CLMT-2015.06.30-10Q
Table of Contents

 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
Form 10-Q
 
 
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2015
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
On August 7, 2015, there were 75,760,218 common units outstanding.
 

Table of Contents

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
QUARTERLY REPORT
For the Three and Six Months Ended June 30, 2015
Table of Contents
 
 
Page
 

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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 and estimated annual EBITDA contributions from such 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 Standard, including the prices paid for Renewable Identification Numbers (“RINs”), (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 and (vi) our access to capital to fund capital expenditures and our working capital needs and our ability to obtain debt or equity financing on satisfactory terms, 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, 2014 (“2014 Annual Report”), (ii) Part II, Item 1A “Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2015 (“Q1 Quarterly Report”) and (iii) 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.




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

 
June 30, 2015
 
December 31, 2014
 
(Unaudited)
 
 
 
(In millions, except unit data)
ASSETS
Current assets:
 
 
 
Cash and cash equivalents
$
11.7

 
$
8.5

Accounts receivable:
 
 
 
Trade
295.8

 
326.0

Other
14.4

 
23.8

 
310.2

 
349.8

Inventories
553.3


513.5

Derivative assets
1.2


23.2

Prepaid expenses and other current assets
10.4


9.2

Deferred income taxes
6.1

 
2.3

Total current assets
892.9

 
906.5

Property, plant and equipment, net
1,588.6


1,464.4

Investment in unconsolidated affiliates
170.6


137.3

Goodwill
245.8


245.8

Other intangible assets, net
235.8


257.5

Other noncurrent assets, net
99.5


108.3

Total assets
$
3,233.2

 
$
3,119.8

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
 
 
 
Accounts payable
$
434.9


$
419.9

Accrued interest payable
32.5


37.6

Accrued salaries, wages and benefits
29.2


21.9

Other taxes payable
19.0


17.9

Other current liabilities
67.5


40.0

Current portion of long-term debt
0.6


0.6

Derivative liabilities
18.3


5.6

Total current liabilities
602.0

 
543.5

Deferred income taxes
22.4


32.3

Pension and postretirement benefit obligations
19.2


20.0

Other long-term liabilities
0.9


0.9

Long-term debt, less current portion
1,717.0


1,712.9

Total liabilities
2,361.5

 
2,309.6

Commitments and contingencies



Partners’ capital:
 
 
 
Limited partners’ interest (75,760,218 units and 69,452,233 units, issued and outstanding as of June 30, 2015 and December 31, 2014, respectively)
841.1

 
765.9

General partner’s interest
32.9

 
30.6

Accumulated other comprehensive income (loss)
(2.3
)

13.7

Total partners’ capital
871.7

 
810.2

Total liabilities and partners’ capital
$
3,233.2

 
$
3,119.8

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 June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
2015
 
2014
 
(In millions, except per unit and unit data)
Sales
$
1,156.2


$
1,434.9


$
2,174.8


$
2,775.9

Cost of sales
953.5


1,335.9


1,776.9


2,552.1

Gross profit
202.7

 
99.0

 
397.9

 
223.8

Operating costs and expenses:
 
 
 
 
 
 

Selling
37.8


40.7


76.2


59.7

General and administrative
31.7


20.9


70.9


46.8

Transportation
42.3


41.3


84.3


81.7

Taxes other than income taxes
4.0


3.6


8.0


5.7

Other
3.2


2.8


6.1


4.9

Operating income (loss)
83.7

 
(10.3
)
 
152.4

 
25.0

Other income (expense):
 
 
 
 
 
 
 
Interest expense
(27.4
)

(28.7
)

(54.4
)

(54.9
)
Debt extinguishment costs
(46.6
)

—


(46.6
)

(89.6
)
Realized gain (loss) on derivative instruments
(14.0
)

6.0


(5.1
)

12.6

Unrealized gain (loss) on derivative instruments
5.2


23.6


(22.7
)

48.2

Loss from unconsolidated affiliates
(8.2
)
 
(1.0
)
 
(12.7
)
 
(1.2
)
Other
0.7


0.2


1.5


0.1

Total other income (expense)
(90.3
)
 
0.1

 
(140.0
)
 
(84.8
)
Net income (loss) before income taxes
(6.6
)

(10.2
)

12.4


(59.8
)
Income tax benefit
(9.1
)

(1.9
)

(13.9
)

(1.7
)
Net income (loss)
$
2.5


$
(8.3
)
 
$
26.3

 
$
(58.1
)
Allocation of net income (loss):
 
 
 
 
 
 
 
Net income (loss)
$
2.5


$
(8.3
)

$
26.3


$
(58.1
)
Less:
 
 
 
 
 
 
 
General partner’s interest in net income (loss)
—


(0.2
)

0.5


(1.2
)
General partner’s incentive distribution rights
4.2


3.9


8.4


7.7

Non-vested share based payments
—


—


—


—

Net income (loss) available to limited partners
$
(1.7
)
 
$
(12.0
)
 
$
17.4

 
$
(64.6
)
Weighted average limited partner units outstanding:
 
 
 
 
 
 
 
Basic
76,092,517


69,604,669


73,675,251


69,614,055

Diluted
76,092,517


69,604,669


73,730,189


69,614,055

Limited partners’ interest basic and diluted net income (loss) per unit
$
(0.02
)

$
(0.17
)

$
0.23


$
(0.93
)
Cash distributions declared per limited partner unit
$
0.685


$
0.685


$
1.37


$
1.37

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 June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
2015
 
2014
 
(In millions)
Net income (loss)
$
2.5

 
$
(8.3
)
 
$
26.3

 
$
(58.1
)
Other comprehensive income (loss):
 
 
 
 
 
 
 
Cash flow hedges:
 
 
 
 
 
 
 
Cash flow hedge (gain) loss reclassified to net income (loss)
(11.5
)
 
(1.1
)
 
(9.8
)
 
2.8

Change in fair value of cash flow hedges
(1.1
)
 
8.1

 
(6.2
)
 
50.5

Defined benefit pension and retiree health benefit plans
0.1

 
—

 
0.3

 
0.2

Foreign currency translation adjustment
—

 
0.1

 
(0.3
)
 
0.3

Total other comprehensive income (loss)
(12.5
)
 
7.1

 
(16.0
)
 
53.8

Comprehensive income (loss) attributable to partners’ capital
$
(10.0
)
 
$
(1.2
)
 
$
10.3

 
$
(4.3
)
See accompanying notes to unaudited condensed consolidated financial statements.


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
 
 
Accumulated Other
Comprehensive Income (Loss)
 
Partners’ Capital
 
 
 
 
General
Partner
 
Limited
Partners
 
Total
 
(In millions)
Balance at December 31, 2014
$
13.7

 
$
30.6

 
$
765.9

 
$
810.2

Other comprehensive loss
(16.0
)
 
—

 
—

 
(16.0
)
Net income
—

 
8.9

 
17.4

 
26.3

Common units repurchased for phantom unit grants
—

 
—

 
(3.6
)
 
(3.6
)
Amortization of vested phantom units
—

 
—

 
1.1

 
1.1

Issuances of phantom units, net of taxes withheld
—

 
—

 
(1.4
)
 
(1.4
)
Proceeds from public offerings of common units, net
—

 
—

 
161.5

 
161.5

Contributions from Calumet GP, LLC
—

 
3.5

 
—

 
3.5

Distributions to partners
—

 
(10.1
)
 
(99.8
)
 
(109.9
)
Balance at June 30, 2015
$
(2.3
)
 
$
32.9

 
$
841.1

 
$
871.7

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
 
Six Months Ended June 30,
 
2015

2014
 
(In millions)
Operating activities
 
 
 
Net income (loss)
$
26.3


$
(58.1
)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
 
 
Depreciation and amortization
71.4


65.6

Amortization of turnaround costs
12.7


11.9

Non-cash interest expense
2.9


3.5

Non-cash debt extinguishment costs
9.1

 
18.7

Provision for doubtful accounts
0.2


1.2

Unrealized (gain) loss on derivative instruments
22.7


(48.2
)
Non-cash equity based compensation
5.5


2.9

Deferred income tax benefit
(14.1
)
 
