prairie Refining, LLC. The refinery is expected to process 20,000 bpd of Bakken crude oil to primarily serve diesel demand in the region. Construction of the refinery began during the first quarter of 2013 with startup of the refinery expected late in the fourth quarter of 2014. 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 us 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 be repaid by us through our 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 us and MDU expected to occur in 2014. During the three months ended March 31, 2014, we had contributed $16.0 million to the Dakota Prairie Refining, LLC joint venture, funded primarily through cash flow from operations. The joint venture will allocate profits on a 50%/50% basis to us and MDU. We are covering the debt service cost of the lower interest rate term loan facility pursuant to the joint venture agreement. The joint venture is governed by a board of managers comprised of representatives from both us and MDU. MDU is to provide a portion of the crude oil supply to the refinery, as well as natural gas and electricity utility services. We are providing refinery operations, crude oil procurement and refined product marketing expertise to the joint venture.
Capital Expenditures
Our property, plant and equipment capital expenditure requirements consist of capital improvement expenditures, replacement capital expenditures and environmental capital expenditures. Capital improvement expenditures include expenditures to acquire assets to grow our business, to expand existing facilities, such as projects that increase operating capacity, or to reduce operating costs. Replacement capital expenditures replace worn out or obsolete equipment or parts. Environmental capital expenditures include asset additions to meet or exceed environmental and operating regulations.
The following table sets forth our capital improvement expenditures, replacement capital expenditures and environmental capital expenditures in each of the periods shown.
 

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Three Months Ended March 31,
 
2014
 
2013
 
(In millions)
Capital improvement expenditures
$
43.8

 
$
4.7

Replacement capital expenditures
3.2

 
7.9

Environmental capital expenditures
2.6

 
8.5

Total
$
49.6

 
$
21.1

We anticipate that future capital expenditure requirements will be provided primarily through cash flow from operations, cash on hand and available borrowings under our revolving credit facility.
We estimate our replacement and environmental capital expenditures will be approximately $50.0 million to $60.0 million for 2014. These estimated amounts for 2014 include a portion of the $6.0 million to $8.0 million in environmental projects to be spent over the next year as required by our settlement with the LDEQ under the “Small Refinery and Single Site Refining Initiative.” Please read Note 7 of Part I, Item 1 “Financial Statements—Commitments and Contingencies—Environmental — Occupational Health and Safety” for additional information.
We have several capital improvement projects underway including capacity expansions at certain of our facilities, as well as active investments, such as the joint venture with MDU. We currently estimate that these organic growth opportunities could lead to capital improvement expenditures between 2014 and the first quarter of 2016 of approximately $400.0 million to $450.0 million. We estimate we will spend approximately $270.0 million to $300.0 million in 2014 on capital investment in growth projects. Our primary capital improvements projects include the following:
•
Montana Refinery Expansion - We plan to increase our Montana refinery’s crude oil throughput capacity from 10,000 bpd to 20,000 bpd, including a new 20,000 bpd crude oil unit (“Montana Refinery Expansion”). The incremental production slate will consist primarily of gasoline, diesel, jet fuel and diluent, all of which will be sold into regional markets. We anticipate the total cost of the Montana Refinery Expansion to be approximately $400.0 million, which we expect to be completed by the first quarter of 2016.
•
Dakota Prairie Refining, LLC - We have entered into a joint venture agreement with MDU to develop, build and operate a 20,000 bpd diesel refinery in southwestern North Dakota. Please read — “Joint Venture” above for additional information.
Turnaround costs represent capitalized costs associated with our periodic major maintenance and repairs. During the three months ended March 31, 2014, we spent approximately $3.0 million funded through cash flow from operations. Additionally, we estimate turnaround spending requirements will be approximately $20.0 million to $25.0 million for 2014 primarily related to scheduled turnaround activity at our Shreveport refinery. We expect these expenditures will be funded primarily through cash flow from operations.
Debt and Credit Facilities
As of March 31, 2014, our primary debt and credit instruments consisted of:
•
an $850.0 million senior secured revolving credit facility maturing in June 2016, 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;
•
$275.0 million of 9.625% senior notes due 2020 (“2020 Notes”);
•
$900.0 million of 6.50% senior notes due 2021 (“2021 Notes”); and
•
$350.0 million of 7.625% senior notes due 2022 (“2022 Notes”).
We believe we were in compliance with all covenants under the debt instruments in place as of March 31, 2014 and have adequate liquidity to conduct our business.

