10-Q
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
|
| |
x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2016
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 | | 35-1811116 |
(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 May 6, 2016, there were 76,063,679 common units outstanding.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
QUARTERLY REPORT
For the Three Months Ended March 31, 2016
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, 2015 (“2015 Annual Report”) and (ii) Part I, Item 3 “Quantitative and Qualitative Disclosures About Market Risk” and Part II, Item 1A “Risk Factors” in this Quarterly Report. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.
References in this Quarterly Report to “Calumet Specialty Products Partners, L.P.,” “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.
PART I
Item 1. Financial Statements
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS
|
| | | | | | | |
| March 31, 2016 | | December 31, 2015 |
| (Unaudited) | | |
| (In millions, except unit data) |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | 7.2 |
| | $ | 5.6 |
|
Accounts receivable: | | | |
Trade | 209.1 |
| | 195.3 |
|
Other | 22.0 |
| | 15.4 |
|
| 231.1 |
| | 210.7 |
|
Inventories | 429.9 |
|
| 384.4 |
|
Prepaid expenses and other current assets | 6.9 |
|
| 8.3 |
|
Total current assets | 675.1 |
| | 609.0 |
|
Property, plant and equipment, net | 1,727.6 |
|
| 1,719.2 |
|
Investment in unconsolidated affiliates | 115.8 |
|
| 126.0 |
|
Goodwill | 212.0 |
|
| 212.0 |
|
Other intangible assets, net | 206.5 |
|
| 214.1 |
|
Other noncurrent assets, net | 61.6 |
|
| 64.4 |
|
Total assets | $ | 2,998.6 |
| | $ | 2,944.7 |
|
LIABILITIES AND PARTNERS’ CAPITAL |
Current liabilities: | | | |
Accounts payable | $ | 288.1 |
|
| $ | 316.6 |
|
Accrued interest payable | 45.3 |
|
| 31.1 |
|
Accrued salaries, wages and benefits | 23.7 |
|
| 32.9 |
|
Other taxes payable | 17.5 |
|
| 17.9 |
|
Other current liabilities | 143.5 |
|
| 119.0 |
|
Current portion of long-term debt | 1.7 |
|
| 1.7 |
|
Note payable — related party | 72.4 |
| | 73.5 |
|
Derivative liabilities | 29.3 |
|
| 33.9 |
|
Total current liabilities | 621.5 |
| | 626.6 |
|
Noncurrent deferred income taxes | 2.1 |
|
| 2.1 |
|
Pension and postretirement benefit obligations | 12.5 |
|
| 13.0 |
|
Other long-term liabilities | 0.9 |
|
| 0.9 |
|
Long-term debt, less current portion | 1,883.1 |
|
| 1,698.2 |
|
Total liabilities | 2,520.1 |
| | 2,340.8 |
|
Commitments and contingencies |
|
|
|
Partners’ capital: | | | |
Limited partners’ interest 75,884,400 units and 75,884,400 units, issued and outstanding as of March 31, 2016 and December 31, 2015, respectively | 461.4 |
| | 578.0 |
|
General partner’s interest | 20.8 |
| | 27.5 |
|
Accumulated other comprehensive loss | (3.7 | ) |
| (1.6 | ) |
Total partners’ capital | 478.5 |
| | 603.9 |
|
Total liabilities and partners’ capital | $ | 2,998.6 |
| | $ | 2,944.7 |
|
See accompanying notes to unaudited condensed consolidated financial statements.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
|
| | | | | | | |
| Three Months Ended March 31, |
| 2016 | | 2015 |
| (In millions, except per unit and unit data) |
Sales | $ | 713.0 |
|
| $ | 1,018.6 |
|
Cost of sales | 626.8 |
|
| 823.4 |
|
Gross profit | 86.2 |
|
| 195.2 |
|
Operating costs and expenses: | | | |
Selling | 30.5 |
|
| 38.4 |
|
General and administrative | 27.6 |
|
| 39.2 |
|
Transportation | 39.2 |
|
| 42.0 |
|
Taxes other than income taxes | 5.7 |
|
| 4.0 |
|
Other | 2.0 |
|
| 2.9 |
|
Operating income (loss) | (18.8 | ) |
| 68.7 |
|
Other income (expense): | | | |
Interest expense | (30.3 | ) |
| (27.0 | ) |
Realized gain (loss) on derivative instruments | (12.3 | ) |
| 8.9 |
|
Unrealized gain (loss) on derivative instruments | 4.6 |
|
| (27.9 | ) |
Loss from unconsolidated affiliates | (11.1 | ) |
| (4.5 | ) |
Other | 0.4 |
|
| 0.8 |
|
Total other expense | (48.7 | ) |
| (49.7 | ) |
Net income (loss) before income taxes | (67.5 | ) |
| 19.0 |
|
Income tax expense (benefit) | 0.2 |
|
| (4.8 | ) |
Net income (loss) | $ | (67.7 | ) |
| $ | 23.8 |
|
Allocation of net income (loss): | | | |
Net income (loss) | $ | (67.7 | ) |
| $ | 23.8 |
|
Less: | | | |
General partner’s interest in net income (loss) | (1.4 | ) |
| 0.5 |
|
General partner’s incentive distribution rights | — |
|
| 4.2 |
|
Net income (loss) available to limited partners | $ | (66.3 | ) |
| $ | 19.1 |
|
Weighted average limited partner units outstanding: | | | |
Basic | 76,449,841 |
|
| 71,232,392 |
|
Diluted | 76,449,841 |
|
| 71,275,452 |
|
Limited partners’ interest basic and diluted net income (loss) per unit | $ | (0.87 | ) |
| $ | 0.27 |
|
Cash distributions declared per limited partner unit | $ | 0.685 |
|
| $ | 0.685 |
|
See accompanying notes to unaudited condensed consolidated financial statements.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
|
| | | | | | | |
| Three Months Ended March 31, |
| 2016 | | 2015 |
| (In millions) |
Net income (loss) | $ | (67.7 | ) | | $ | 23.8 |
|
Other comprehensive income (loss): | | | |
Cash flow hedges: | | | |
Cash flow hedge (gain) loss reclassified to net income (loss) | (2.1 | ) | | 1.7 |
|
Change in fair value of cash flow hedges | — |
| | (5.1 | ) |
Defined benefit pension and retiree health benefit plans | — |
| | 0.2 |
|
Foreign currency translation adjustment | — |
| | (0.3 | ) |
Total other comprehensive loss | (2.1 | ) | | (3.5 | ) |
Comprehensive income (loss) attributable to partners’ capital | $ | (69.8 | ) | | $ | 20.3 |
|
See accompanying notes to unaudited condensed consolidated financial statements.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
|
| | | | | | | | | | | | | | | |
| Accumulated Other Comprehensive Loss | | Partners’ Capital | | |
| | General Partner | | Limited Partners | | Total |
| (In millions) |
Balance at December 31, 2015 | $ | (1.6 | ) | | $ | 27.5 |
| | $ | 578.0 |
| | $ | 603.9 |
|
Other comprehensive loss | (2.1 | ) | | — |
| | — |
| | (2.1 | ) |
Net loss | — |
| | (1.4 | ) | | (66.3 | ) | | (67.7 | ) |
Amortization of vested phantom units | — |
| | — |
| | 1.8 |
| | 1.8 |
|
Distributions to partners | — |
| | (5.3 | ) | | (52.1 | ) | | (57.4 | ) |
Balance at March 31, 2016 | $ | (3.7 | ) | | $ | 20.8 |
| | $ | 461.4 |
| | $ | 478.5 |
|
See accompanying notes to unaudited condensed consolidated financial statements.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | | | | | | |
| Three Months Ended March 31, |
| 2016 |
| 2015 |
| (In millions) |
Operating activities | | | |
Net income (loss) | $ | (67.7 | ) |
| $ | 23.8 |
|
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | | |
Depreciation and amortization | 38.8 |
|
| 35.4 |
|
Amortization of turnaround costs | 9.1 |
|
| 6.1 |
|
Non-cash interest expense | 1.9 |
|
| 1.4 |
|
Provision for doubtful accounts | 0.3 |
|
| — |
|
Unrealized (gain) loss on derivative instruments | (4.6 | ) |
| 27.9 |
|
Loss on disposal of fixed assets | 0.8 |
| | 0.3 |
|
Non-cash equity based compensation | 1.8 |
|
| 3.2 |
|
Deferred income tax benefit | — |
| | (4.8 | ) |
Lower of cost or market inventory adjustment | (8.1 | ) | | 13.2 |
|
Loss from unconsolidated affiliates | 11.1 |
| | 4.5 |
|
Other non-cash activities | 1.2 |
|
| 1.3 |
|
Changes in assets and liabilities: | | | |
Accounts receivable | (20.7 | ) |
| 29.2 |
|
Inventories | (36.0 | ) |
| (18.9 | ) |
Prepaid expenses and other current assets | — |
|
| 4.4 |
|
Derivative activity | (3.6 | ) |
| 9.2 |
|
Turnaround costs | (6.4 | ) |
| (2.7 | ) |
Other assets | (0.3 | ) | | — |
|
Accounts payable | (1.8 | ) |
| (78.9 | ) |
Accrued interest payable | 14.2 |
|
| 0.7 |
|
Accrued salaries, wages and benefits | (9.2 | ) |
| (1.9 | ) |
Other taxes payable | (0.4 | ) |
| (2.0 | ) |
Other liabilities | 24.0 |
|
| 38.2 |
|
Pension and postretirement benefit obligations | (0.5 | ) |
| (0.2 | ) |
Net cash provided by (used in) operating activities | (56.1 | ) | | 89.4 |
|
Investing activities | | | |
Additions to property, plant and equipment | (66.8 | ) |
| (74.1 | ) |
Investment in unconsolidated affiliates | (0.9 | ) |
| (25.0 | ) |
Proceeds from sale of property, plant and equipment | — |
| | 0.1 |
|
Net cash used in investing activities | (67.7 | ) | | (99.0 | ) |
Financing activities | | | |
Proceeds from borrowings — revolving credit facility | 393.9 |
|
| 358.8 |
|
Repayments of borrowings — revolving credit facility | (210.0 | ) |
| (509.5 | ) |
Repayments of borrowings — related party note | (1.5 | ) | | — |
|
Payments on capital lease obligations | (2.0 | ) |