(1.9
)
Lower of cost or market inventory adjustment
0.8

 
(2.9
)
Losses from unconsolidated affiliates
12.7

 
1.2

Other non-cash activities
3.9


2.1

Changes in assets and liabilities:
 
 
 
Accounts receivable
39.4


(120.6
)
Inventories
(40.6
)

(86.7
)
Prepaid expenses and other current assets
4.5


(1.8
)
Derivative activity
(3.5
)

3.8

Turnaround costs
(5.9
)

(22.2
)
Accounts payable
(7.0
)

162.3

Accrued interest payable
(5.1
)

20.9

Accrued salaries, wages and benefits
1.6


(16.0
)
Other taxes payable
1.3


(1.2
)
Other liabilities
21.7


1.9

Pension and postretirement benefit obligations
(0.5
)

(0.5
)
Net cash provided by (used in) operating activities
160.0

 
(64.1
)
Investing activities
 
 
 
Additions to property, plant and equipment
(153.2
)

(105.5
)
Cash paid for acquisitions, net of cash acquired
—


(234.0
)
Investment in unconsolidated affiliates
(46.0
)

(37.5
)
Proceeds from sale of property, plant and equipment
0.2

 
—

Net cash used in investing activities
(199.0
)
 
(377.0
)
Financing activities
 
 
 
Proceeds from borrowings — revolving credit facility
637.3


390.0

Repayments of borrowings — revolving credit facility
(685.0
)

(330.8
)
Repayments of borrowings — senior notes
(275.0
)

(500.0
)
Payments on capital lease obligations
(3.5
)

(0.5
)
Proceeds from senior notes offering
322.6


900.0

Debt issuance costs
(5.6
)

(16.0
)
Proceeds from public offerings of common units, net
161.5


—

Contributions from Calumet GP, LLC
3.5


—

Common units repurchased and taxes paid for phantom unit grants
(3.6
)

(2.1
)
Cash settlement of unit based compensation
—


(0.9
)
Distributions to partners
(110.0
)

(105.1
)
Net cash provided by financing activities
42.2

 
334.6

Net increase (decrease) in cash and cash equivalents
3.2

 
(106.5
)
Cash and cash equivalents at beginning of period
8.5


121.1

Cash and cash equivalents at end of period
$
11.7

 
$
14.6

Supplemental disclosure of non-cash financing and investing activities
 
 
 
Non-cash property, plant and equipment additions
$
61.9

 
$
25.4

See accompanying notes to unaudited condensed consolidated financial statements.

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 June 30, 2015, the Company had 75,760,218 limited partner common units and 1,546,126 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 and waxes and fuel and fuel related products including gasoline, diesel, jet fuel, asphalt and heavy fuel oils, in addition to oilfield services and products. The Company is also engaged in the resale of purchased crude oil to third party customers. The Company is based in Indianapolis, Indiana and owns specialty and fuel products facilities primarily located in northwest Louisiana, northwest Wisconsin, northern Montana, western Pennsylvania, Texas, New Jersey, eastern Missouri and North Dakota. The Company owns and leases oilfield services locations in Texas, Oklahoma, Louisiana, Arkansas, Colorado, Utah, Wyoming, Montana, New Mexico, New York, North Dakota, Pennsylvania and Ohio. The Company owns and leases additional facilities, primarily related to production and distribution of specialty, fuel and oilfield services products, throughout the United States (“U.S.”).
The unaudited condensed consolidated financial statements of the Company as of June 30, 2015 and for the three and six months ended June 30, 2015 and 2014 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 and six months ended June 30, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, 2015. These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s 2014 Annual Report.
2. Summary of Significant Accounting Policies
New Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which supersedes the revenue recognition requirements in Accounting Standards Codification 605, Revenue Recognition. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract. ASU 2014-09 was originally effective for fiscal periods (including interim periods) beginning after December 15, 2016. In June 2015, the FASB voted to defer the effective date by one year, with early adoption permitted as of the original effective date. The final ASU reflecting these changes is expected to be issued later this year. ASU 2014-09 allows for either a full retrospective or a modified retrospective transition method. The Company is currently evaluating the impact of this standard on its condensed consolidated financial statements.
In February 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (“ASU 2015-02”). ASU 2015-02 amends the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. ASU 2015-02 is effective for fiscal periods (including interim periods) beginning after December 15, 2015 and early adoption is permitted. The adoption of ASU 2015-02 is not expected to have an impact on the Company’s condensed consolidated financial statements.
In April 2015, the FASB issued ASU No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03”). ASU 2015-03 requires debt issuance costs to be recognized in the balance sheet as a direct deduction from the related debt liability rather than as an asset. ASU 2015-03 also requires the amortization of debt issuance costs to be reported as interest expense. ASU 2015-03 is effective for fiscal periods (including interim periods) beginning after December 15, 2015 and early adoption is permitted. ASU 2015-03 must be applied

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retrospectively, where the balance sheet of each presented individual period is adjusted to indicate the period-specific impact of using the new guidance. The Company has not yet adopted ASU 2015-03, but the impact of adopting would result in the Company reclassifying approximately $32.3 million and $34.7 million, as of June 30, 2015 and December 31, 2014, respectively, of deferred debt issuance costs from other noncurrent assets to long-term debt in the condensed consolidated balance sheets.
In April 2015, the FASB issued ASU No. 2015-04, Compensation - Retirement Benefits (Topic 715): Practical Expedient for the Measurement Date of an Employer’s Defined Benefit Obligation and Plan Assets (“ASU 2015-04”). ASU 2015-04 provides guidance for the measuring of assets in defined benefit pension plans and other retirement plans if they are on fiscal years that do not end on the last day of a month. ASU 2015-04 is effective for fiscal periods (including interim periods) beginning after December 15, 2015 and early adoption is permitted. The adoption of ASU 2015-04 is not expected to have an impact on the Company’s condensed consolidated financial statements.
In April 2015, the FASB issued ASU No. 2015-05, Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement (“ASU 2015-05”). ASU 2015-05 provides guidance to determine whether a cloud computing agreement includes a software license or should be considered as a service agreement. ASU 2015-05 is effective for fiscal periods (including interim periods) beginning after December 15, 2015 and early adoption is permitted. An entity can elect to adopt the amendments either (1) prospectively to all arrangements entered into or materially modified after the effective date or (2) retrospectively. The Company is currently evaluating the impact of this standard on its condensed consolidated financial statements.
In April 2015, the FASB issued ASU No. 2015-06, Earnings Per Share (Topic 260) - Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions (“ASU 2015-06”). ASU 2015-06 provides guidance for calculating historical earnings per unit under the two-class method, stating that the earnings or losses of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner interest. ASU 2015-06 is effective for fiscal periods (including interim periods) beginning after December 15, 2015 and early adoption is permitted. ASU 2015-06 should be applied retrospectively. The adoption of ASU 2015-06 is not expected to have an impact on the Company’s condensed consolidated financial statements.
In May 2015, the FASB issued ASU 2015-07, Fair Value Measurement (Topic 820) - Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (“ASU 2015-07”). ASU 2015-07 provides guidance that amends the required disclosure of investments for which fair value is measured at net asset value per share (or its equivalent). The amendments remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient. ASU 2015-07 is effective for fiscal periods (including interim periods) beginning after December 15, 2015 and early adoption is permitted. ASU 2015-07 should be applied retrospectively. The Company is currently evaluating the impact of this standard on its condensed consolidated financial statements.
In May 2015, the FASB issued ASU 2015-08, Business Combinations (Topic 805) - Pushdown Accounting - Amendments to SEC Paragraphs Pursuant to Staff Bulletin No. 115 (“ASU 2015-08”). The amendments in ASU 2015-08 amend various SEC paragraphs included in the FASB’s Accounting Standards Codification to reflect the issuance of Staff Accounting Bulletin No. 115 (“SAB 115”). SAB 115 rescinds portions of the interpretive guidance included in the SEC’s Staff Accounting Bulletins series and brings existing guidance into conformity with ASU No. 2014-17, “Business Combinations (Topic 805): Pushdown Accounting,” which provides an acquired entity with an option to apply pushdown accounting in its separate financial statements upon occurrence of an event in which an acquirer obtains control of the acquired entity. The Company adopted the amendments in ASU 2015-08, effective May 8, 2015, as the amendments in the update are effective upon issuance. The adoption did not have an impact on the Company’s condensed consolidated financial statements.
In June 2015, the FASB issued ASU 2015-10, Technical Corrections and Improvements (“ASU 2015-10”). With regard to fair value measurement disclosures, ASU 2015-10 clarified that, for nonrecurring measurements estimated at a date during the reporting period other than the end of the reporting period, an entity should clearly indicate that the fair value information presented is not as of the period’s end as well as the date or period that the measurement was taken. The Company adopted ASU 2015-10, effective June 12, 2015, as the change was effective upon issuance. The adoption did not have an impact on the Company’s condensed consolidated financial statements.
In July 2015, the FASB issued ASU 2015-12, Plan Accounting: Defined Benefits Pension Plans (Topic 960), Defined Contribution Pension Plans (Topic 962) and Health and Welfare Benefit Plans (Topic 965): I. Fully Benefit-Responsive Investment Contracts; II. Plan Investment Disclosures; and III. Measurement Date Practical Expedient (“ASU 2015-12”). This three-part ASU simplifies current benefit plan accounting and requires (i) fully benefit-responsive investment contracts to be measured, presented, and disclosed only at contract value and accordingly removes the requirement to reconcile their contract value to fair value; (ii) benefit plans to disaggregate their investments measured using fair value by general type, either on the face of the financial statements or in the notes to the financial statements; (iii) the net appreciation or depreciation in