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Short Term Liquidity
As of March 31, 2014, our principal sources of short-term liquidity were (i) $533.6 million of availability under our revolving credit facility and (ii) $179.6 million of cash. Borrowings under our revolving credit facility can be used for, among other things, working capital, capital expenditures, and other lawful partnership purposes including acquisitions.
Borrowings under the revolving credit facility are limited to a borrowing base that is determined based on advance rates of percentages of Eligible Accounts Receivable and Eligible Inventory (as defined in the revolving credit agreement). As such, the borrowing base can fluctuate based on changes in selling prices of our products and our current material costs, primarily the cost of crude oil. On March 31, 2014, we had availability on our revolving credit facility of $533.6 million, based on a $705.4 million borrowing base, $171.8 million in outstanding standby letters of credit and no outstanding borrowings. The borrowing base cannot exceed the revolving credit facility commitments then in effect. The lender group under our revolving credit facility is comprised of a syndicate of thirteen lenders with total commitments of $850.0 million. The lenders under our revolving credit facility have a first priority lien on our cash, accounts receivable, inventory and certain other personal property.
Amounts outstanding under our revolving credit facility fluctuate materially during each quarter mainly due to normal changes in working capital, payments of quarterly distributions to unitholders and debt service costs. Specifically, the amount borrowed under our revolving credit facility is typically at its highest level after we pay for the majority of our crude oil supplies on the 20th day of every month per standard industry terms. The maximum revolving credit facility borrowings during the quarter ended March 31, 2014 were $5.0 million. Our availability on our revolving credit facility during the peak borrowing days of the quarter has been ample to support our operations and service upcoming requirements. During the quarter ended March 31, 2014, availability for additional borrowings under our revolving credit facility was approximately $439.2 million at its lowest point. We believe that we will continue to have sufficient cash flow from operations and borrowing availability under our revolving credit facility to meet our financial commitments, minimum quarterly distributions to our unitholders, debt service obligations, debt instrument covenants, contingencies and anticipated capital expenditures.
The revolving credit facility currently bears interest at a rate equal to prime plus a basis points margin or LIBOR plus a basis points margin, at our option. As of March 31, 2014, this margin was 100 basis points for prime and 225 basis points for LIBOR; however, the margin can fluctuate quarterly based on our average availability for additional borrowings under the revolving credit facility in the preceding calendar quarter.
In addition to paying interest on outstanding borrowings under the revolving credit facility, we are required to pay a commitment fee to the lenders under the revolving credit facility with respect to the unutilized commitments thereunder at a rate equal to either 0.375% or 0.50% per annum depending on the average daily available unused borrowing capacity for the preceding month. We also pay a customary letter of credit fee, including a fronting fee of 0.125% per annum of the stated amount of each outstanding letter of credit, and customary agency fees.
Our revolving credit facility contains various covenants that limit, among other things, our ability to: incur indebtedness; grant liens; dispose of certain assets; make certain acquisitions and investments; redeem or prepay other debt or make other restricted payments such as distributions to unitholders; enter into transactions with affiliates; and enter into a merger, consolidation or sale of assets. The revolving credit facility generally permits us to make cash distributions to our unitholders as long as immediately after giving effect to such a cash distribution we have cash and availability under the revolving credit facility totaling at least the greater of (i) 15% of the lesser of (a) the Borrowing Base (as defined in the credit agreement) without giving effect to the LC Reserve (as defined in the credit agreement) and (b) the revolving credit facility commitments then in effect and (ii) $45.0 million. Further, the revolving credit facility contains one springing financial covenant which provides that only if our availability under the revolving credit facility falls below the greater of (i) 12.5% of the lesser of (a) the Borrowing Base (as defined in the credit agreement) (without giving effect to the LC Reserve (as defined in the credit agreement)) and (b) the credit agreement commitments then in effect and (ii) $46.4 million, we will be required to maintain as of the end of each fiscal quarter a Fixed Charge Coverage Ratio (as defined in the credit agreement) of at least 1.0 to 1.0.
If an event of default exists under the revolving credit facility, the lenders will be able to accelerate the maturity of the credit facility and exercise other rights and remedies. An event of default includes, among other things, the nonpayment of principal, interest, fees or other amounts; failure of any representation or warranty to be true and correct when made or confirmed; failure to perform or observe covenants in the revolving credit facility or other loan documents, subject, in limited circumstances, to certain grace periods; cross-defaults in other indebtedness if the effect of such default is to cause, or permit the holders of such indebtedness to cause, the acceleration of such indebtedness under any material agreement; bankruptcy or insolvency events; monetary judgment defaults; asserted invalidity of the loan documentation; and a change of control.
As of March 31, 2014, we were in compliance with all covenants under the revolving credit facility.