| (1.7 | ) |
Proceeds from other financing obligations | 2.4 |
| | — |
|
Proceeds from senior notes offering | — |
|
| 322.6 |
|
Debt issuance costs | — |
|
| (5.6 | ) |
Proceeds from public offerings of common units, net | — |
|
| 161.7 |
|
Contributions from Calumet GP, LLC | — |
|
| 3.5 |
|
Common units repurchased and taxes paid for phantom unit grants | — |
|
| (3.2 | ) |
Distributions to partners | (57.4 | ) |
| (52.7 | ) |
Net cash provided by financing activities | 125.4 |
| | 273.9 |
|
Net increase in cash and cash equivalents | 1.6 |
| | 264.3 |
|
Cash and cash equivalents at beginning of period | 5.6 |
|
| 8.5 |
|
Cash and cash equivalents at end of period | $ | 7.2 |
| | $ | 272.8 |
|
Supplemental disclosure of non-cash financing and investing activities | | | |
Non-cash property, plant and equipment additions | $ | 29.3 |
| | $ | 47.2 |
|
See accompanying notes to unaudited condensed consolidated financial statements.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. Description of the Business
Calumet Specialty Products Partners, L.P. (the “Company”) is a publicly traded Delaware limited partnership listed on the NASDAQ Global Select Market (“NASDAQ”) under the ticker symbol “CLMT.” The general partner of the Company is Calumet GP, LLC, a Delaware limited liability company. As of March 31, 2016, the Company had 75,884,400 limited partner common units and 1,548,660 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 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 March 31, 2016, and for the three months ended March 31, 2016 and 2015, included herein have been prepared, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Certain information and disclosures normally included in the consolidated financial statements prepared in accordance with generally accepted accounting principles (“GAAP”) in the U.S. have been condensed or omitted pursuant to such rules and regulations, although the Company believes that the following disclosures are adequate to make the information presented not misleading. These unaudited condensed consolidated financial statements reflect all adjustments that, in the opinion of management, are necessary to present fairly the results of operations for the interim periods presented. All adjustments are of a normal nature, unless otherwise disclosed. The results of operations for the three months ended March 31, 2016, are not necessarily indicative of the results that may be expected for the year ending December 31, 2016. These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s 2015 Annual Report.
2. Summary of Significant Accounting Policies
Reclassifications
Certain amounts in the prior years’ condensed consolidated financial statements have been reclassified to conform to the current year presentation.
New Accounting Pronouncements
In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-09, Compensation — Stock Compensation (Topic 606): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). ASU 2016-09 involves several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. Under the new standard, income tax benefits and deficiencies are to be recognized as income tax expense or benefit in the income statement and the tax effects of exercised or vested awards should be treated as discrete items in the reporting period in which they occur. Excess tax benefits should be classified along with other income tax cash flows as an operating activity. In regards to forfeitures, the entity may make an entity-wide accounting policy election to either estimate the number of awards that are expected to vest or account for forfeitures when they occur. The amendments in this standard are effective for fiscal years (including interim periods) beginning after December 15, 2016, with early adoption permitted. The Company is currently evaluating the impact of this standard on its condensed consolidated financial statements.
In March 2016, the FASB issued ASU No. 2016-07, Investments — Equity Method and Joint Ventures (Topic 323): Simplifying the Transition to the Equity Method of Accounting (“ASU 2016-07”), which eliminates the retroactive adjustments to an investment upon it qualifying for the equity method of accounting as a result of an increase in the level of ownership interest or degree of influence by the investor. ASU 2016-07 requires that the equity method investor add the cost of acquiring the additional interest in the investee to the current basis of the investor’s previously held interest and adopt the equity method of accounting as of the date the investment qualifies for equity method accounting. The amendments in this standard are effective for fiscal years (including interim periods) beginning after December 15, 2016, with early adoption permitted. The Company is currently evaluating the impact of this standard on its condensed consolidated financial statements.
In March 2016, the FASB issued ASU No. 2016-06, Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments (“ASU 2016-06”). ASU 2016-06 simplifies the embedded derivative analysis for debt instruments containing contingent call or put options by removing the requirement to assess whether a contingent event is related to interest rates or credit risks. The amendments in this standard are effective for fiscal years (including interim periods) beginning after December 15,
2016, with early adoption permitted. The adoption of ASU 2016-06 is not expected to have an impact on the Company’s condensed consolidated financial statements.
In March 2016, the FASB issued ASU No. 2016-05, Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships (“ASU 2016-05”). ASU 2016-05 clarifies that a change in the counterparty to a derivative instrument that has been designated as a hedging instrument under Topic 815 does not, in and of itself, require dedesignation of that hedging relationship provided that all other hedge accounting criteria continue to be met. The amendments in this standard are effective for fiscal years (including interim periods) beginning after December 15, 2016, with early adoption permitted. An entity can elect to adopt the amendments of ASU 2016-05 on either a prospective or modified retrospective basis. The adoption of ASU 2016-05 is not expected to have an impact on the Company’s condensed consolidated financial statements.
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which supersedes the lease accounting requirements in Accounting Standards Codification (“ASC”) Topic 840, Leases. ASU 2016-02 provides principles for the recognition, measurement, presentation and disclosure of leases for both lessees and lessors. The new standard requires lessees to apply a dual approach, classifying leases as either finance or operating leases based on the principle of whether or not the lease is effectively a financed purchase by the lessee. This classification will determine whether lease expense is recognized based on an effective interest method or on a straight-line basis over the term of the lease, respectively. A lessee is also required to record a right-of-use asset and a lease liability for all leases with a term of greater than twelve months regardless of classification. Leases with a term of twelve months or less will be accounted for similar to existing guidance for operating leases. The amendments in this standard are effective for fiscal years (including interim periods) beginning after December 15, 2018, with early adoption permitted and modified retrospective application required. The Company is currently evaluating the impact of this standard on its condensed consolidated financial statements.
In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments — Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities (“ASU 2016-01”). ASU 2016-01 requires that (i) equity investments in unconsolidated entities that are not accounted for under the equity method of accounting generally be measured at fair value with changes recognized in net income (loss) and (ii) when the fair value option has been elected for financial liabilities, changes in fair value due to instrument-specific credit risk be recognized separately in other comprehensive income (loss). Additionally, ASU 2016-01 changes the presentation and disclosure requirements for financial instruments. The amendments in this standard are effective for fiscal years (including interim periods) beginning after December 15, 2017, with early adoption not permitted. The Company is currently evaluating the impact of this standard on its condensed consolidated financial statements.