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investments for the period to be presented in the aggregate rather than by general type, and removes certain disclosure requirements relevant to individual investments that represent five percent or more of net assets available for benefits. Further, the amendments in this ASU eliminate the requirement to disclose the investment strategy for certain investments that are measured using Net Asset Value (“NAV”) per share using the practical expedient in the FASB ASC Topic 820. Part III of the ASU provides a practical expedient to permit employee benefit plans to measure investments and investment-related accounts as of the month-end that is closest to the plan’s fiscal year-end, when the fiscal period does not coincide with a month-end, while requiring certain additional disclosures. The amendments in Parts I and II of this standard are effective retrospectively for fiscal years beginning after December 15, 2015 and early adoption is permitted. The amendments in Part III of this standard are effective prospectively for fiscal years beginning after December 15, 2015 and early adoption is permitted. The Company is currently evaluating the impact of this standard on its condensed consolidated financial statements.
3. Acquisitions
On August 1, 2014, the Company completed the acquisition of substantially all of the assets of privately-held Specialty Oilfield Solutions, Ltd. (“SOS”) for aggregate consideration of approximately $29.6 million, net of cash acquired (“SOS Acquisition”). SOS is a full-service drilling fluids and solids control company with operations in the Eagle Ford, Marcellus and Utica shale formations. The SOS Acquisition was financed with borrowings under the Company’s revolving credit facility. The Company believes the SOS Acquisition increases its sales into the oilfield services market, expands its geographic reach and increases its asset diversity.
On March 31, 2014, the Company completed the acquisition of 100% of the membership interests 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 exploration industry (“Anchor Acquisition”). Total consideration was approximately $223.6 million, net of cash acquired. In connection with the Anchor Acquisition, the Company is required to pay the sellers 50% of the amount of taxes paid in a post-closing tax period that 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), which is estimated to be $1.0 million as of June 30, 2015. 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 approximately $884.0 million from the Company’s March 2014 private placement of 6.50% senior notes due April 15, 2021. The Company believes the Anchor Acquisition further expands its specialty products offering, increases its sales into the oilfield services market, expands its geographic reach and increases its asset diversity.
On February 28, 2014, the Company completed the acquisition of substantially all of the assets of United Petroleum, LLC (“United Petroleum”), a marketer and distributor of high performance lubricants, for aggregate consideration of approximately $10.4 million, (“United Petroleum Acquisition”). The United Petroleum Acquisition was financed with cash on hand. The Company believes the United Petroleum Acquisition increases its position in the specialty lubricants market.
There have been no changes to the purchase price allocation, goodwill or intangible assets for the SOS, Anchor and United Petroleum Acquisitions since December 31, 2014.
Results of Sales and Earnings
The following financial information reflects sales and operating loss of the Anchor Acquisition included in the unaudited condensed consolidated statements of operations for the six months ended June 30, 2015 (in millions): 
 
Six Months Ended June 30, 2015
Sales
$
151.5

Operating loss
$
(24.3
)
Unaudited Pro Forma Financial Information
The following unaudited pro forma financial information reflects the unaudited condensed consolidated results of operations of the Company as if the Anchor Acquisition had taken place on January 1, 2014 (in millions, except for per unit data): 
 
Six Months Ended June 30, 2014
Sales
$
2,858.4

Net loss
$
(64.3
)
Limited partners’ interest net loss per unit — basic and diluted
$
(1.02
)

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The Company’s historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the Anchor Acquisition. This unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved had the pro forma events taken place on the dates indicated, or the future consolidated results of operations of the combined company.
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 $50.9 million and $18.9 million lower as of June 30, 2015 and December 31, 2014, respectively.
Inventories consist of the following (in millions):
 
June 30, 2015
 
December 31, 2014
Raw materials
$
100.8

 
$
77.8

Work in process
80.1

 
75.4

Finished goods
372.4

 
360.3

 
$
553.3

 
$
513.5

Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years that inventory volumes decline as the result of charging cost of sales with LIFO inventory costs generated in prior periods. In periods of rapidly declining prices, LIFO inventories may have to be written down to market value due to the higher costs assigned to LIFO layers in prior periods. Such write downs are subject to reversal in subsequent periods, not to exceed LIFO cost, if prices recover. During the three months ended June 30, 2015 and 2014, the Company recorded $12.4 million and $1.6 million of gains, respectively, in cost of sales in the condensed consolidated statements of operations due to the lower of cost or market valuation. During the six months ended June 30, 2015 and 2014, the Company recorded $0.8 million of losses and $2.9 million of gains, respectively, in cost of sales in the condensed consolidated statements of operations due to the lower of cost or market valuation.
5. Investment in Unconsolidated Affiliates
Dakota Prairie Refining, LLC
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 (“Dakota Prairie”). The capitalization of the construction cost was funded through cash contributions from MDU and cash contributions from the Company 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. Additionally, MDU and the Company may make cash contributions to fund working capital needs. The joint venture allocates 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 is providing natural gas and electricity utility services. The Company is providing refinery operations, crude oil procurement and refined product marketing expertise to the joint venture. Dakota Prairie reached mechanical completion and was commissioned in April 2015 and commenced sales of finished products in May 2015.
The Company accounts for its ownership in the Dakota Prairie joint venture under the equity method of accounting. As of June 30, 2015 and December 31, 2014, the Company had an investment of $144.6 million and $117.2 million, respectively, in Dakota Prairie, primarily related to the development and operations of the refinery.