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For additional information regarding our revolving credit facility, see Note 8 of Part I, Item 1 “Financial Statements—Long-Term Debt” in this Quarterly Report and Note 7 “Long-Term Debt” in Part II, Item 8 “Financial Statements and Supplementary Data” in our 2013 Annual Report.
Long-Term Financing
In addition to our principal sources of short-term liquidity listed above, we can meet our cash requirements (other than distributions of cash from operations to our common unitholders) through the issuance of long-term notes or additional common units.
From time to time we issue long-term debt securities, referred to as our senior notes. All of our outstanding senior notes are unsecured obligations that rank equally with all of our other senior debt obligations to the extent they are unsecured. As of March 31, 2014, we had $275.0 million in 2020 Notes, $900.0 million in 2021 Notes and $350.0 million in 2022 Notes outstanding. As of December 31, 2013, we had $500.0 million in 2019 Notes, $275.0 million in 2020 Notes and $350.0 million in 2022 Notes outstanding.
The indentures governing our senior notes contain covenants that, among other things, restrict our ability and the ability of certain of our subsidiaries to: (i) sell assets; (ii) pay distributions on, redeem or repurchase our common units or redeem or repurchase 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 our restricted subsidiaries to us; (vii) consolidate, merge or transfer all or substantially all of our assets; (viii) engage in transactions with affiliates and (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. At any time when the senior 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 senior 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, our Fixed Charge Coverage Ratio (as defined in the indentures governing the 2020, 2021 and 2022 Notes) was 2.3 to 1.0.
Upon the occurrence of certain change of control events, each holder of the senior notes will have the right to require that we repurchase all or a portion of such holder’s senior notes in cash at a purchase price equal to 101% of the principal amount thereof, plus any accrued and unpaid interest to the date of repurchase.
To date, our debt balances have not adversely affected our operations, our ability to grow or our ability to repay or refinance our indebtedness. Based on our historical record, we believe that our capital structure will continue to allow us to achieve our business objectives.
We are subject, however, to conditions in the equity and debt markets for our common units and long-term senior notes, and there can be no assurance we will be able or willing to access the public or private markets for our common units and/or senior notes in the future. If we are unable or unwilling to issue additional common units, we may be required to either restrict capital expenditures and/or potential future acquisitions or pursue debt financing alternatives, some of which could involve higher costs or negatively affect our credit ratings. Furthermore, our ability to access the public and private debt markets is affected by our credit ratings.
For additional information regarding our senior notes, see Note 8 — “Long-Term Debt” under Part I, Item 1 “Financial Statements—Notes to Unaudited Condensed Consolidated Financial Statements” in this Quarterly Report and Note 7 — “Long-Term Debt” in Part II, Item 8 “Financial Statements and Supplementary Data” of our 2013 Annual Report.
Master Derivative Contracts and Collateral Trust Agreement
Under our credit support arrangements, our payment obligations under all of our master derivatives contracts for commodity hedging generally are secured by a first priority lien on our and our subsidiaries’ real property, plant and equipment, fixtures, intellectual property, certain financial assets, certain investment property, commercial tort claims, chattel paper, documents, instruments and proceeds of the foregoing (including proceeds of hedge arrangements). We had no additional letters of credit or cash margin posted with any hedging counterparty as of March 31, 2014. Our master derivatives contracts and Collateral Trust Agreement (as defined below) continue to impose a number of covenant limitations on our operating and financing activities, including limitations on liens on collateral, limitations on dispositions of collateral and collateral maintenance and insurance requirements. For financial reporting purposes, we do not offset the collateral provided to a counterparty against the fair value of our obligation to that counterparty. Any outstanding collateral is released to us upon settlement of the related derivative instrument liability.

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The fair value of our derivatives decreased by approximately $5.0 million subsequent to March 31, 2014 to a net asset of approximately $8.0 million. All credit support thresholds with our hedging counterparties are at levels such that it would take a substantial increase in fuel products crack spreads or interest rates to require significant additional collateral to be posted. As a result, we do not expect further increases in fuel products crack spreads or interest rates to significantly impact our liquidity.
Additionally, we have a collateral trust agreement (the “Collateral Trust Agreement”) which governs how secured hedging counterparties will share collateral pledged as security for the payment obligations owed by us to secured hedging counterparties under their respective master derivatives contracts. The Collateral Trust Agreement limits to $100.0 million the extent to which forward purchase contracts for physical commodities are covered by, and secured under, the Collateral Trust Agreement. There is no such limit on financially settled derivative instruments used for commodity hedging. Subject to certain conditions set forth in the Collateral Trust Agreement, we have the ability to add secured hedging counterparties from time to time.
Equity Transactions
On March 10, 2014, we entered into an Equity Placement Agreement with various sales agents under which we may issue and sell, from time to time, common units representing limited partner interests, having an aggregate offering price of up to $300.0 million through one or more sales agents. The Equity Placement Agreement provides us the right, but not the obligation, to sell common units in the future, at prices we deem appropriate. These sales, if any, will be made pursuant to the terms of the Equity Placement Agreement between us and the sales agents. The net proceeds from any sales under this agreement will be used for general partnership purposes, which may include, among other things, repayment of indebtedness, working capital, capital expenditures and acquisitions. Our general partner will contribute its proportionate capital contribution to retain its 2% general partner interest. For the three months ended March 31, 2014, we had no sales of common units under the Equity Placement Agreement.
During 2014, we have made, or expect to make, the following cash distributions on all outstanding common units (including our general partner’s incentive distribution rights) (in millions except per unit data):
Quarter Ended
 
Declaration Date
 
Record Date
 
Distribution Date
 
Quarterly Distribution per Unit
 
Aggregate Quarterly Distribution
 
Annualized Distribution per Unit
 
Aggregate Annualized Distribution
December 31, 2013
 
January 24, 2014
 
February 4, 2014
 
February 14, 2014
 
$
0.685

 
$
52.6

 
$
2.74

 
$
210.4

March 31, 2014
 
April 22, 2014
 
May 5, 2014
 
May 15, 2014
 
$
0.685

 
$
52.5

 
$
2.74

 
$
210.0

Contractual Obligations and Commercial Commitments
A summary of our total contractual cash obligations as of March 31, 2014 at current maturities and reflects only those line items that have materially changed since December 31, 2013 is as follows:
 