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which supersedes the revenue recognition requirements in ASC Topic 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 years (including interim periods) beginning after December 15, 2016. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, which defers the effective date by one year, with early adoption permitted as of the original effective date. ASU 2014-09 allows for either a full retrospective or a modified retrospective transition method. In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606) — Principal versus Agent Considerations (“ASU 2016-08”). ASU 2016-08 provides clarifying guidance regarding the application of ASU 2014-09 when another party, along with the reporting entity, is involved in providing a good or a service to a customer. In these circumstances, an entity is required to determine whether the nature of its promise is to provide that good or service to the customer (that is, the entity is a principal) or to arrange for the good or service to be provided to the customer by the other party (that is, the entity is an agent). ASU 2016-08 clarifies the implementation guidance on principal versus agent considerations. In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606) — Identifying Performance Obligations and Licensing (“ASU 2016-10”). ASU 2016-10 further amends the guidance with respect to certain implementation issues on identifying performance obligations and accounting for licenses of intellectual property. The new revenue standard permits companies to either apply the requirements retrospectively to all prior periods presented or apply the requirements in the year of adoption through a cumulative adjustment. The amendments in these standards, along with ASU 2014-09, are effective for fiscal years (including interim periods) beginning after December 15, 2017. The Company is currently evaluating the impact of these standards on its condensed consolidated financial statements.
3. Inventories
The cost of inventory is recorded using the last-in, first-out (“LIFO”) method. An actual valuation of inventory under the LIFO method can be made only at the end of each year based on the inventory levels and costs at that time. Accordingly, interim LIFO calculations are based on management’s estimates of expected year-end inventory levels and costs and are subject to the final year-end LIFO inventory valuation. Costs include crude oil and other feedstocks, labor, processing costs and refining overhead costs. Inventories are valued at the lower of cost or market value. The replacement cost of these inventories, based on current market values, would have been $69.3 million and $41.0 million lower as of March 31, 2016, and December 31, 2015, respectively.
Inventories consist of the following (in millions):
|
| | | | | | | |
| March 31, 2016 | | December 31, 2015 |
Raw materials | $ | 51.6 |
| | $ | 47.9 |
|
Work in process | 72.7 |
| | 64.0 |
|
Finished goods | 305.6 |
| | 272.5 |
|
| $ | 429.9 |
| | $ | 384.4 |
|
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 March 31, 2016 and 2015, the Company recorded $8.1 million of gains and $13.2 million of losses, respectively, in cost of sales in the condensed consolidated statements of operations due to the lower of cost or market (“LCM”) valuation.
4. Investment in Unconsolidated Affiliates
The following table summarizes the Company’s investments in unconsolidated affiliates as of March 31, 2016, and December 31, 2015 (in millions):
|
| | | | | | | | | | | | | |
| Three Months Ended March 31, 2016 | | Year Ended December 31, 2015 |
| Investment | | Percent Ownership | | Investment | | Percent Ownership |
Dakota Prairie Refining, LLC | $ | 113.7 |
| | 50 | % | | $ | 124.7 |
| | 50 | % |
Other | 2.1 |
| | | | 1.3 |
| | |
Total | $ | 115.8 |
| | | | $ | 126.0 |
| | |
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, cash contributions from the Company and proceeds of $75.0 million from a 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. In addition to the $300.0 million commitment outlined in the joint venture agreement, MDU and the Company made additional cash contributions, net of distributions, in the amount of $80.6 million and $88.7 million, respectively, to fund construction costs and working capital needs. Additionally, MDU or the Company may make cash contributions or loans to fund working capital needs. The joint venture allocates profits on a 50%/50% basis to the Company and MDU, except for the adjustments made to the Company’s share for repayment of the principal and interest of the $75.0 million term loan as noted above. 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 to the joint venture. The Company is providing refinery operations, crude oil procurement and refined product marketing expertise to the joint venture. Dakota Prairie commenced sales of finished products in May 2015.
The following represents summary financial information for Dakota Prairie, presented at 100% (in millions):
|
| | | | | | | |
| Three Months Ended March 31, |
| 2016 | | 2015 |
Operating revenue | $ | 45.1 |
| | $ | 1.7 |
|
Operating loss | $ | (20.8 | ) | | $ | (7.0 | ) |
Net loss | $ | (21.6 | ) | | $ | (7.1 | ) |
5. Commitments and Contingencies
From time to time, the Company is a party to certain claims and litigation incidental to its business, including claims made by various 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 conducts crude oil and specialty hydrocarbon refining, blending and terminal operations in addition to providing oilfield services and products, which activities 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. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties; the imposition of investigatory, remedial or corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the permitting, development or expansion of projects, and the issuance of injunctive relief limiting or prohibiting Company activities. Moreover, 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, some of which legal requirements are discussed below, could significantly increase the Company’s operational or compliance expenditures.
Remediation of subsurface contamination is in process at certain of the Company’s refinery sites and is being overseen by the appropriate state agencies. Based on current investigative and remedial activities, the Company believes that the soil and groundwater contamination at these refineries can be controlled or remedied without having a material adverse effect on the Company’s financial condition. However, such costs are often unpredictable and, therefore, there can be no assurance that the future costs will not become material.
San Antonio Refinery
In connection with the acquisition of the San Antonio refinery, 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 HollyFrontier Corporation
(“Holly”), the owner and operator of the Montana refinery prior to its acquisition by Connacher, under an asset purchase agreement between Holly and Connacher, pursuant to which Connacher acquired the Montana refinery. Under this asset purchase agreement, Holly agreed to indemnify Connacher and Montana Refining Company, Inc., subject to 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 $18.2 million as of March 31, 2016, of which $14.6 million was capitalized into the cost of the Company’s recently completed expansion project and $3.6 million was expensed. The Company continues to believe that Holly is responsible to indemnify the Company for these remediation expenses disputed by Holly, and on September 22, 2015, the Company initiated a lawsuit against Holly and the sellers of the Montana refinery under the asset purchase agreement. On November 24, 2015, Holly and the sellers of the Montana refinery under the asset purchase agreement filed a motion to dismiss the case pending arbitration. On February 10, 2016, the court granted Holly’s motion to dismiss the case and ordered that all of the claims be addressed in arbitration. In the event the Company is unsuccessful, the Company will be responsible for those remediation expenses. The Company expects that it may incur some costs to remediate other environmental conditions at the Montana 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.
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 $4.0 million as of March 31, 2016, 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 the three months ended March 31, 2016, the Company incurred no costs related to installing process equipment at the Superior refinery pursuant to the EPA fuel content regulations. For the three months ended March 31, 2015, the Company incurred approximately $0.3 million of costs related to installing process equipment at the Superior refinery pursuant to the EPA fuel content regulations.
On June 29, 2012, the EPA issued a Finding of Violation/Notice of Violation to the Superior refinery, which included a proposed penalty amount of $0.1 million. This finding is in response to information provided to the EPA by the Company in response to an information request. The EPA alleges that the efficiency of the flares at the Superior refinery is lower than regulatory requirements. The Company is contesting the allegations and 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 position 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 acquisition of the Superior refinery, which named the Company and Murphy Oil as insureds and covers environmental conditions existing at the Superior refinery prior to the acquisition of the Superior refinery.
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 March 31, 2016 and 2015, the Company incurred approximately $0.4 million and $1.0 million, respectively, of such expenditures and estimates additional expenditures of approximately $3.0 million to $5.0 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 position 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 March 31, 2016, the trust fund contained approximately $0.8 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 acquisition of Bel-Ray, the Company became a party to the Weston Agreement.
Weston has been addressing the environmental issues at the Bel-Ray facility over time, and the next phase will address the groundwater issues, which extend offsite.
Occupational Health and Safety
The Company is subject to various laws and regulations relating to occupational health and safety, including OSHA and comparable state laws. These laws and regulations strictly govern the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in the Company’s operations and that this information be provided to employees, contractors, state and local government authorities and customers. The Company maintains safety and training programs as part of its ongoing efforts to ensure compliance with applicable laws and regulations. The Company conducts periodic audits of Process Safety Management (“PSM”) systems at each of its locations subject to the PSM standard. The Company’s compliance with applicable health and safety laws and regulations has required, and continues to require, substantial expenditures. Changes in occupational safety and health laws and regulations or a finding of non-compliance with current laws and regulations could result in additional capital expenditures or operating expenses, as well as civil penalties and, in the event of a serious injury or fatality, criminal charges.