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The following represents summary financial information for Dakota Prairie, presented at 100% (in millions):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
2015
 
2014
Operating revenue
$
48.4

 
$
—

 
$
50.1

 
$
—

Operating loss
$
(14.8
)
 
$
(1.6
)
 
$
(21.8
)
 
$
(2.6
)
Net loss
$
(15.2
)
 
$
(1.6
)
 
$
(22.3
)
 
$
(2.6
)
Juniper GTL LLC
On June 9, 2014, the Company entered into a joint venture agreement with Clean Fuels North America, LLC, which is owned by SGC Energia and Great Northern Project Development, to develop, build and operate a gas-to-liquids (“GTL”) plant in Lake Charles, Louisiana, which is expected to be operational by mid-2016. The joint venture is named New Source Fuels, LLC, and it owns 100% of Juniper GTL LLC (“Juniper”). The capitalization of the joint venture is expected to be funded through $100.0 million of equity contributions and $35.0 million in senior secured debt with the joint venture as the borrower. The Company intends to invest $25.0 million in total in exchange for an equity interest of approximately 23% in the joint venture. Funding of the project will occur over the course of the construction period. The joint venture is governed by a board of managers comprised of representatives from all of the members that own at least 10% of the equity in Juniper.
The Company accounts for its ownership in the Juniper joint venture under the equity method of accounting. As of June 30, 2015 and December 31, 2014, the Company had an investment of $24.6 million and $18.5 million, respectively, in Juniper, primarily related to the development of the plant.
6. Commitments and Contingencies
From time to time, the Company is a party to certain claims and litigation incidental to its business, including claims made by various regulatory and taxation 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 January 14, 2015, the Obama Administration announced that the EPA is expected to propose in 2015, and finalize in 2016, new regulations that will set methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities as part of the Administration’s efforts to reduce methane emissions from the oil and gas sector by up to 45% from 2012 levels by 2025. In a second example, in December 2014, the EPA published a proposed rulemaking that it expects to finalize in 2015, which rulemaking proposes to revise the National Ambient Air Quality Standard for ozone to between 65 to 70 parts per billion for both the 8-hour primary and secondary standards.
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.

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San Antonio Refinery
In connection with the San Antonio Acquisition, the Company agreed to indemnify NuStar for an unlimited term and without consideration of a monetary deductible or 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, pursuant to which Anadarko and Age Refining are obligated to assess and remediate certain contamination at the San Antonio refinery that predates the Company’s acquisition of the facility. The Company does not expect this pre-existing contamination at the San Antonio refinery to have a material adverse effect on its financial position or results of operations.
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 (the “Montana Consent Decree”) with the EPA and the Montana Department of Environmental Quality (the “MDEQ”). The material obligations imposed by the Montana Consent Decree have been completed. On September 27, 2012, Montana Refining Company, Inc. received a final Corrective Action Order on Consent, replacing the refinery’s previously held 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 Holly Frontier 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 timely notification, certain conditions and certain monetary baskets and caps, for environmental conditions arising under Holly’s ownership and operation of the Montana refinery and existing as of the date of sale to Connacher. During 2014, Holly provided the Company a notice challenging the Company’s position that Holly is obligated to indemnify the Company’s remediation expenses for environmental conditions to the extent arising under Holly’s ownership and operation of the refinery and existing as of the date of sale to Connacher, which expenses totaled approximately $17.8 million as of June 30, 2015, of which $14.6 million was capitalized and $3.2 million was expensed. The Company continues to believe that Holly is responsible to indemnify the Company for these remediation expenses disputed by Holly, and the parties have participated in mediation in accordance with the dispute resolution procedure set forth in the asset purchase agreement to resolve this issue. In the event the Company is unsuccessful, the Company will be responsible for those remediation expenses. The Company expects that it may incur some expenses to remediate other environmental conditions at the Montana refinery in connection with the current capacity expansion of the refinery; however, the Company believes at this time that these other costs it may incur will not be material to its financial position or results of operations.
On April 9, 2015, the MDEQ issued a Notice of Violation to the Montana refinery for alleged violation of certain air quality permit conditions and for an opacity exceedance. The MDEQ has proposed a penalty of $0.1 million. The Company is implementing internal corrective measures in response to findings alleged in the Notice of Violation or determined by the Company. 
Superior Refinery
In connection with the acquisition of the Superior refinery, 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 estimates costs of up to $1.0 million as of June 30, 2015 to make known equipment upgrades and conduct other discrete tasks in compliance with the Superior Consent Decree. Failure to perform these required tasks under the Superior Consent Decree could result in the imposition of stipulated penalties, which could be material. The Company is currently assessing certain past actions at the refinery for compliance with the terms of the Superior Consent Decree, which actions may be subject to stipulated penalties under the Superior Consent Decree but, in any event, the Company does not currently believe that the imposition of such penalties for those actions, should they be imposed, would be material. In addition, the Company is pursuing 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 three and six months ended June 30, 2015, the Company incurred no expenses related to installing process equipment at the Superior refinery pursuant to the EPA fuel content regulations. For three and six months ended June 30, 2014, the Company incurred approximately $0.1 million and $0.5 million, respectively, of costs related to installing process equipment at the Superior refinery pursuant to the EPA fuel content regulations.

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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 is in settlement discussions with the EPA to resolve this issue. The Company has not yet received formal action from the EPA. The Company does not believe that the resolution of these allegations will have a material adverse effect on the Company’s financial results or results of 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 23, 2010. Among other things, the Company agreed to complete beneficial environmental programs and implement emissions reduction projects at the Company’s Shreveport, Cotton Valley and Princeton refineries on an agreed-upon schedule. During the three months ended June 30, 2015 and 2014, the Company incurred approximately $1.4 million and $0.1 million, respectively, of such expenditures. During the six months ended June 30, 2015 and 2014, the Company incurred approximately $2.4 million and $0.2 million, respectively, of such expenditures and estimates additional expenditures of approximately $7.0 million to $9.0 million of capital expenditures and expenditures related to additional personnel and environmental studies through 2016 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 results of 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 Company believes the contractual indemnity is unlimited in amount and duration, but requires the Company to contribute $1.0 million of the first $5.0 million of indemnified costs for certain of the specified environmental liabilities.
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 June 30, 2015, the trust fund contained approximately $0.7 million. In addition, Weston has 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.

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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 June 30, 2015 and 2014, the Company incurred $0.2 million and $0.3 million, respectively, of PSM related capital expenditures. During the six months ended June 30, 2015 and 2014, the Company incurred $0.3 million and $0.5 million, respectively, of related capital expenditures and expects to incur up to $1.0 million during 2015 to address OSHA compliance issues identified in these studies. The Company expects these capital expenditures will enhance its equipment such that the equipment maintains compliance with applicable consensus codes and standards.
In the first quarter of 2011, OSHA conducted an inspection of the Cotton Valley refinery’s 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 the parties have 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 Company’s Karns City facility collective bargaining agreement was ratified on April 9, 2015 and will expire on January 31, 2019. The Montana refinery collective bargaining agreement was ratified on May 14, 2015 and will expire on January 31, 2019. The Missouri esters facility collective bargaining agreement was ratified on May 1, 2015 and will expire on April 30, 2016.
Legal Proceedings
The Company is involved in the legal proceedings described below and is subject to other claims and litigation arising in the normal course of its business. The Company has recorded accruals with respect to certain of these matters, where appropriate, that are reflected in its unaudited condensed consolidated financial statements but are not, individually or in the aggregate, considered material. For other matters, the Company has not recorded accruals because it has not yet determined that a loss is probable or because the amount of loss cannot be reasonably estimated. While the ultimate outcome of the matters described below and other claims and litigation currently pending cannot be determined, the Company currently does not expect that these proceedings and claims, individually or in the aggregate, will have a material adverse effect on its financial position, results of operations or cash flows. The outcome of any litigation is inherently uncertain, however, and if decided adversely to the Company, or if the Company determines that settlement of particular litigation is appropriate, the Company may be subject to liability that could have a material adverse effect on its financial position, results of operations, or cash flows. Accordingly, the Company discloses matters below for which a material loss is reasonably possible. In each case, however, the Company has either determined that the range of loss is not reasonably estimable or that any reasonably estimable range of loss is not material to its unaudited condensed consolidated financial statements.
On November 12, 2014, a nationwide collective action lawsuit alleging that Anchor, a wholly owned subsidiary of the Company, failed to pay drilling fluid engineers overtime in compliance with the Fair Labor Standards Act (“FLSA”) was filed titled Jonathan Wolfe v. Anchor Drilling Fluids USA, Inc. in the U.S. District Court for the Western District of Pennsylvania (“Wolfe”). The Company filed its answer to the complaint on January 9, 2015 and the Wolfe plaintiff filed an amended complaint on February 26, 2015, adding that Anchor’s failure to pay overtime to a subclass of drilling fluid engineers violated the Pennsylvania Minimum Wage Act (the “Pennsylvania Act”). For this subclass, the Wolfe plaintiff seeks certification of a class action under the Pennsylvania Act. The Wolfe plaintiff seeks to recover overtime pay, liquidated damages and attorneys’ fees and costs. The portion of the potential liability that relates to the period prior to March 31, 2014, the date on which the Company acquired Anchor, is eligible for indemnification under the securities purchase agreement that effected that transaction; however, the right to indemnification under the securities purchase agreement for the potential Wolfe liability is subject to a deductible and limitations otherwise set forth in the securities purchase agreement. On May 1, 2015, the parties engaged in mediation and agreed to a tentative settlement of this litigation. The tentative settlement must be approved by the