 
 
Payments Due by Period
 
Total

Less Than
1 Year

1-3
Years

3-5
Years

More Than
5 Years
 
(In millions)
Operating activities:









Interest on long-term debt at contractual rates and maturities (1)
$
786.9


$
95.9


$
229.2


$
223.9


$
237.9

Operating lease obligations (2)
149.0


32.9


52.2


37.4


26.5

Letters of credit (3)
171.8


171.8


—


—


—

Purchase commitments (4)
1,611.1


1,605.0


5.8


0.3


—

Financing activities:









Capital lease obligations
4.6


0.4


0.6


0.7


2.9

Long-term debt obligations, excluding capital lease obligations
1,525.0


—


—


—


1,525.0

Total obligations
$
4,248.4


$
1,906.0


$
287.8


$
262.3


$
1,792.3


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(1) 
Interest on long-term debt at contractual rates and maturities relates primarily to interest on our senior notes, revolving credit facility fees and interest on our capital lease obligations, which excludes the adjustment for the interest rate swap agreement.
(2) 
We have various operating leases primarily for railcars, the use of land, storage tanks, compressor stations, equipment, precious metals and office facilities that extend through May 2027.
(3) 
Letters of credit primarily supporting crude oil purchases and precious metals leasing.
(4) 
Purchase commitments consist primarily of obligations to purchase fixed volumes of crude oil, other feedstocks, finished products for resale and renewable fuels from various suppliers based on current market prices at the time of delivery.
In connection with the closing of the acquisition of Penreco on January 3, 2008, we entered into a feedstock purchase agreement with Phillips 66 related to the LVT unit at its Lake Charles, Louisiana refinery (the “LVT Feedstock Agreement”). Pursuant to the LVT Feedstock Agreement, Phillips 66 is obligated to supply a minimum quantity (the “Base Volume”) of feedstock for the LVT unit for a term of ten years. Based upon this minimum supply quantity, we expect to purchase $72.1 million of feedstock for the LVT unit in each fiscal year of the term based on pricing estimates as of March 31, 2014. This amount is not included in the table above.
For additional information regarding our expected capital and turnaround expenditures for the remainder of 2014, for which we have not contractually committed, refer to “Capital Expenditures” above.
Off-Balance Sheet Arrangements
We did not enter into any material off-balance sheet debt or operating lease transactions during the three months ended March 31, 2014.
Critical Accounting Policies and Estimates
For additional discussion regarding our critical accounting policies and estimates, see “Critical Accounting Policies and Estimates” under Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2013 Annual Report.
Recent Accounting Pronouncements
For additional discussion regarding recent accounting pronouncements, see Note 2 — “New and Recently Adopted Accounting Pronouncements” under Part I, Item 1 “Financial Statements—Notes to Unaudited Condensed Consolidated Financial Statements.”
Item 3. Quantitative and Qualitative Disclosures About Market Risk
The following should be read in conjunction with “Quantitative and Qualitative Disclosures About Market Risk” included under Part II, Item 7A in our 2013 Annual Report. There have been no material changes in that information other than as discussed below. Also, see Note 9 — “Derivatives” under Part I, Item 1 “Financial Statements—Notes to Unaudited Condensed Consolidated Financial Statements” in this Quarterly Report for additional discussion related to derivative instruments and hedging activities.
Commodity Price Risk
Derivative Instruments
We are exposed to price risks due to fluctuations in the price of crude oil, refined products (primarily in our fuel products segment) and natural gas. We use various strategies to reduce our exposure to commodity price risk. We do not attempt to eliminate all of our risk as the costs of such actions are believed to be too high in relation to the risk posed to our future cash flows, earnings and liquidity. The strategies to reduce our risk utilize both physical forward contracts and financially settled derivative instruments, such as swaps, collars and options, to attempt to reduce our exposure with respect to:
•crude oil purchases and sales;
•refined 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, LLS, WCS, MSW and Brent.
As of March 31, 2014, we had primarily entered into swap contracts on forecasted purchases from 2014 through 2016 of NYMEX WTI crude oil and forecasted sales of U.S. Gulf Coast ultra-low sulfur diesel, U.S. Gulf Coast jet fuel and U.S. Gulf Coast gasoline. These derivative instruments, on a combined basis, were entered into to hedge a portion of our gross profit in our fuel products segment. We have also entered into basis swap contracts that improve the effectiveness of our crude oil swap contracts by locking in the spread between NYMEX WTI and the crude oil that we are actually purchasing for use by our facilities. Please read Note 9 — “Derivatives” under Part I, Item 1 “Financial Statements—Notes to Unaudited Condensed Consolidated Financial Statements” for additional information of the accounting treatment for the various types of derivative instruments and a further discussion of our hedging policies.
The following table provides a summary of the implied crack spreads for our crude oil and diesel fuel swaps on a combined basis as of March 31, 2014 in our fuel products segment which we disclose in Note 9 — “Derivatives” under Part I, Item 1 “Financial Statements—Notes to Unaudited Condensed Consolidated Financial Statements.”
Crude Oil and Diesel Swap Contracts by Expiration Dates
Barrels
 