The Company has completed studies to assess the adequacy of its PSM practices at its Shreveport refinery with respect to certain consensus codes and standards. During the three months ended March 31, 2016 and 2015, the Company incurred $0.3 million and $0.1 million, respectively, of related capital expenditures and expects to incur up to $1.0 million during 2016 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. 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 financial position or results of operations.
Labor Matters
The Company has employees covered by various collective bargaining agreements. The Company’s Cotton Valley facility collective bargaining agreement was ratified on April 1, 2016, and will expire on March 31, 2019. The Dickinson facility collective bargaining agreement was ratified on April 1, 2016, and will expire on March 31, 2019. The Shreveport refinery collective bargaining agreement was extended until a new agreement is reached or is voided by either party with a 30-day written notice. The Missouri esters facility collective bargaining agreement was extended until a new agreement is reached or is voided by either party with a 30-day written notice.
Legal Proceedings
The Company is subject to 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 the 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 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.
Standby Letters of Credit
The Company has agreements with various financial institutions for standby letters of credit which have been issued primarily to vendors and for the benefit of Dakota Prairie to support its revolving credit facility. As of March 31, 2016, and December 31, 2015, the Company had outstanding standby letters of credit of $63.5 million and $66.8 million, respectively, under its senior secured revolving credit facility (the “revolving credit facility”). Refer to Note 6 for additional information regarding the Company’s revolving credit facility. At March 31, 2016, and December 31, 2015, 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 March 31, 2016, and December 31, 2015) with the consent of the Agent (as defined below).
As of March 31, 2016, and December 31, 2015, the Company had availability to issue letters of credit of $101.3 million and $233.5 million, respectively, under its revolving credit facility.
6. Long-Term Debt
Long-term debt consisted of the following (in millions):
|
| | | | | | | |
| March 31, 2016 | | December 31, 2015 |
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 3.3% at March 31, 2016 | $ | 294.9 |
| | $ | 111.0 |
|
Borrowings under 2021 Notes, interest at a fixed rate of 6.50%, interest payments semiannually, borrowings due April 2021, effective interest rate of 6.8% for the three months ended March 31, 2016 | 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 three months ended March 31, 2016 (1) | 352.8 |
| | 352.9 |
|
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 three months ended March 31, 2016 | 325.0 |
| | 325.0 |
|
Related party note payable, interest at a fixed rate of 6.0% on a portion of the note, interest payments at various dates, borrowings due July 2016, weighted average interest rate of 6.0% for the three months ended March 31, 2016 | 72.4 |
| | 73.5 |
|
Capital lease obligations, at various interest rates, interest and principal payments monthly through October 2034 | 46.1 |
| | 46.4 |
|
Less unamortized debt issuance costs (2) | (27.7 | ) | | (28.9 | ) |
Less unamortized discounts | (6.3 | ) | | (6.5 | ) |
Total long-term debt | 1,957.2 |
| | 1,773.4 |
|
Less current portion of note payable — related party | 72.4 |
| | 73.5 |
|
Less current portion of long-term debt | 1.7 |
| | 1.7 |
|
| $ | 1,883.1 |
| | $ | 1,698.2 |
|
| |
(1) | The balance includes a fair value interest rate hedge adjustment, which increased the debt balance by $2.8 million and $2.9 million as of March 31, 2016, and December 31, 2015, respectively (refer to Note 7 for additional information on the interest rate swap designated as a fair value hedge). |
| |
(2) | Deferred debt issuance costs are being amortized by the effective interest rate method over the lives of the related debt instruments. These amounts are net of accumulated amortization of $9.4 million and $8.1 million at March 31, 2016, and December 31, 2015, respectively. |
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 9.625% senior notes due 2020 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.
On March 27, 2015, in connection with the issuance and sale of the 2023 Notes, 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 offer 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. On December 11, 2015, the Company filed an exchange offer registration statement for the 2023 Notes with the SEC, which was declared effective on January 28, 2016. The exchange offer was completed on March 7, 2016, thereby fulfilling all of the requirements of the 2023 Notes registration rights agreement.
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 ADF Holdings, Inc., the parent company of Anchor Drilling Fluids USA, Inc. (subsequently converted to ADF Holdings, LLC and Anchor Drilling Fluids USA, LLC), 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.
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.
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 S&P Global Ratings (“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 March 31, 2016, the Company’s Fixed Charge Coverage Ratio (as defined in the indentures governing the 2021, 2022 and 2023 Notes) was 1.0 to 1.0. As of March 31, 2016, 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 either the prime rate plus a basis points margin or the London Interbank Offered Rate (“LIBOR”) plus a basis points margin, at the Company’s option. As of March 31, 2016, the margin was 75 basis points for prime rate loans and 175 basis points for LIBOR rate loans; however, the margin can fluctuate quarterly based on the Company’s average availability for additional borrowings under the revolving credit facility during the preceding fiscal 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 as of March 31, 2016, under the revolving credit facility was $459.7 million. As of March 31, 2016, the Company had $294.9 million in outstanding borrowings under the revolving credit facility and outstanding standby letters of credit of $63.5 million, leaving $101.3 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 (collectively, the “Credit Agreement Collateral”).
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 (which amount is subject to increase in proportion to revolving commitment increases), then the Company will be required to maintain as of the end of each fiscal quarter a Fixed Charge Coverage Ratio (as defined in the revolving credit agreement) of at least 1.0 to 1.0.
As of March 31, 2016, the Company was in compliance with all covenants under the revolving credit facility.
Maturities of Long-Term Debt
As of March 31, 2016, principal payments on debt obligations and future minimum rentals on capital lease obligations are as follows (in millions):
|
| | | | |
Year | | Maturity |
2016 | | $ | 74.7 |
|
2017 | | 1.6 |
|
2018 | | 1.5 |
|
2019 | | 296.2 |
|
2020 | | 0.9 |
|
Thereafter | | 1,614.5 |
|
Total | | $ | 1,989.4 |
|
7. 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, options and futures, to attempt to reduce the Company’s exposure with respect to:
| |
• | crude oil purchases and sales; |
| |
• | fuel product sales and 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 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 8) 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.