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U.S. District Court. The tentative settlement amount is not material to the unaudited condensed consolidated financial statements.
On November 21, 2014, a nationwide collective action lawsuit alleging that Anchor and the Company, as well as SOS, failed to pay solids control technicians overtime in compliance with the FLSA was filed titled Timothy Niver v. Specialty Oilfield Solutions, Ltd., et al. in the U.S. District Court for the Western District of Pennsylvania (“Niver”).  The Niver plaintiff filed an amended complaint on January 21, 2015, adding that defendants’ failure to pay overtime to a subclass of solids control technicians violated the Pennsylvania Act.  For this subclass, the Niver plaintiff seeks certification of a class action under the Pennsylvania Act. The Niver plaintiff seeks to recover overtime pay, liquidated damages and attorneys’ fees and costs. Anchor and the Company filed their answer to the amended complaint on February 2, 2015. The Company consented to conditional certification in the case, and notice of the collective action has been issued to potential class members. The portion of the potential liability that relates to the period prior to August 1, 2014, the date on which the Company acquired the assets of SOS, was retained by, and is the responsibility of, SOS. To the extent Anchor or the Company is found liable for damages relating to the period prior to the acquisition of the assets of SOS, Anchor and the Company are eligible for indemnification under the asset purchase agreement that effected that transaction, and no deductible is applicable; however, the right to indemnification is subject to limitations otherwise set forth in the asset purchase agreement. On June 1, 2015, the parties engaged in mediation and agreed to a tentative settlement of this litigation. The tentative settlement must be approved by the U.S. District Court. The tentative settlement amount is not material to the unaudited condensed consolidated financial statements.
Standby Letters of Credit
The Company has agreements with various financial institutions for standby letters of credit which have been issued primarily to vendors. As of June 30, 2015 and December 31, 2014, the Company had outstanding standby letters of credit of $99.1 million and $114.3 million, respectively, under its senior secured revolving credit facility (the “revolving credit facility”). Refer to Note 7 for additional information regarding the Company’s revolving credit facility. At June 30, 2015 and December 31, 2014, the maximum amount of letters of credit the Company could issue under its revolving credit facility was subject to borrowing base limitations, with a maximum letter of credit sublimit equal to $600.0 million, which amount may be increased to 90% of revolver commitments in effect ($1.0 billion at June 30, 2015 and December 31, 2014) with the consent of the Agent (as defined in the revolving credit facility agreement).
As of June 30, 2015 and December 31, 2014, the Company had availability to issue letters of credit of $423.2 million and $310.8 million, respectively, under its revolving credit facility.
7. Long-Term Debt
Long-term debt consisted of the following (in millions):
 
June 30,
2015
 
December 31,
2014
Borrowings under amended and restated senior secured revolving credit agreement with third-party lenders, interest payments quarterly, borrowings due July 2019, weighted average interest rate of 3.4% at June 30, 2015
$
103.1

 
$
150.8

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 six months ended June 30, 2015
—

 
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 6.7% for the six months ended June 30, 2015
900.0


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 8.0% for the six months ended June 30, 2015 (1)
353.0

 
352.5

Borrowings under 2023 Notes, interest at a fixed rate of 7.75%, interest payments semiannually, borrowings due April 2023, effective interest rate of 8.0% for the six months ended June 30, 2015
325.0

 
—

Capital lease obligations, at various interest rates, interest and principal payments monthly through October 2034
43.4

 
43.6

Less unamortized discounts
(6.9
)
 
(8.4
)
Total long-term debt
1,717.6

 
1,713.5

Less current portion of long-term debt
0.6

 
0.6

 
$
1,717.0

 
$
1,712.9


17
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(1) 
The balance includes a fair value interest rate hedge adjustment, which increased the debt balance by $3.0 million and $2.5 million as of June 30, 2015 and December 31, 2014, respectively (refer to Note 8 for additional information on the interest rate swap designated as a fair value hedge at December 31, 2014).
Senior Notes
7.75% Senior Notes (the “2023 Notes”)
On March 27, 2015, the Company issued and sold $325.0 million in aggregate principal amount of 7.75% senior notes due April 15, 2023 in a private placement pursuant to Section 4(a)(2) of the Securities Act of 1933, as amended (the “Securities Act”), to eligible purchasers at a discounted price of 99.257 percent of par. The 2023 Notes were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the U.S. pursuant to Regulation S under the Securities Act. The Company received net proceeds of approximately $317.0 million net of discount, initial purchasers’ fees and expenses, which the Company used to fund the redemption of $178.8 million in aggregate principal amount of outstanding 2020 Notes (defined below) on April 28, 2015, to repay borrowings outstanding under its revolving credit facility and for general partnership purposes, including planned capital expenditures at the Company’s facilities and working capital. Interest on the 2023 Notes is paid semiannually in arrears on April 15 and October 15 of each year, beginning on October 15, 2015.
At any time prior to April 15, 2018, the Company may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2023 Notes with the net proceeds of a public or private equity offering at a redemption price of 107.75% 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 2023 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, 2018, the Company may on any one or more occasions redeem all or a part of the 2023 Notes at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest to the applicable redemption date on such 2023 Notes, if redeemed during the twelve-month period beginning on April 15 of the years indicated below:
Year
 
Percentage
2018
 
105.813
%
2019
 
103.875
%
2020
 
101.938
%
2021 and thereafter
 
100.000
%
Prior to April 15, 2018, the Company may on any one or more occasions redeem all or part of the 2023 Notes at a redemption price equal to the sum of: (1) the principal amount thereof, plus (2) the make-whole premium (as set forth in the indenture governing the 2023 Notes) at the redemption date, plus any accrued and unpaid interest to the applicable redemption date.
In connection with the private placement of the 2023 Notes, on March 27, 2015, the Company entered into a registration rights agreement with the initial purchasers of the 2023 Notes obligating the Company to use reasonable best efforts to file an exchange registration statement with the SEC so that holders of the 2023 Notes can offer to exchange the 2023 Notes for registered notes having substantially the same terms as the 2023 Notes and evidencing the same indebtedness as the 2023 Notes. The Company must use reasonable best efforts to file a shelf registration statement for the resale of the 2023 Notes. If the Company fails to satisfy these obligations on a timely basis, the annual interest borne by the 2023 Notes will be increased by up to 1.0% per annum until the exchange offer is completed or the shelf registration statement is declared effective.
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 in a private placement pursuant to Section 4(a)(2) of the Securities Act, to eligible purchasers at par. The Company received net proceeds of approximately $884.0 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 9.375% senior notes due 2019 (the “2019 Notes”) 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.
On March 24, 2015, the Company filed an exchange offer registration statement for the 2021 Notes with the SEC, which was declared effective on April 3, 2015. The exchange offer was completed on April 30, 2015, thereby fulfilling all of the requirements of the 2021 Notes registration rights agreement.