BPD
 
Implied Crack Spread ($/Bbl)
Second Quarter 2014
1,137,500

 
12,500

 
$
27.47

Third Quarter 2014
1,472,000


16,000


27.63

Fourth Quarter 2014
1,426,000


15,500


27.59

Calendar Year 2015
5,785,500

 
15,851

 
26.59

Calendar Year 2016
1,830,000

 
5,000

 
27.27

Totals
11,651,000

 
 
 
 
Average price
 
 
 
 
$
27.03

The following table provides a summary of the implied crack spreads for our crude oil and jet fuel swaps on a combined basis as of March 31, 2014 in our fuel products segment which we disclose in Note 9 — “Derivatives” under Part I, Item 1 “Financial Statements—Notes to Unaudited Condensed Consolidated Financial Statements.”
Crude Oil and Jet Swap Contracts by Expiration Dates
Barrels
 
BPD
 
Implied Crack Spread ($/Bbl)
Second Quarter 2014
273,000


3,000


$
25.33

Third Quarter 2014
276,000


3,000


24.83

Fourth Quarter 2014
276,000


3,000


24.30

Calendar Year 2015
957,500


2,623


28.10

Totals
1,782,500





Average price




$
26.58

The following table provides a summary of the implied crack spreads for our crude oil and gasoline fuel swaps on a combined basis as of March 31, 2014 in our fuel products segment which we disclose in Note 9 — “Derivatives” under Part I, Item 1 “Financial Statements—Notes to Unaudited Condensed Consolidated Financial Statements.”
Crude Oil and Gasoline Swap Contracts by Expiration Dates
Barrels
 
BPD
 
Implied Crack Spread ($/Bbl)
Second Quarter 2014
1,638,000

 
18,000

 
$
15.82

Third Quarter 2014
1,610,000

 
17,500

 
13.99

Fourth Quarter 2014
460,000

 
5,000

 
11.82

Calendar Year 2015
45,500

 
125

 
19.00

Totals
3,753,500

 
 
 
 
Average price
 
 
 
 
$
14.58

The following table provides a summary of natural gas swaps as of March 31, 2014 in our specialty products segment which we disclose in Note 9 — “Derivatives” under Part I, Item 1 “Financial Statements—Notes to Unaudited Condensed Consolidated Financial Statements.”

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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

Totals
11,230,000

 

Average price
 
 
$
4.27

Our derivative instruments and overall specialty products segment and fuel products segment hedging positions are monitored regularly by our risk management committee, which includes our executive officers. The risk management committee reviews market information and our hedging positions regularly to determine if additional derivative activity is required. A summary of derivative positions and a summary of hedging strategy are presented to our general partner’s board of directors quarterly.
Holding all other variables constant, we expect a $1 increase in the applicable commodity prices would change our recorded mark-to-market valuation by the following amounts based upon the volumes hedged as of March 31, 2014: 
 
In millions
Crude oil swaps
$
17.2

Crude oil basis swaps
$
0.7

Diesel swaps
$
(11.7
)
Jet fuel swaps
$
(1.8
)
Gasoline swaps
$
(3.8
)
Natural gas swaps
$
11.2

Compliance Price Risk
Renewable Identification Numbers
We are exposed to market risks related to the volatility in the price of credits needed to comply with governmental programs. The EPA sets annual quotas for the percentage of biofuels that must be blended into transportation fuels consumed in the U.S., and as a producer of motor fuels from petroleum, we are required to blend biofuels into the fuel products we produce at a rate that will meet the EPA’s annual quota. To the extent we are unable to blend biofuels at that rate, we must purchase RINs in the open market to satisfy the annual requirement. We have not entered into any derivative instruments to manage this risk, but we have purchased RINs when the price of these instruments is deemed favorable.
Interest Rate Risk
We use various strategies to reduce our expose 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. Our goal is to manage interest rate sensitivity by modifying the pricing characteristics of certain debt instruments so that earnings are not adversely affected by movement in interest rates. During 2014, we entered into an interest rate swap agreement that converted a portion of our senior notes from a fixed interest rate to a variable rate that fluctuates based on changes in the one-month London Interbank Offered Rate (“LIBOR”). We have disclosed this interest rate swap designated as a fair value hedge in Note 9 — “Derivatives” under Part I, Item 1 “Financial Statements—Notes to Unaudited Condensed Consolidated Financial Statements.”
For the balance of our long-term debt that is not subject to interest rate swap arrangements, our exposure to interest rate changes is limited to the fair value of the debt issued, which would not have a material impact on our earnings or cash flows. The following table provides information about the fair value of our fixed rate debt obligations as of March 31, 2014 and December 31, 2013, which we disclose in Note 8 — “Long-Term Debt” and Note 10— “ Fair Value Measurements” under Part I, Item 1 “Financial Statements—Notes to Unaudited Condensed Consolidated Financial Statements.”