The following tables summarize the Company’s gross fair values of its derivative instruments, presenting the impact of offsetting derivative assets in the Company’s condensed consolidated balance sheets as of March 31, 2016, and December 31, 2015 (in millions):
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | March 31, 2016 | | December 31, 2015 |
| | 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 not designated as hedges: | | | | | | | | | | |
Fuel products segment: | | | | | | | | | | | | |
Crude oil swaps | | $ | 3.8 |
| | $ | (3.8 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Crude oil basis swaps | | 1.0 |
| | (1.0 | ) | | — |
| | 0.4 |
| | (0.4 | ) | | — |
|
Crude oil percentage basis swaps | | 0.1 |
| | (0.1 | ) | | — |
| | 0.2 |
| | (0.2 | ) | | — |
|
Crude oil options | | 0.6 |
| | (0.6 | ) | | — |
| | 0.8 |
| | (0.8 | ) | | — |
|
Total derivative instruments not designated as hedges | | 5.5 |
| | (5.5 | ) | | — |
| | 1.4 |
| | (1.4 | ) | | — |
|
Total derivative instruments | | $ | 5.5 |
|
| $ | (5.5 | ) |
| $ | — |
|
| $ | 1.4 |
|
| $ | (1.4 | ) |
| $ | — |
|
The following tables summarize the Company’s gross fair values of its derivative instruments, presenting the impact of offsetting derivative liabilities in the Company’s condensed consolidated balance sheets as of March 31, 2016, and December 31, 2015 (in millions):
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | March 31, 2016 | | December 31, 2015 |
| | 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 not designated as hedges: | | | | | | | | | | |
Specialty products segment: | | | | | | | | | | | | |
Natural gas swaps | | $ | (13.0 | ) | | $ | — |
| | $ | (13.0 | ) | | $ | (14.9 | ) | | $ | — |
| | $ | (14.9 | ) |
Natural gas collars | | (0.7 | ) | | — |
| | (0.7 | ) | | (0.9 | ) | | — |
| | (0.9 | ) |
Fuel products segment: | | | | | | | | | | | | |
Crude oil swaps | | (7.5 | ) | | 3.8 |
| | (3.7 | ) | | (5.2 | ) | | — |
| | (5.2 | ) |
Crude oil basis swaps | | (4.1 | ) | | 1.0 |
| | (3.1 | ) | | (0.7 | ) | | 0.4 |
| | (0.3 | ) |
Crude oil percentage basis swaps | | (6.5 | ) | | 0.1 |
| | (6.4 | ) | | (6.9 | ) | | 0.2 |
| | (6.7 | ) |
Crude oil options | | (1.5 | ) | | 0.6 |
| | (0.9 | ) | | (1.1 | ) | | 0.8 |
| | (0.3 | ) |
Gasoline crack spread swaps | | — |
| | — |
| | — |
| | (4.3 | ) | | — |
| | (4.3 | ) |
Natural gas swaps | | (1.5 | ) | | — |
| | (1.5 | ) | | (1.3 | ) | | — |
| | (1.3 | ) |
Total derivative instruments not designated as hedges | (34.8 | ) | | 5.5 |
| | (29.3 | ) | | (35.3 | ) | | 1.4 |
| | (33.9 | ) |
Total derivative instruments | $ | (34.8 | ) |
| $ | 5.5 |
|
| $ | (29.3 | ) |
| $ | (35.3 | ) |
| $ | 1.4 |
|
| $ | (33.9 | ) |
The Company is exposed to credit risk in the event of nonperformance by its counterparties on these derivative transactions. The Company does not expect nonperformance on any derivative instruments, however, no assurances can be provided. The Company’s credit exposure related to these derivative instruments is represented by the fair value of contracts reported as derivative assets. As of March 31, 2016, the Company had no counterparties in which the derivatives held were net assets. As of December 31, 2015, the Company had no counterparties in which the derivatives held were net assets. To manage credit risk, the Company selects and periodically reviews counterparties based on credit ratings. The Company primarily executes its derivative instruments with large financial institutions that have ratings of at least 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 March 31, 2016, or December 31, 2015. The Company’s contracts with these counterparties allow for netting of derivative instruments executed under each contract. Collateral received from counterparties is reported in other current liabilities, and collateral held by counterparties is reported in deposits on the Company’s condensed consolidated balance sheets and is not netted against derivative assets or liabilities. As of March 31, 2016, and December 31, 2015, 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 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 in the unaudited condensed consolidated statements of operations.
The Company recorded the following amounts in its condensed consolidated balance sheets, unaudited condensed consolidated statements of operations, unaudited condensed consolidated statements of comprehensive income (loss) and unaudited condensed consolidated statements of partners’ capital as of and for the three months ended March 31, 2016 and 2015, 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 Loss on Derivatives (Effective Portion) | | Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Income (Loss) (Effective Portion) | | Amount of Gain (Loss) Recognized in Net Income (Loss) on Derivatives (Ineffective Portion) |
Three Months Ended | | Location of Gain (Loss) | | Three Months Ended | | Location of Gain (Loss) | | Three Months Ended |
March 31, | | | March 31, | | | March 31, |
2016 | | 2015 | | | 2016 | | 2015 | | | 2016 | | 2015 |
Specialty products segment: | | | | | | | | | | | | | | |
Crude oil swaps | $ | — |
| | $ | — |
| | Cost of sales | | $ | (0.7 | ) | | $ | (0.4 | ) | | Unrealized/ Realized | | $ | — |
| | $ | — |
|
Fuel products segment: | | | | | | | | | | | | | | |
Crude oil swaps | (1.3 | ) | | (6.3 | ) | | Cost of sales | | (13.2 | ) | | (21.5 | ) | | Unrealized/ Realized | | — |
| | (0.2 | ) |
Gasoline swaps | — |
| | 0.8 |
| | Sales | | — |
| | 14.0 |
| | Unrealized/ Realized | | — |
| | 0.7 |
|
Diesel swaps | 1.3 |
| | 0.1 |
| | Sales | | 16.0 |
| | 4.8 |
| | Unrealized/ Realized | | — |
| | — |
|
Jet fuel swaps | — |
| | 0.3 |
| | Sales | | — |
| | 1.4 |
| | Unrealized/ Realized | | — |
| | — |
|
Total | $ | — |
| | $ | (5.1 | ) | | | | $ | 2.1 |
| | $ | (1.7 | ) | | | | $ | — |
| | $ | 0.5 |
|
The effective portion of the cash flow hedges classified in accumulated other comprehensive loss was gains of $4.3 million and $6.4 million as of March 31, 2016, and December 31, 2015, respectively. Absent a change in the fair market value of the underlying transactions, except for any underlying transactions pertaining to the payment of interest on existing financial instruments, the following other comprehensive income (loss) at March 31, 2016, will be reclassified to earnings by December 31, 2016, with balances being recognized as follows (in millions):
|
| | | |
Year | Accumulated Other Comprehensive Income |
2016 | $ | 4.3 |
|
Total | $ | 4.3 |
|
Derivative Instruments Designated as Fair Value Hedges
For derivative instruments that are designated and qualify as a fair value hedge (which are limited to interest rate swaps), 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 months ended March 31, 2016 and 2015, related to its derivative instrument designated as a fair value hedge (in millions):
|
| | | | | | | | | | | | | | | | | | | | | |
| Location of Loss of Derivative |
| Amount of Loss Recognized in Net Income (Loss) |
| Hedged Item | | Location of Gain on Hedged Item |
| Amount of Gain Recognized in Net Income (Loss) |
| Three Months Ended March 31, |
|
| Three Months Ended March 31, |
| 2016 | | 2015 |
|
| 2016 | | 2015 |
Swaps not allocated to a specific segment: | |
|
|
| |
|
|
| | |
Interest rate swap | Interest expense |
| $ | 0.1 |
| | $ | 0.2 |
|
| 2022 Notes | | Interest income |
| $ | — |
| | $ | — |
|
Total |
|
| $ | 0.1 |
| | $ | 0.2 |
|
|
| |
|
| $ | — |
| | $ | — |
|
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 and platinum swaps that do not qualify as cash flow hedges for accounting purposes as they are determined not to be highly effective in offsetting changes in the cash flows associated with crude oil purchases and gasoline and diesel sales at the Company’s Superior refinery.