18
Table of Contents

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 in a private placement pursuant to Section 4(a)(2) of the Securities Act, to eligible purchasers at a discounted price of 98.494 percent of par. The Company received net proceeds of approximately $337.4 million, net of discount, initial purchasers’ fees and expenses, which the Company used for general partnership purposes, to fund previously announced organic growth projects, the purchase price of the Bel-Ray acquisition and the redemption of $100.0 million in aggregate principal amount outstanding of 9.375% senior notes due 2019. Interest on the 2022 Notes is paid semiannually in arrears on January 15 and July 15 of each year, beginning on July 15, 2014.
9.625% Senior Notes (the “2020 Notes”)
On June 29, 2012, in connection with the acquisition of Royal Purple, Inc. (“Royal Purple”), the Company issued and sold $275.0 million in aggregate principal amount of 9.625% senior notes due August 1, 2020 in a private placement pursuant to Section 4(a)(2) of the Securities Act, to eligible purchasers at a discounted price of 98.25 percent of par. The Company received net proceeds of approximately $262.5 million, net of discount, initial purchasers’ fees and expenses, which the Company used to fund a portion of the purchase price of Royal Purple. Interest on the 2020 Notes was previously paid semiannually in arrears on February 1 and August 1 of each year, beginning on February 1, 2013.
On April 27, 2015, the Company redeemed $96.2 million aggregate principal amount of 2020 Notes with a portion of the net proceeds of the March 13, 2015 public offering of its common units in which it sold 6,000,000 common units. Additionally, on April 28, 2015, the Company redeemed the remaining $178.8 million aggregate principal amount of 2020 Notes with a portion of the net proceeds from the issuance of the 2023 Notes. In conjunction with the redemptions, the Company incurred debt extinguishment costs of $46.6 million.
2021 Notes, 2022 Notes and 2023 Notes
In accordance with SEC Rule 3-10 of Regulation S-X, condensed consolidated financial statements of non-guarantors are not required. The Company has no assets or operations independent of its subsidiaries. Obligations under its 2021, 2022 and 2023 Notes are fully and unconditionally and jointly and severally guaranteed on a senior unsecured basis by the Company’s current 100%-owned operating subsidiaries and certain of the Company’s future operating subsidiaries, with the exception of the Company’s “minor” subsidiaries (as defined by Rule 3-10 of Regulation S-X), including 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 2021, 2022 and 2023 Notes). There are no significant restrictions on the ability of the Company or subsidiary guarantors for the Company to obtain funds from its subsidiary guarantors by dividend or loan. None of the subsidiary guarantors’ assets represent restricted assets pursuant to SEC Rule 4-08(e)(3) of Regulation S-X.
The 2021, 2022 and 2023 Notes are subject to certain automatic customary releases, including the sale, disposition, or transfer of capital stock or substantially all of the assets of a subsidiary guarantor, designation of a subsidiary guarantor as unrestricted in accordance with the applicable indenture, exercise of legal defeasance option or covenant defeasance option, liquidation or dissolution of the subsidiary guarantor and a subsidiary guarantor ceases to both guarantee other Company debt and to be an obligor under the revolving credit facility. The Company’s 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 2021, 2022 and 2023 Notes.
The indentures governing the 2021, 2022 and 2023 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 2021, 2022 and 2023 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 2021, 2022 and 2023 Notes, has occurred and is continuing, many of these covenants will be suspended. As of June 30, 2015, the Company’s Fixed Charge Coverage Ratio (as defined in the indentures governing the 2021, 2022 and 2023 Notes) was 3.1 to 1.0. As of June 30, 2015, the Company was in compliance with all covenants under the indentures governing the 2021, 2022 and 2023 Notes.
Second Amended and Restated Senior Secured Revolving Credit Facility
The Company has a $1.0 billion senior secured revolving credit facility, subject to borrowing base limitations, which includes a $500.0 million incremental uncommitted expansion feature. The revolving credit facility is the Company’s primary source of liquidity for cash needs in excess of cash generated from operations. The revolving credit facility matures in July 2019 and currently bears interest at a rate equal to prime plus a basis points margin or London Interbank Offered Rate

19
Table of Contents

(“LIBOR”) plus a basis points margin, at the Company’s option. As of June 30, 2015, the margin was 75 basis points for prime and 175 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 quarterly 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 0.250% or 0.375% 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% per annum of the stated amount of each outstanding letter of credit, and customary agency fees.
The borrowing capacity at June 30, 2015 under the revolving credit facility was $625.3 million. As of June 30, 2015, the Company had $103.1 million in outstanding borrowings under the revolving credit facility and outstanding standby letters of credit of $99.1 million, leaving $423.2 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 accounts receivable, inventory and substantially all of its cash.
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 (a) 12.5% of the Borrowing Base (as defined in the revolving credit agreement) then in effect and (b) $45.0 million, 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 June 30, 2015, the Company was in compliance with all covenants under the revolving credit facility.
Maturities of Long-Term Debt
As of June 30, 2015, principal payments on debt obligations and future minimum rentals on capital lease obligations are as follows (in millions):
Year
 
 
2015
 
$
0.3

2016
 
0.7

2017
 
0.7

2018
 
0.8

2019
 
103.9

Thereafter
 
1,615.1

Total
 
$
1,721.5

8. 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), natural gas and precious metals. 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;
•
precious metals purchases; and
•fluctuations in the value of crude oil between geographic regions and between the different types of crude oil such as NYMEX West Texas Intermediate (“NYMEX WTI”), Light Louisiana Sweet (“LLS”), Western Canadian Select (“WCS”), Mixed Sweet Blend (“MSW”) and ICE Brent (“Brent”).
The Company manages its exposure to commodity markets, credit, volumetric and liquidity risks to manage its costs and volatility of cash flows as conditions warrant or opportunities become available. These risks may be managed in a variety of

20
Table of Contents

ways that may include the use of derivative instruments. Derivative instruments may be used for the purpose of mitigating risks associated with an asset, liability, and anticipated future transactions and the changes in fair value of the Company’s derivative instruments will affect its earnings and cash flows; however, such changes should be offset by price or rate changes related to the underlying commodity or financial transaction that is part of the risk management strategy. The Company does not speculate with derivative instruments or other contractual arrangements that are not associated with its business objectives.  Speculation is defined as increasing the Company’s natural position above the maximum position of its physical assets or trading in commodities, currencies or other risk bearing assets that are not associated with the Company’s business activities and objectives. The Company’s positions are monitored routinely by a risk management committee to ensure compliance with its stated risk management policy and documented risk management strategies. All strategies are reviewed on an ongoing basis by the Company’s risk management committee, which will add, remove or revise strategies in anticipation of changes in market conditions and/or in risk profiles. Such changes in strategies are to position the Company in relation to its risk exposures in an attempt to capture market opportunities as they arise. 
The Company recognizes all derivative instruments at their fair values (see Note 9) 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 portions or all of its derivative instruments for hedge accounting.

21
Table of Contents

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 June 30, 2015 and December 31, 2014 (in millions):
 
 
June 30, 2015
 
December 31, 2014
 
 
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
 
$
—

 
$
—

 
$
—

 
$
—

 
$
(10.0
)
 
$
(10.0
)
Gasoline swaps
 
—

 
—

 
—

 
15.9

 
(4.4
)
 
11.5

Swaps not allocated to a specific segment:
 
 
 
 
 
 
 
 
 
 
 
 
Interest rate swaps
 


 


 
—

 
2.5

 
—

 
2.5

Total derivative instruments designated as hedges
 
—

 
—

 
—

 
18.4

 
(14.4
)
 
4.0

Derivative instruments not designated as hedges:
 
 
 
 
 
 
 
 
 
 
Fuel products segment:
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil swaps
 
1.7

 
(2.3
)
 
(0.6
)
 
31.4

 
(111.2
)
 
(79.8
)
Crude oil basis swaps
 
—

 
—

 
—

 
0.8

 
—

 
0.8

Crude oil percentage basis swaps
 
2.3

 
(2.3
)
 
—

 
—

 
(0.2
)
 
(0.2
)
Crude oil options
 
1.1

 
(1.1
)
 