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March 31, 2014
 
December 31, 2013
 
Fair Value
 
Carrying Value
 
Fair Value
 
Carrying Value
 
(In millions)
Financial Instrument:
 
 
 
 
 
 
 
2019 Notes
$
—

 
$
—

 
$
554.2

 
$
490.5

2020 Notes
$
318.3

 
$
270.9

 
$
309.4

 
$
270.7

2021 Notes
$
903.4

 
$
900.0

 
$
—

 
$
—

2022 Notes
$
376.3

 
$
343.3

 
$
353.9

 
$
344.8

For our variable rate debt, if any, changes in interest rates generally do not impact the fair value of the debt instrument, but may impact our future earnings and cash flows. We have an $850.0 million revolving credit facility as of March 31, 2014 and December 31, 2013, with borrowings bearing interest at the prime rate or LIBOR, at our option, plus the applicable margin. Borrowings under this facility are variable. We have no variable rate debt outstanding as of March 31, 2014 and December 31, 2013.
Foreign Currency Risk
We have minimal exposure to foreign currency risk and as such the cost of hedging this risk is viewed to be in excess of the benefit of further reductions in our exposure to foreign currency exchange rate fluctuations.
Item 4. Controls and Procedures
(a) Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), as amended, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of March 31, 2014 at the reasonable assurance level.
(b) Changes in Internal Control over Financial Reporting
There was no change in our internal control over financial reporting during the first quarter of 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
On December 10, 2013 and March 31, 2014 we completed the Bel-Ray and Anchor Acquisitions, respectively, which include certain existing information systems and internal controls over financial reporting. We are currently in the process of evaluating and integrating the Bel-Ray and Anchor Acquisitions’ historical internal controls over financial reporting with ours. We expect to complete the integration of the Bel-Ray Acquisition in fiscal year 2014 and the integration of the Anchor Acquisition in fiscal year 2015.

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PART II
Item 1. Legal Proceedings
We are not a party to, and our property is not the subject of, any pending legal proceedings other than ordinary routine litigation incidental to our business. Our operations are subject to a variety of risks and disputes normally incidental to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. The information provided under Note 7 — “Commitments and Contingencies” in Part I, Item 1 “Financial Statements—Notes to Unaudited Condensed Consolidated Financial Statements” is incorporated herein by reference.
Item 1A. Risk Factors

In addition to risks factor set forth below, you should carefully consider the risk factors discussed in Part I Item 1A “Risk Factors” in our 2013 Annual Report, which could materially affect our business, financial condition or future results. There have been no material changes in the risk factors discussed in Part I Item IA “Risk Factors” in our 2013 Annual Report other than with respect to the risk factor discussed below. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

We have historically conducted portions of our operations, and intend to own and operate Anchor, within subsidiaries treated as corporations for U.S. federal income tax purposes. These subsidiaries are, therefore, subject to corporate-level income taxes. We may conduct additional activities in subsidiaries treated as corporations in the future.
We have historically conducted portions of our operations in which we market finished petroleum products to certain customers through a subsidiary that was organized as a corporation. We intend to own and operate Anchor as a subsidiary that is treated as a corporation for U.S. federal income tax purposes. We may also elect to conduct additional operations through corporate subsidiaries in the future. These corporate subsidiaries are obligated to pay corporate income taxes, which reduce each corporation’s cash available for distribution to us and, in turn, to service our debt and make distributions to our unitholders. If the Internal Revenue Service were to successfully assert that this corporation has more tax liability than we anticipate or legislation were enacted that increased the corporate tax rate, our cash available for servicing the debt would be further reduced.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
 
Total Number of Common Units Purchased
 
Average Price Paid per Common Unit
 
Total Number of Common Units Purchased as a Part of Publicly Announced Plans
 
Maximum Number of Common Units that May Yet be Purchased Under Plans
January 1, 2014 - January 31, 2014
—

 
$
—

 
—

 
—

February 1, 2014 - February 28, 2014
—

 
—

 
—

 
—

March 1, 2014 - March 31, 2014 (1)
119,692

 
25.36

 
—

 
—

Total
119,692

 
$
25.36

 
—

 
—

 
(1) 
A total of 119,692 common units were purchased by our general partner, Calumet GP, LLC, related to the Calumet GP, LLC Long-Term Incentive Plan (the “LTIP”) at an average price per common unit of $25.36 for total consideration of approximately $3.0 million. The purchase and sale of these common units was exempt from registration under Section 4(a)(2) of the Securities Act. The LTIP provides for the delivery of up to 783,960 common units to satisfy awards of phantom units, restricted units or unit options to the employees, consultants or directors of the Company. Such units may be newly issued by the Company or purchased in the open market. None of the common units were purchased pursuant to publicly announced plans or programs. The common units were purchased through a single broker in open market transactions. For more information on the LTIP, refer to Part III, Item 11 “Executive and Director Compensation — Compensation Discussion and Analysis — Elements of Executive Compensation — Long-Term, Unit-Based Awards” in our 2013 Annual Report.
Item 3. Defaults Upon Senior Securities
None.