The amount reclassified from accumulated other comprehensive 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 in the unaudited condensed consolidated statements of operations for the three months ended March 31, 2016 and 2015 (in millions):
|
| | | | | | | |
| Three Months Ended March 31, |
| 2016 | | 2015 |
Realized gain on derivative instruments | $ | — |
| | $ | 1.2 |
|
The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations for the three months ended March 31, 2016 and 2015, 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 March 31, | | Three Months Ended March 31, |
2016 | | 2015 | | 2016 | | 2015 |
Specialty products segment: | | | | | | | |
Natural gas swaps | $ | (3.7 | ) | | $ | (2.1 | ) | | $ | 2.0 |
| | $ | (3.2 | ) |
Platinum swaps | — |
| | — |
| | — |
| | (0.1 | ) |
Fuel products segment: | | | | | | | |
Crude oil swaps | (0.9 | ) | | (48.3 | ) | | 1.5 |
| | 50.2 |
|
Crude oil basis swaps | — |
| | 1.0 |
| | (2.6 | ) | | (0.4 | ) |
Crude oil percentage basis swaps | (3.9 | ) | | — |
| | 0.2 |
| | — |
|
Crude oil options | — |
| | — |
| | (0.6 | ) | | — |
|
Crude oil futures | (2.0 | ) | | — |
| | — |
| | — |
|
Gasoline swaps | — |
| | (2.0 | ) | | — |
| | (1.1 | ) |
Gasoline crack spread swaps | (1.2 | ) | | (0.8 | ) | | 4.3 |
| | (1.5 | ) |
Diesel swaps | — |
| | 58.0 |
| | — |
| | (63.4 | ) |
Diesel crack spread swaps | — |
| | 0.9 |
| | — |
| | (6.4 | ) |
Jet fuel swaps | — |
| | 1.6 |
| | — |
| | (1.6 | ) |
Natural gas swaps | (0.6 | ) | | — |
| | (0.2 | ) | | (0.3 | ) |
Total | $ | (12.3 | ) | | $ | 8.3 |
| | $ | 4.6 |
| | $ | (27.8 | ) |
Derivative Positions — Specialty Products Segment
Natural Gas Swap Contracts
At March 31, 2016, the Company had the following derivatives related to natural gas purchases in its specialty products segment, none of which are designated as hedges:
|
| | | | | | |
Natural Gas Swap Contracts by Expiration Dates | MMBtu |
| $/MMBtu |
Second Quarter 2016 | 1,380,000 |
|
| $ | 4.26 |
|
Third Quarter 2016 | 1,380,000 |
|
| $ | 4.26 |
|
Fourth Quarter 2016 | 1,540,000 |
|
| $ | 4.14 |
|
Calendar Year 2017 | 4,950,000 |
| | $ | 3.85 |
|
Total | 9,250,000 |
|
|
|
Average price |
|
| $ | 4.02 |
|
At December 31, 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 |
First Quarter 2016 | 1,580,000 |
|
| $ | 4.24 |
|
Second Quarter 2016 | 1,380,000 |
|
| $ | 4.26 |
|
Third Quarter 2016 | 1,380,000 |
|
| $ | 4.26 |
|
Fourth Quarter 2016 | 1,540,000 |
|
| $ | 4.14 |
|
Calendar Year 2017 | 4,950,000 |
|
| $ | 3.85 |
|
Total | 10,830,000 |
|
|
|
Average price |
|
| $ | 4.05 |
|
Natural Gas Collars
At March 31, 2016, 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) |
Second Quarter 2016 | 180,000 |
| | $ | 4.25 |
| | $ | 3.89 |
|
Third Quarter 2016 | 180,000 |
| | $ | 4.25 |
| | $ | 3.89 |
|
Fourth Quarter 2016 | 60,000 |
| | $ | 4.25 |
| | $ | 3.89 |
|
Total | 420,000 |
| | | | |
Average price | | | $ | 4.25 |
| | $ | 3.89 |
|
At December 31, 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) |
First Quarter 2016 | 180,000 |
| | $ | 4.25 |
| | $ | 3.89 |
|
Second Quarter 2016 | 180,000 |
| | $ | 4.25 |
| | $ | 3.89 |
|
Third Quarter 2016 | 180,000 |
| | $ | 4.25 |
| | $ | 3.89 |
|
Fourth Quarter 2016 | 60,000 |
| | $ | 4.25 |
| | $ | 3.89 |
|
Total | 600,000 |
| | | | |
Average price | | | $ | 4.25 |
| | $ | 3.89 |
|
Derivative Positions — Fuel Products Segment
Crude Oil Swap Contracts
At March 31, 2016, the Company had the following derivatives related to crude oil purchases in its fuel products segment, none of which are designated as hedges:
|
| | | | | | | | | |
Crude Oil Swap Contracts by Expiration Dates | Barrels Purchased |
| BPD |
| Average Swap ($/Bbl) |
Second Quarter 2016 | 54,120 |
| | 595 |
| | $ | 39.32 |
|
Third Quarter 2016 | 398,893 |
| | 4,336 |
| | $ | 39.52 |
|
Fourth Quarter 2016 | 398,893 |
| | 4,336 |
| | $ | 39.52 |
|
Calendar Year 2017 | 1,297,976 |
| | 3,556 |
| | $ | 48.87 |
|
Total | 2,149,882 |
|
|
|
|
|
Average price |
|
|
|
| $ | 45.16 |
|
At March 31, 2016, 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) |
Calendar Year 2017 | 528,520 |
| | 1,448 |
| | $ | 41.56 |
|
Total | 528,520 |
| | | | |
Average price | | | | | $ | 41.56 |
|
At December 31, 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) |
First Quarter 2016 | 29,120 |
| | 320 |
| | $ | 44.06 |
|
Second Quarter 2016 | 29,120 |
| | 320 |
| | $ | 44.06 |
|
Third Quarter 2016 | 29,440 |
| | 320 |
| | $ | 44.06 |
|
Fourth Quarter 2016 | 29,440 |
| | 320 |
| | $ | 44.06 |
|
Calendar Year 2017 | 630,720 |
| | 1,728 |
| | $ | 54.94 |
|
Total | 747,840 |
| | | | |
Average price | | | | | $ | 53.24 |
|
Crude Oil Basis Swap Contracts
The Company has entered into crude oil basis swaps to mitigate the risk of future changes in pricing differentials between LLS and NYMEX WTI. At March 31, 2016, the Company had the following derivatives related to crude oil basis swaps in its fuel products segment, none of which are designated as hedges:
|
| | | | | | | | | |
Crude Oil Basis Swap Contracts by Expiration Dates | Barrels Purchased | | BPD | | Average Differential to NYMEX WTI ($/Bbl) |
Second Quarter 2016 | 365,000 |
| | 5,000 |
| | $ | 1.80 |
|
Third Quarter 2016 | 460,000 |
| | 5,000 |
| | $ | 1.80 |
|
Fourth Quarter 2016 | 460,000 |
| | 5,000 |
| | $ | 1.80 |
|
Total | 1,285,000 |
| | | | |
Average differential | | | | | $ | 1.80 |
|
At December 31, 2015, the Company had the following derivatives related to crude oil basis swaps in its fuel products segment, none of which are designated as hedges:
|
| | | | | | | | | |
Crude Oil Basis Swap Contracts by Expiration Dates | Barrels Purchased | | BPD | | Average Differential to NYMEX WTI ($/Bbl) |
First Quarter 2016 | 182,000 |
| | 2,000 |
| | $ | 2.40 |
|
Second Quarter 2016 | 182,000 |
| | 2,000 |
| | $ | 2.40 |
|
Third Quarter 2016 | 184,000 |
| | 2,000 |
| | $ | 2.40 |
|
Fourth Quarter 2016 | 184,000 |
| | 2,000 |
| | $ | 2.40 |
|
Total | 732,000 |
| | | | |
Average differential | | | | | $ | 2.40 |
|
The Company has entered into crude oil basis swaps to mitigate the risk of future changes in pricing differentials between WCS and NYMEX WTI. At March 31, 2016, the Company had the following derivatives related to crude oil basis swaps in its fuel products segment, none of which are designated as hedges:
|
| | | | | | | | | |
Crude Oil Basis Swap Contracts by Expiration Dates | Barrels Purchased | | BPD | | Average Differential to NYMEX WTI ($/Bbl) |
Second Quarter 2016 | 697,000 |
| | 7,659 |
| | $ | (14.02 | ) |
Third Quarter 2016 | 1,196,000 |
| | 13,000 |
| | $ | (13.18 | ) |
Fourth Quarter 2016 | 1,196,000 |
| | 13,000 |
| | $ | (13.18 | ) |
Calendar Year 2017 | 2,555,000 |
| | 7,000 |
| | $ | (13.22 | ) |
Total | 5,644,000 |
| | | | |
Average differential | | | | | $ | (13.31 | ) |
At December 31, 2015, the Company had the following derivatives related to crude oil basis swaps in its fuel products segment, none of which are designated as hedges:
|
| | | | | | | | | |
Crude Oil Basis Swap Contracts by Expiration Dates | Barrels Purchased | | BPD | | Average Differential to NYMEX WTI ($/Bbl) |
First Quarter 2016 | 91,000 |
| | 1,000 |
| | $ | (14.10 | ) |
Second Quarter 2016 | 91,000 |
| | 1,000 |
| | $ | (14.10 | ) |
Third Quarter 2016 | 92,000 |
| | 1,000 |
| | $ | (14.10 | ) |
Fourth Quarter 2016 | 92,000 |
| | 1,000 |
| | $ | (14.10 | ) |
Calendar Year 2017 | 365,000 |
| | 1,000 |
| | $ | (13.70 | ) |
Total | 731,000 |
| | | | |
Average differential | | | | | $ | (13.90 | ) |
Crude Oil Percentage Basis Swap Contracts
The Company has entered into derivative instruments to secure a percentage differential on WCS crude oil to NYMEX WTI. At March 31, 2016, the Company had the following derivatives related to crude oil percentage basis swaps in its fuel products segment, none of which are designated as hedges:
|
| | | | | | | | |
Crude Oil Percentage Basis Swap Contracts by Expiration Dates | Barrels Purchased | | BPD | | Fixed Percentage of NYMEX WTI (Average % of WTI/Bbl) |
Second Quarter 2016 | 728,000 |
| | 8,000 |
| | 73.5 | % |
Third Quarter 2016 | 736,000 |
| | 8,000 |
| | 73.5 | % |
Fourth Quarter 2016 | 736,000 |
| | 8,000 |
| | 73.5 | % |
Calendar Year 2017 | 1,095,000 |
| | 3,000 |
| | 72.3 | % |
Total | 3,295,000 |
| | | | |
Average percentage | | | | | 73.1 | % |
At December 31, 2015, the Company had the following derivatives related to crude oil percentage basis swaps in its fuel products segment, none of which are designated as hedges:
|
| | | | | | | | |
Crude Oil Percentage Basis Swap Contracts by Expiration Dates | Barrels Purchased |
| BPD |
| Fixed Percentage of NYMEX WTI (Average % of WTI/Bbl) |
First Quarter 2016 | 728,000 |
| | 8,000 |
| | 73.5 | % |
Second Quarter 2016 | 728,000 |
|
| 8,000 |
| | 73.5 | % |
Third Quarter 2016 | 736,000 |
|
| 8,000 |
| | 73.5 | % |
Fourth Quarter 2016 | 736,000 |
| | 8,000 |
| | 73.5 | % |
Calendar Year 2017 | 730,000 |
| | 2,000 |
| | 73.0 | % |
Total | 3,658,000 |
|
|
|
|
|
Average percentage |
|
|
|
|
|
| 73.4 | % |
Crude Oil Option Contracts
The Company has entered into derivative instruments to mitigate the risk of future changes in the price of NYMEX WTI crude oil. At March 31, 2016, the Company had the following derivatives related to crude oil call option purchases in its fuel products segment, none of which are designated as hedges:
|
| | | | | | | | | |
Crude Oil Option Contracts by Expiration Dates | Barrels Purchased | | BPD | | Average Bought Call ($/Bbl) |
Fourth Quarter 2016 | 350,000 |
| | 11,290 |
| | $ | 55.00 |
|
Total | 350,000 |
| | | | |
Average price | | | | | $ | 55.00 |
|
At March 31, 2016, the Company had the following derivatives related to crude oil call option sales in its fuel products segment, none of which are designated as hedges:
|
| | | | | | | | | |
Crude Oil Option Contracts by Expiration Dates | Barrels Sold | | BPD | | Average Sold Call ($/Bbl) |
Second Quarter 2016 | 300,000 |
| | 9,677 |
| | $ | 41.78 |
|
Total | 300,000 |
| | | | |
Average price | | | | | $ | 41.78 |
|
At March 31, 2016, the Company had the following derivatives related to crude oil put option purchases in its fuel products segment, none of which are designated as hedges:
|
| | | | | | | | | |
Crude Oil Option Contracts by Expiration Dates | Barrels Purchased | | BPD | | Average Bought Put ($/Bbl) |
Second Quarter 2016 | 300,000 |
| | 9,677 |
| | $ | 32.58 |
|
Total | 300,000 |
| | | | |
Average price | | | | | $ | 32.58 |
|
At December 31, 2015, the Company had the following derivatives related to crude oil call option purchases in its fuel products segment, none of which are designated as hedges:
|
| | | | | | | | | |
Crude Oil Option Contracts by Expiration Dates | Barrels Purchased | | BPD | | Average Bought Call ($/Bbl) |
Fourth Quarter 2016 | 350,000 |
| | 11,290 |
| | $ | 55.00 |
|
Total | 350,000 |
| | | | |
Average price | | | | | $ | 55.00 |
|
Gasoline Crack Spread Swap Contracts
At December 31, 2015, the Company had the following derivatives related to gasoline crack spread sales in its fuel products segment, none of which are designated as hedges:
|
| | | | | | | | | |
Gasoline Crack Spread Swap Contracts by Expiration Dates | Barrels Sold | | BPD | | Average Swap ($/Bbl) |
First Quarter 2016 | 873,000 |
| | 9,593 |
| | $ | 8.98 |
|
Total | 873,000 |
| | | | |
Average price | | | | | $ | 8.98 |
|
Natural Gas Swap Contracts
At March 31, 2016, 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 |
Second Quarter 2016 | 603,000 |
| | $ | 2.99 |
|
Third Quarter 2016 | 606,000 |
| | $ | 3.03 |
|
Fourth Quarter 2016 | 790,000 |
| | $ | 3.02 |
|
Total | 1,999,000 |
| | |
Average price | | | $ | 3.01 |
|
At December 31, 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 |
First Quarter 2016 | 603,000 |
| | $ | 3.01 |
|
Second Quarter 2016 | 603,000 |
| | $ | 2.99 |
|
Third Quarter 2016 | 606,000 |
| | $ | 3.03 |
|
Fourth Quarter 2016 | 790,000 |
| | $ | 3.02 |
|
Total | 2,602,000 |
| | |
Average price | | | $ | 3.01 |
|
8. Fair Value Measurements
The Company uses a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. Observable inputs are from sources independent of the Company. Unobservable inputs reflect the Company’s assumptions about the factors market participants would use in valuing the asset or liability developed based upon the best information available in the circumstances. These tiers include the following:
| |
• | Level 1 — inputs include observable unadjusted quoted prices in active markets for identical assets or liabilities |
| |
• | Level 2 — inputs include other than quoted prices in active markets that are either directly or indirectly observable |
| |
• | Level 3 — inputs include unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions |
In determining fair value, the Company uses various valuation techniques and prioritizes the use of observable inputs. The availability of observable inputs varies from instrument to instrument and depends on a variety of factors including the type of instrument, whether the instrument is actively traded and other characteristics particular to the instrument. For many financial instruments, pricing inputs are readily observable in the market, the valuation methodology used is widely accepted by market participants and the valuation does not require significant management judgment. For other financial instruments, pricing inputs are less observable in the marketplace and may require management judgment.
Recurring Fair Value Measurements
Derivative Assets and Liabilities
Derivative instruments are reported in the accompanying unaudited condensed consolidated financial statements at fair value. The Company’s derivative instruments consist of over-the-counter (“OTC”) contracts, which are not traded on a public exchange. Substantially all of the Company’s derivative instruments are with counterparties that have long-term credit ratings of at least Baa1 and BBB+ by Moody’s and S&P, respectively.
To estimate the fair values of the Company’s commodity derivative instruments, the Company uses the forward rate, the strike price, contractual notional amounts, the risk free rate of return and contract maturity. To estimate the fair value of the Company’s fixed-to-floating interest rate swap derivative instrument, the Company uses discounted cash flows, which use observable inputs such as maturity and market interest rates. Various analytical tests are performed to validate the counterparty data. The fair values of the Company’s derivative instruments are adjusted for nonperformance risk and creditworthiness of the hedging entities through the Company’s credit valuation adjustment (“CVA”). The CVA is calculated at the counterparty level utilizing the fair value exposure at each payment date and applying a weighted probability of the appropriate survival and marginal default percentages. The Company uses the counterparty’s marginal default rate and the Company’s survival rate when the Company is in a net asset position at the payment date and uses the Company’s marginal default rate and the counterparty’s survival rate when the Company is in a net liability position at the payment date. As a result of applying the applicable CVA at March 31, 2016, the Company’s net liability was reduced by approximately $2.3 million. As a result of applying the CVA at December 31, 2015, the Company’s net liability was reduced by approximately $1.2 million.
Observable inputs utilized to estimate the fair values of the Company’s derivative instruments were based primarily on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. Based on the use of various unobservable inputs, principally non-performance risk, creditworthiness of the hedging entities and unobservable inputs in the forward rate, the Company has categorized these derivative instruments as Level 3. Significant increases (decreases) in any of those unobservable inputs in isolation would result in a significantly lower (higher) fair value measurement. The Company believes it has obtained the most accurate information available for the types of derivative instruments it holds. See Note 7 for further information on derivative instruments.
Pension Assets
Pension assets are reported at fair value in the accompanying unaudited condensed consolidated financial statements. At March 31, 2016, the Company’s investments associated with its pension plan (as such term is hereinafter defined) primarily consisted of mutual funds. The mutual funds are categorized as Level 2 because inputs used in their valuation are not quoted prices in active markets that are indirectly observable and are valued at the net asset value (“NAV”) of shares in each fund held by the pension plan at quarter end as provided by the third party administrator. Plan investments can be redeemed within a short time frame (10 or so business days), if requested. See Note 10 for further information on pension assets.