—

 
—

 
—

 
—

Gasoline swaps
 
—

 
—

 
—

 
2.4

 
(0.4
)
 
2.0

Gasoline crack spread swaps
 
0.9

 
(0.9
)
 
—

 
—

 
—

 
—

Diesel swaps
 
1.6

 
(0.9
)
 
0.7

 
116.1

 
(19.1
)
 
97.0

Diesel crack spread swaps
 
5.6

 
(4.0
)
 
1.6

 
4.5

 
—

 
4.5

Jet fuel swaps
 
—

 
—

 
—

 
7.9

 
(5.2
)
 
2.7

Platinum swaps
 
—

 
—

 
—

 
—

 
(0.1
)
 
(0.1
)
Specialty products segment:
 
 
 
 
 

 
 
 
 
 
 
Natural gas swaps
 
—

 
(0.5
)
 
(0.5
)
 
—

 
(7.2
)
 
(7.2
)
Natural gas collars
 
—

 
—

 
—

 
0.1

 
(0.6
)
 
(0.5
)
Total derivative instruments not designated as hedges
 
13.2

 
(12.0
)
 
1.2

 
163.2

 
(144.0
)
 
19.2

Total derivative instruments
 
$
13.2

 
$
(12.0
)
 
$
1.2

 
$
181.6

 
$
(158.4
)
 
$
23.2


22
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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 June 30, 2015 and December 31, 2014 (in millions):
 
 
June 30, 2015
 
December 31, 2014
 
 
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
 
$
—

 
$
—

 
$
—

 
$
(13.8
)
 
$
10.0

 
$
(3.8
)
Gasoline swaps
 
—

 
—

 
—

 
—

 
4.4

 
4.4

Total derivative instruments designated as hedges
—

 
—

 
—

 
(13.8
)

14.4


0.6

Derivative instruments not designated as hedges:
 
 
 
 
 
 
 
 
 
 
Fuel products segment:
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil swaps
 
(2.5
)
 
2.3

 
(0.2
)
 
(102.4
)
 
111.2

 
8.8

Crude oil percentage basis swaps
 
—

 
2.3

 
2.3

 
(0.2
)
 
0.2

 
—

Crude oil options
 
(2.1
)
 
1.1

 
(1.0
)
 
—

 
—

 
—

Gasoline swaps
 
(7.5
)
 
—

 
(7.5
)
 
(1.0
)
 
0.4

 
(0.6
)
Gasoline crack spread swaps
 
(4.1
)
 
0.9

 
(3.2
)
 
—

 
—

 
—

Diesel swaps
 
(0.1
)
 
0.9

 
0.8

 
(28.1
)
 
19.1

 
(9.0
)
Diesel crack spread swaps
 
—

 
4.0

 
4.0

 
—

 
—

 
—

Jet fuel swaps
 
—

 
—

 
—

 
(5.2
)
 
5.2

 
—

Platinum swaps
 
(0.4
)
 
—

 
(0.4
)
 
(0.1
)
 
0.1

 
—

Natural gas swaps
 
(0.3
)
 
—

 
(0.3
)
 
—

 
—

 
—

Specialty products segment:
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas swaps
 
(12.4
)
 
0.5

 
(11.9
)
 
(12.1
)
 
7.2

 
(4.9
)
Natural gas collars
 
(0.9
)
 
—

 
(0.9
)
 
(1.1
)
 
0.6

 
(0.5
)
Total derivative instruments not designated as hedges
(30.3
)
 
12.0

 
(18.3
)
 
(150.2
)
 
144.0

 
(6.2
)
Total derivative instruments
$
(30.3
)
 
$
12.0

 
$
(18.3
)
 
$
(164.0
)
 
$
158.4

 
$
(5.6
)
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 June 30, 2015, the Company had one counterparty in which derivatives held were net assets. As of December 31, 2014, the Company had five 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 Baa1 and BBB+ by Moody’s and S&P, respectively. In the event of default, the Company would potentially be subject to losses on derivative instruments with mark-to- market gains. The Company requires collateral from its counterparties when the fair value of the derivatives exceeds agreed upon thresholds in its master derivative contracts with these counterparties. No such collateral was held by the Company as of June 30, 2015 or December 31, 2014. 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 June 30, 2015 and December 31, 2014, 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 agreed-upon collateral, such as cash or letters of credit, with the counterparty to the extent that the Company’s mark-to-market

23
Table of Contents

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.

24
Table of Contents

The Company recorded the following amounts in its condensed consolidated balance sheets, unaudited condensed consolidated statements of operations, unaudited condensed consolidated statements of comprehensive income (loss) and unaudited condensed consolidated statements of partners’ capital as of and for the three months ended June 30, 2015 and 2014 related to its derivative instruments that were designated as cash flow hedges (in millions):
Type of Derivative
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)
 
Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (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
June 30,
 
 
June 30,
 
 
June 30,
2015
 
2014
 
 
2015
 
2014
 
 
2015
 
2014
Fuel products segment:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil swaps
$
(2.7
)
 
$
53.5

 
Cost of sales
 
$
(53.2
)
 
$
13.6

 
Unrealized/ Realized
 
$
—

 
$
30.3

Gasoline swaps
2.7

 
(8.2
)
 
Sales
 
19.3

 
(5.8
)
 
Unrealized/ Realized
 
—

 
(3.6
)
Diesel swaps
(1.4
)
 
(33.4
)
 
Sales
 
39.8

 
(4.9
)
 
Unrealized/ Realized
 
—

 
(1.6
)
Jet fuel swaps
0.3

 
(3.8
)
 
Sales
 
4.0

 
(0.9
)
 
Unrealized/ Realized
 
—

 
(0.5
)
Specialty products segment:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil swaps
—

 
—

 
Cost of sales
 
1.6

 
(0.9
)
 
Unrealized/ Realized
 
—

 
—

Total
$
(1.1
)
 
$
8.1

 
 
 
$
11.5

 
$
1.1

 
 
 
$
—

 
$
24.6

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 six months ended June 30, 2015 and 2014 related to its derivative instruments that were designated as cash flow hedges (in millions):
Type of Derivative
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)
 
Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Loss) (Effective Portion)
 
Amount of Gain (Loss) Recognized in Net Income (Loss) on Derivatives (Ineffective Portion)
Six Months Ended
 
Location of Gain (Loss)
 
Six Months Ended
 
Location of Gain (Loss)
 
Six Months Ended
June 30,
 
 
June 30,
 
 
June 30,
2015
 
2014
 
 
2015
 
2014
 
 
2015
 
2014
Fuel products segment:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil swaps
$
(9.0
)
 
$
71.2

 
Cost of sales
 
$
(74.7
)
 
$
23.1

 
Unrealized/ Realized
 
$
(0.2
)
 
$
47.7

Gasoline swaps
3.5

 
(10.0
)
 
Sales
 
33.3

 
(11.5
)
 
Unrealized/ Realized
 
0.7

 
(4.5
)
Diesel swaps
(1.3
)
 
(13.4
)
 
Sales
 
44.6

 
(11.1
)
 
Unrealized/ Realized
 
—

 
(0.1
)
Jet fuel swaps
0.6

 
2.7

 
Sales
 
5.4

 
(2.1
)
 
Unrealized/ Realized
 
—

 
(0.4
)
Specialty products segment:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil swaps
—

 
—

 
Cost of sales
 
1.2

 
(1.2
)
 
Unrealized/ Realized
 
—

 
—

Total
$
(6.2
)
 
$
50.5

 
 
 
$
9.8

 
$
(2.8
)
 
 
 
$
0.5

 
$
42.7

The effective portion of the cash flow hedges classified in accumulated other comprehensive income (loss) was a gain of $9.7 million and a gain of $25.8 million as of June 30, 2015 and December 31, 2014, 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 June 30, 2015 will be reclassified to earnings by December 31, 2016 with balances being recognized as follows (in millions):
Year
Accumulated Other Comprehensive Income (Loss)
2015
$
(1.1
)
2016
10.8