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Item 4. Mine Safety Disclosures
None.
Item 5. Other Information
On May 7, 2014, Calumet GP, LLC, our general partner, entered into an Employment Agreement with each of Jennifer G. Straumins, R. Patrick Murray, II and Timothy R. Barnhart (each, an “Agreement” and collectively, the “Agreements”). Pursuant to the Agreements, Ms. Straumins, the President and Chief Operating Officer of our general partner, will receive an annualized base salary of $360,500, Mr. Murray, the Senior Vice President, Chief Financial Officer and Secretary of our general partner, will receive an annualized base salary of $329,600 and Mr. Barnhart, the Senior Vice President - Operations of our general partner, will receive an annualized base salary of $309,000.
The Agreements are effective as of May 7, 2014 and, unless terminated earlier in accordance with their terms, the Agreements will continue for initial terms of three years. In addition, on each anniversary of the effective date, unless the Agreements have been terminated, the term of the Agreements will automatically be extended for an additional year unless either party provides written notice of non-renewal at least 180 days prior to such anniversary.
Pursuant to the Agreements, Ms. Straumins, Mr. Murray and Mr. Barnhart (collectively, the “Executives”) are eligible to receive (1) annual incentive awards under the applicable incentive or bonus compensation plan based on a target bonus and (2) equity-based compensation under our general partner’s equity-based compensation plans in effect from time to time, each as determined by the board of directors of our general partner or a committee thereof. In addition, if our general partner terminates an Executive’s employment without “cause” (as defined in the Agreements) or if the applicable Executive terminates his or her employment for “good reason” (as defined in the Agreements), so long as such Executive executes (and does not revoke) a release of claims in the form attached to the applicable Agreement, then (a) the general partner will pay the Executive a single lump sum cash payment equal to 150% of the Executive’s base salary and target bonus, as in effect on the termination date, except that if the termination date occurs within 24 months following a “change in control” (as defined in the Agreements), then the Executive will instead be paid a cash payment equal to 300% of the Executive’s base salary and target bonus then in effect, (b) the Executive will be entitled to a pro rata portion of his or her annual incentive award for the year in which the termination occurs upon satisfaction of the performance goals and approval by the board of directors of our general partner, (c) all or a portion of the unvested LTIP awards granted prior to the termination date will immediately become fully vested as of the termination date, depending on whether the unvested LTIP awards are subject to a performance requirement that has not been satisfied as of the termination date and (d) if the Executive timely and properly elects continuation coverage under our general partner’s group health plans pursuant to the Consolidated Omnibus Reconciliation Act of 1985, the Executive will be reimbursed for the difference between the monthly amount the Executive pays for such coverage and the monthly employee contribution amount that active similarly situated employees pay for the same or similar coverage. The Agreements also include certain confidentiality, non-competition and non-solicitation covenants that apply during the period of each Executive’s employment with our general partner and for one year thereafter.
The foregoing description of the Agreements does not purport to be complete and is qualified in its entirety by reference to the full text of the Agreements, copies of which are filed as Exhibits 10.1, 10.2 and 10.3 to this Quarterly Report and are incorporated herein by reference.


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Table of Contents

Item 6. Exhibits
The following documents are filed as exhibits to this Quarterly Report:
Exhibit
Number
 
Description
 
 
 
2.1
 
Securities Purchase Agreement, dated as of March 25, 2014, by and among ADF Holdings, Inc., Calumet Lubricants Co., Limited Partnership, the sellers listed therein, GarMark Advisors II L.L.C., as the sellers’ representative, and Calumet Specialty Products Partners, L.P., as guarantor (incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on March 26, 2014 (File No. 000-51734)).
 
 
 
3.1
 
Certificate of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form S-1 filed with the Commission on October 7, 2005 (File No. 333-128880)).
 
 
 
3.2
 
Amended and Restated Limited Partnership Agreement of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)).
 
 
 
3.3
 
Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on July 11, 2006 (File No. 000-51734)).
 
 
 
3.4
 
Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on April 18, 2008 (File No. 000-51734)).
 
 
 
3.5
 
Certificate of Formation of Calumet GP, LLC (incorporated by reference to Exhibit 3.3 of Registrant’s Registration Statement on Form S-1 filed with the Commission on October 7, 2005 (File No. 333-128880)).
 
 
 
3.6
 
Amended and Restated Limited Liability Company Agreement of Calumet GP, LLC (incorporated by reference to Exhibit 3.2 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)).
 
 
 
4.1
 
Indenture, dated March 31, 2014, by and among the Issuers, the Guarantors and the Trustee, relating to the offering of the 2021 Notes (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on March 31, 2014 (File No. 000-51734)).
 
 
 
4.2
 
Form of 6.50% Senior Note due 2021 (included in Exhibit 4.1).
 
 
 
4.3
 
Registration Rights Agreement, dated March 31, 2014, by and among the Issuers, the Guarantors and the Initial Purchasers, relating to the offering of the 2021 Notes (incorporated by reference to Exhibit 4.3 to the Registrant’s Current Report on Form 8-K filed with the Commission on March 31, 2014 (File No. 000-51734)).
 
 
 
10.1*
 
Employment Agreement, effective as of May 7, 2014, by and between Calumet GP, LLC and Jennifer G. Straumins.
 