Renewable Identification Numbers Obligation
The Company’s RINs obligation (“RINs Obligation”) represents a liability for the purchase of RINs to satisfy the EPA requirement to blend biofuels into the fuel products it produces pursuant to the EPA’s Renewable Fuel Standard. RINs are assigned to biofuels produced in the U.S. as required by the EPA. The EPA sets annual quotas for the percentage of biofuels that must be blended into transportation fuels consumed in the U.S., and as a producer of motor fuels from petroleum, the Company is required to blend biofuels into the fuel products it produces at a rate that will meet the EPA’s annual quota. To the extent the Company is unable to blend biofuels at that rate, it must purchase RINs in the open market to satisfy the annual requirement. The Company’s RINs Obligation is based on the amount of RINs it must purchase net of amounts internally generated and the price of those RINs as of the balance sheet date. The RINs Obligation is categorized as Level 2 and is measured at fair value using the market approach based on quoted prices from an independent pricing service.
For the three months ended March 31, 2016 and 2015, the Company sold approximately 29 million and 49 million RINs, respectively, for gains of $20.8 million and $35.0 million, respectively, net of cost to generate, recorded in cost of sales in the unaudited condensed consolidated statements of operations. As of March 31, 2016 and 2015, the Company had a RINs Obligation of approximately 154 million and 81 million RINs, respectively, which resulted in RINs expense for the three months ended March 31, 2016 and 2015, of approximately $37.6 million and $42.2 million, respectively.
Hierarchy of Recurring Fair Value Measurements
The Company’s recurring assets and liabilities measured at fair value at March 31, 2016, and December 31, 2015, were as follows (in millions):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| March 31, 2016 | | December 31, 2015 |
| Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
Assets: | | | | | | | | | | | | | | | |
Pension plan investments | $ | 0.2 |
| | $ | 48.8 |
| | $ | — |
| | $ | 49.0 |
| | $ | 0.4 |
| | $ | 47.1 |
| | $ | — |
| | $ | 47.5 |
|
Total recurring assets at fair value | $ | 0.2 |
| | $ | 48.8 |
| | $ | — |
| | $ | 49.0 |
| | $ | 0.4 |
| | $ | 47.1 |
| | $ | — |
| | $ | 47.5 |
|
Liabilities: | | | | | | | | | | | | | | | |
Derivative liabilities: | | | | | | | | | | | | | | | |
Crude oil swaps | $ | — |
| | $ | — |
| | $ | (3.7 | ) | | $ | (3.7 | ) | | $ | — |
| | $ | — |
| | $ | (5.2 | ) | | $ | (5.2 | ) |
Crude oil basis swaps | — |
| | — |
| | (3.1 | ) | | (3.1 | ) | | — |
| | — |
| | (0.3 | ) | | (0.3 | ) |
Crude oil percentage basis swaps | — |
| | — |
| | (6.4 | ) | | (6.4 | ) | | — |
| | — |
| | (6.7 | ) | | (6.7 | ) |
Crude oil options | — |
| | — |
| | (0.9 | ) | | (0.9 | ) | | — |
| | — |
| | (0.3 | ) | | (0.3 | ) |
Gasoline crack spread swaps | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (4.3 | ) | | (4.3 | ) |
Natural gas swaps | — |
| | — |
| | (14.5 | ) | | (14.5 | ) | | — |
| | — |
| | (16.2 | ) | | (16.2 | ) |
Natural gas collars | — |
| | — |
| | (0.7 | ) | | (0.7 | ) | | — |
| | — |
| | (0.9 | ) | | (0.9 | ) |
Total derivative liabilities | — |
| | — |
| | (29.3 | ) | | (29.3 | ) | | — |
| | — |
| | (33.9 | ) | | (33.9 | ) |
RINs Obligation | — |
| | (115.2 | ) | | — |
| | (115.2 | ) | | — |
| | (88.4 | ) | | — |
| | (88.4 | ) |
Total recurring liabilities at fair value | $ | — |
| | $ | (115.2 | ) | | $ | (29.3 | ) | | $ | (144.5 | ) | | $ | — |
| | $ | (88.4 | ) | | $ | (33.9 | ) | | $ | (122.3 | ) |
The table below sets forth a summary of net changes in fair value of the Company’s Level 3 financial assets and liabilities for the three months ended March 31, 2016 and 2015 (in millions):
|
| | | | | | | |
| Three Months Ended March 31, |
| 2016 | | 2015 |
Fair value at January 1, | $ | (33.9 | ) | | $ | 17.6 |
|
Realized (gain) loss on derivative instruments | 12.3 |
| | (8.9 | ) |
Unrealized gain (loss) on derivative instruments | 4.6 |
| | (27.9 | ) |
Interest expense, net | (0.1 | ) | | (0.2 | ) |
Change in fair value of cash flow hedges | — |
| | (5.1 | ) |
Settlements | (12.2 | ) | | 2.2 |
|
Transfers in (out) of Level 3 | — |
| | — |
|
Fair value at March 31, | $ | (29.3 | ) | | $ | (22.3 | ) |
Total gain (loss) included in net income (loss) attributable to changes in unrealized gain (loss) relating to financial assets and liabilities held as of March 31, | $ | 4.6 |
| | $ | (27.9 | ) |
All settlements from derivative instruments designated as cash flow hedges and deemed “effective” are included in sales for gasoline, diesel and jet fuel derivatives, and cost of sales for crude oil derivatives in the unaudited condensed consolidated statements of operations in the period that the hedged cash flow occurs. Any “ineffectiveness” associated with these settlements from derivative instruments designated as cash flow hedges are recorded in earnings in realized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. All settlements from derivative instruments designated as fair value hedges are accrued and recorded as an adjustment to interest expense in the unaudited condensed consolidated statements of operations. All settlements from derivative instruments not designated as hedges are recorded in realized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. See Note 7 for further information on derivative instruments.
Nonrecurring Fair Value Measurements
Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances, such as when there is evidence of impairment. Assets and liabilities acquired in business combinations are recorded at their fair value as of the date of acquisition.
The Company reviews for goodwill impairment annually on October 1 and whenever events or changes in circumstances indicate its carrying value may not be recoverable. The fair value of the reporting units is determined using the income approach. The income approach focuses on the income-producing capability of an asset, measuring the current value of the asset by calculating the present value of its future economic benefits such as cash earnings, cost savings, corporate tax structure and product offerings. Value indications are developed by discounting expected cash flows to their present value at a rate of return that incorporates the risk-free rate for the use of funds, the expected rate of inflation and risks associated with the reporting unit. These assets would generally be classified within Level 3, in the event that the Company were required to measure and record such assets at fair value within its unaudited condensed consolidated financial statements.
The Company periodically evaluates the carrying value of long-lived assets to be held and used, including indefinite-lived intangible assets and property plant and equipment, when events or circumstances warrant such a review. Fair value is determined primarily using anticipated cash flows assumed by a market participant discounted at a rate commensurate with the risk involved and these assets would generally be classified within Level 3, in the event that the Company was required to measure and record such assets at fair value within its unaudited condensed consolidated financial statements.
Estimated Fair Value of Financial Instruments
Cash
The carrying value of cash is considered to be representative of its fair value.
Debt
The estimated fair value of long-term debt at March 31, 2016, and December 31, 2015, consists primarily of the senior notes. The estimated aggregate fair value of the Company’s senior notes defined as Level 1 was based upon quoted market prices in an active market. The estimated aggregate fair value of the Company’s senior notes classified as Level 2 was based upon directly observable inputs. The carrying value of borrowings, if any, under the Company’s revolving credit facility and capital lease obligations approximate their fair values as determined by discounted cash flows and are classified as Level 3. See Note 6 for further information on long-term debt.
The Company’s carrying and estimated fair value of the Company’s financial instruments, carried at adjusted historical cost, at March 31, 2016, and December 31, 2015, were as follows (in millions):
|
| | | | | | | | | | | | | | | | | |
| | | March 31, 2016 | | December 31, 2015 |
| Level | | Fair Value | | Carrying Value | | Fair Value | | Carrying Value |
Financial Instrument: | | |