Total
$
9.7

Based on fair values as of June 30, 2015, the Company expects to reclassify $4.6 million of net gains on derivative instruments from accumulated other comprehensive income to earnings during the next twelve months due to actual crude oil

25
Table of Contents

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, such as an interest rate swap, 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 is recognized if 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 converted a portion of the Company’s fixed rate debt to a floating rate. This agreement involved 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. On January 13, 2015, the Company terminated its interest rate swap, which was designated as a fair value hedge, related to a notional amount of $200.0 million of 2022 Notes. In settlement of this swap, the Company recognized a net gain of approximately $3.3 million.
The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2015 and 2014 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 June 30,

Six Months Ended June 30,


Three Months Ended June 30,

Six Months Ended June 30,

2015
 
2014

2015
 
2014


2015
 
2014

2015
 
2014
Swaps not allocated to a specific segment:

 
 



 



 
 


 
 
Interest rate swap
Interest income (expense)

$
—

 
$
1.0


$
—

 
$
(0.6
)

2022 Notes
 
Interest income (expense)

$
—

 
$
(1.0
)

$
—

 
$
0.6

Total


$
—

 
$
1.0


$
—

 
$
(0.6
)


 


$
—

 
$
(1.0
)

$
—

 
$
0.6

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. Additionally, the Company has entered into diesel crack spread collars, gasoline crack spread collars, natural gas collars, and certain other crude oil swaps, diesel swaps, gasoline swaps, natural gas swaps, crude oil options and platinum swaps that are not designated as cash flow hedges for accounting purposes.

26
Table of Contents

The amount reclassified from accumulated other comprehensive income (loss) into earnings, as a result of the discontinuance of cash flow hedge accounting for certain crude oil, gasoline, 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 the following gains and losses in the unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2015 (in millions):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
2015
 
2014
Realized gain (loss) on derivative instruments
$
1.2

 
$
(2.1
)
 
$
2.4

 
$
(3.3
)
The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations for the three months ended June 30, 2015 and 2014 related to its derivative instruments not designated as hedges (in millions):
Type of Derivative
Amount of Gain (Loss) Recognized in Realized Gain (Loss) on Derivative Instruments
 
Amount of Gain (Loss) Recognized in Unrealized Gain (Loss) on Derivative Instruments
Three Months Ended June 30,
 
Three Months Ended June 30,
2015
 
2014
 
2015
 
2014
Fuel products segment:
 
 
 
 
 
 
 
Crude oil swaps
$
7.7

 
$
10.5

 
$
5.2

 
$
11.1

Crude oil basis swaps
—

 
0.6

 
2.2

 
(1.8
)
Gasoline swaps
(16.4
)
 
(7.6
)
 
(7.1
)
 
(1.5
)
Diesel swaps
1.2

 
(1.6
)
 
(3.8
)
 
(5.5
)
Diesel crack spread swaps
—

 
—

 
7.4

 
—

Gasoline crack spread swaps
(3.9
)
 
—

 
(1.7
)
 
—

Jet fuel swaps
—

 
(0.1
)
 
—

 
—

Diesel crack spread collars
—

 
0.6

 
—

 
—

Platinum swaps
—

 
—

 
(0.2
)
 
—

Natural gas swaps
—

 
—

 
—

 
—

Gasoline crack spread collars
—

 
—

 
—

 
(0.5
)
Specialty products segment:
 
 
 
 
 
 
 
Natural gas swaps
(2.5
)
 
0.4

 
3.1

 
0.4

Total
$
(13.9
)
 
$
2.8

 
$
5.1

 
$
2.2


27
Table of Contents

The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations for the six months ended June 30, 2015 and 2014 related to its derivative instruments not designated as hedges (in millions):
Type of Derivative
Amount of Gain (Loss) Recognized in Realized Gain (Loss) on Derivative Instruments
 
Amount of Gain (Loss) Recognized in Unrealized Gain (Loss) on Derivative Instruments
Six Months Ended June 30,
 
Six Months Ended June 30,
2015
 
2014
 
2015
 
2014
Fuel products segment:
 
 
 
 
 
 
 
Crude oil swaps
$
(40.6
)
 
$
14.4

 
$
55.4

 
$
14.5

Crude oil basis swaps
1.0

 
1.2

 
1.8

 
(0.5
)
Gasoline swaps
(18.4
)
 
(11.2
)
 
(8.2
)
 
1.0

Diesel swaps
59.2

 
(1.6
)
 
(67.2
)
 
(2.5
)
Diesel crack spread swaps
0.9

 
—

 
1.0

 
—

Gasoline crack spread swaps
(4.7
)
 
—

 
(3.2
)
 
—

Jet fuel swaps
1.6

 
(0.5
)
 
(1.6
)
 
(0.9
)
Diesel crack spread collars
—

 
1.0

 
—

 
0.4

Platinum swaps
—

 
—

 
(0.3
)
 
—

Natural gas swaps
—

 
—

 
(0.3
)
 
—

Gasoline crack spread collars
—

 
—

 
—

 
0.2

Specialty products segment:
 
 
 
 
 
 
 
Natural gas swaps
(4.6
)
 
1.3

 
(0.1
)
 
1.3

Total
$
(5.6
)
 
$
4.6

 
$
(22.7
)
 
$
13.5

Derivative Positions - Specialty Products Segment
Natural Gas Swap Contracts
At June 30, 2015, 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
Third Quarter 2015
1,500,000


$
4.11

Fourth Quarter 2015
1,900,000


$
4.12

Calendar Year 2016
5,880,000


$
4.22

Calendar Year 2017
4,950,000


$
3.85

Total
14,230,000



Average price


$
4.07

At December 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
First Quarter 2015
1,770,000


$
4.09

Second Quarter 2015
1,500,000


$
4.11

Third Quarter 2015
1,500,000


$
4.11

Fourth Quarter 2015
1,900,000


$
4.12

Calendar Year 2016
5,880,000


$
4.22

Calendar Year 2017
1,830,000


$
4.28

Total
14,380,000



Average price


$
4.18


28
Table of Contents

Natural Gas Collars
At June 30, 2015, 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 Collars by Expiration Dates
MMBtu
 
Average Bought Call ($/MMBtu)
 
Average Sold Put ($/MMBtu)
Third Quarter 2015
240,000

 
$
4.25

 
$
3.79

Fourth Quarter 2015
200,000

 
$
4.25

 
$
3.85

Calendar Year 2016
600,000

 
$
4.25

 
$
3.89

Total
1,040,000

 
 
 
 
Average price
 
 
$
4.25

 
$
3.86

At December 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 Collars by Expiration Dates
MMBtu
 
Average Bought Call ($/MMBtu)
 
Average Sold Put ($/MMBtu)
First Quarter 2015
240,000

 
$
4.25

 
$
3.79

Second Quarter 2015
240,000

 
$
4.25

 
$
3.79

Third Quarter 2015
240,000

 
$
4.25

 
$
3.79

Fourth Quarter 2015
200,000

 
$
4.25

 
$
3.85

Calendar Year 2016
600,000

 
$
4.25

 
$
3.89

Total
1,520,000

 
 
 
 
Average price
 
 
$
4.25

 
$
3.84

Derivative Positions - Fuel Products Segment
Natural Gas Swap Contracts
At June 30, 2015, the Company had the following derivatives related to natural gas purchases in its fuel products segment, none of which are designated as hedges.
Natural Gas Swap Contracts by Expiration Dates
MMBtu
 
$/MMBtu
Calendar Year 2016
1,320,000

 
$
3.38

Total
1,320,000

 
 
Average price
 
 
$
3.38

Crude Oil Swap Contracts
At June 30, 2015, 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)
Third Quarter 2015
955,000

 
10,380

 
$
58.96

Fourth Quarter 2015
185,000

 
2,011

 
$
61.48

Calendar Year 2016
720,288

 
1,968

 
$
62.71

Total
1,860,288





Average price




$
60.66

At June 30, 2015, 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)
Third Quarter 2015
120,000

 
1,304

 
$