 
 
10.2*
 
Employment Agreement, effective as of May 7, 2014, by and between Calumet GP, LLC and R. Patrick Murray, II.
 
 
 
10.3*
 
Employment Agreement, effective as of May 7, 2014, by and between Calumet GP, LLC and Timothy R. Barnhart.
 
 
 
31.1*
 
Sarbanes-Oxley Section 302 certification of F. William Grube.
 
 
 
31.2*
 
Sarbanes-Oxley Section 302 certification of R. Patrick Murray, II.
 
 
 
32.1**
 
Section 1350 certification of F. William Grube and R. Patrick Murray, II.
 
 
 
100.INS*
 
XBRL Instance Document
 
 
 
101.SCH*
 
XBRL Taxonomy Extension Schema Document
 
 
 
101.CAL*
 
XBRL Taxonomy Extension Calculation Linkbase Document
 
 
 
101.DEF*
 
XBRL Taxonomy Extension Definition Linkbase Document
 
 
 
101.LAB*
 
XBRL Taxonomy Extension Label Linkbase Document
 
 
 

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Table of Contents

101.PRE*
 
XBRL Taxonomy Extension Presentation Linkbase Document
 
 
 
*
 
Filed herewith.
**
 
Furnished herewith.


69
Table of Contents

SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 
 
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
 
 
 
 
 
By:
Calumet GP, LLC, its general partner
 
 
 
 
Date:
May 9, 2014
By:
/s/ R. Patrick Murray, II
 
 
 
R. Patrick Murray, II
 
 
 
Senior Vice President, Chief Financial Officer and Secretary of Calumet GP, LLC (Principal Accounting and Financial Officer)
 
 
 
(Authorized Person and Principal Accounting Officer)
 
 
 
 


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Table of Contents

Index to Exhibits
 
Exhibit
Number
 
Description
 
 
 
2.1
 
Securities Purchase Agreement, dated as of March 25, 2014, by and among ADF Holdings, Inc., Calumet Lubricants Co., Limited Partnership, the sellers listed therein, GarMark Advisors II L.L.C., as the sellers’ representative, and Calumet Specialty Products Partners, L.P., as guarantor (incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on March 26, 2014 (File No. 000-51734)).
 
 
 
3.1
 
Certificate of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form S-1 filed with the Commission on October 7, 2005 (File No. 333-128880)).
 
 
 
3.2
 
Amended and Restated Limited Partnership Agreement of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)).
 
 
 
3.3
 
Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on July 11, 2006 (File No. 000-51734)).
 
 
 
3.4
 
Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on April 18, 2008 (File No. 000-51734)).
 
 
 
3.5
 
Certificate of Formation of Calumet GP, LLC (incorporated by reference to Exhibit 3.3 of Registrant’s Registration Statement on Form S-1 filed with the Commission on October 7, 2005 (File No. 333-128880)).
 
 
 
3.6
 
Amended and Restated Limited Liability Company Agreement of Calumet GP, LLC (incorporated by reference to Exhibit 3.2 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)).
 
 
 
4.1
 
Indenture, dated March 31, 2014, by and among the Issuers, the Guarantors and the Trustee, relating to the offering of the 2021 Notes (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on March 31, 2014 (File No. 000-51734)).
 
 
 
4.2
 
Form of 6.50% Senior Note due 2021 (included in Exhibit 4.1).
 
 
 
4.3
 
Registration Rights Agreement, dated March 31, 2014, by and among the Issuers, the Guarantors and the Initial Purchasers, relating to the offering of the 2021 Notes (incorporated by reference to Exhibit 4.3 to the Registrant’s Current Report on Form 8-K filed with the Commission on March 31, 2014 (File No. 000-51734)).
 
 
 
10.1*
 
Employment Agreement, effective as of May 7, 2014, by and between Calumet GP, LLC and Jennifer G. Straumins.
 
 
 
10.2*
 
Employment Agreement, effective as of May 7, 2014, by and between Calumet GP, LLC and R. Patrick Murray, II.
 
 
 
10.3*
 
Employment Agreement, effective as of May 7, 2014, by and between Calumet GP, LLC and Timothy R. Barnhart.
 
 
 
31.1*
 
Sarbanes-Oxley Section 302 certification of F. William Grube.
 
 
 
31.2*
 
Sarbanes-Oxley Section 302 certification of R. Patrick Murray, II.
 
 
 
32.1**
 
Section 1350 certification of F. William Grube and R. Patrick Murray, II.
 
 
 
100.INS*
 
XBRL Instance Document
 
 
 
101.SCH*
 
XBRL Taxonomy Extension Schema Document
 
 
 
101.CAL*
 
XBRL Taxonomy Extension Calculation Linkbase Document
 
 
 
101.DEF*
 
XBRL Taxonomy Extension Definition Linkbase Document
 
 
 
101.LAB*
 
XBRL Taxonomy Extension Label Linkbase Document
 
 
 
101.PRE*
 
XBRL Taxonomy Extension Presentation Linkbase Document

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*
 
Filed herewith.
**
 
Furnished herewith.

72