Attached files
file | filename |
---|---|
EXCEL - IDEA: XBRL DOCUMENT - Calumet Specialty Products Partners, L.P. | Financial_Report.xls |
EX-31.2 - EX-31.2 - Calumet Specialty Products Partners, L.P. | h82945exv31w2.htm |
EX-10.1 - EX-10.1 - Calumet Specialty Products Partners, L.P. | h82945exv10w1.htm |
EX-32.1 - EX-32.1 - Calumet Specialty Products Partners, L.P. | h82945exv32w1.htm |
EX-31.1 - EX-31.1 - Calumet Specialty Products Partners, L.P. | h82945exv31w1.htm |
EX-10.2 - EX-10.2 - Calumet Specialty Products Partners, L.P. | h82945exv10w2.htm |
Table of Contents
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2011
OR
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR THE SECURITIES EXCHANGE ACT OF 1934 |
FOR THE TRANSITION PERIOD FROM TO
Commission File number 000-51734
Calumet Specialty Products Partners, L.P.
(Exact Name of Registrant as Specified in Its Charter)
Delaware | 37-1516132 | |
(State or Other Jurisdiction of | (I.R.S. Employer | |
Incorporation or Organization) | Identification Number) | |
2780 Waterfront Parkway East Drive, Suite 200 | ||
Indianapolis, Indiana | 46214 | |
(Address of principal executive officers) | (Zip code) |
Registrants telephone number including area code (317) 328-5660
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 þ No o
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
þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange Act. (Check one):
Large accelerated filer o | Accelerated filer þ | Non-accelerated filer o (Do not check if a smaller reporting company) | Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Act). Yes o No þ
At
August 8, 2011, there were 39,779,778 common units outstanding.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
QUARTERLY REPORT
For the Three and Six Months Ended June 30, 2011
QUARTERLY REPORT
For the Three and Six Months Ended June 30, 2011
Table of Contents
Page | ||||||||
5 | ||||||||
6 | ||||||||
7 | ||||||||
8 | ||||||||
9 | ||||||||
33 | ||||||||
51 | ||||||||
52 | ||||||||
53 | ||||||||
53 | ||||||||
56 | ||||||||
56 | ||||||||
56 | ||||||||
56 | ||||||||
57 | ||||||||
EX-10.1 | ||||||||
EX-10.2 | ||||||||
EX-31.1 | ||||||||
EX-31.2 | ||||||||
EX-32.1 | ||||||||
EX-101 INSTANCE DOCUMENT | ||||||||
EX-101 SCHEMA DOCUMENT | ||||||||
EX-101 CALCULATION LINKBASE DOCUMENT | ||||||||
EX-101 LABELS LINKBASE DOCUMENT | ||||||||
EX-101 PRESENTATION LINKBASE DOCUMENT | ||||||||
EX-101 DEFINITION LINKBASE DOCUMENT |
2
Table of Contents
FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q (this Quarterly Report) includes certain forward-looking
statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the
Securities Act) and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange
Act). These statements can be identified by the use of forward-looking terminology including
may, intend, believe, expect, anticipate, estimate, continue, or other similar words.
The statements regarding (i) estimated capital expenditures as a result of the required audits or
required operational changes included in our settlement with the Louisiana Department of
Environmental Quality (LDEQ) or other environmental and regulatory liabilities, (ii) our
anticipated levels of use of derivatives to mitigate our exposure to crude oil price changes and
fuel products price changes, (iii) the estimated purchase price, potential financing, closing
timeline and all other discussion with respect to the Superior Acquisition (as defined in this
Quarterly Report) and (iv) our ability to meet our financial commitments, minimum quarterly
distributions to our unitholders, debt service obligations, credit agreement covenants,
contingencies and anticipated capital expenditures, as well as other matters discussed in this
Quarterly Report that are not purely historical data, are forward-looking statements. These
statements discuss future expectations or state other forward-looking information and involve
risks and uncertainties. When considering these forward-looking statements, unitholders should keep
in mind the risk factors and other cautionary statements included in this Quarterly Report, our
Quarterly Report filed with the Securities and Exchange Commission (the SEC) on May 6, 2011 (our
2011 First Quarterly Report) and in our Annual Report on Form 10-K filed with the SEC on February
22, 2011 (our 2010 Annual Report). These risk factors and other factors noted throughout this
Quarterly Report and in our 2010 Annual Report could cause our actual results to differ materially
from those contained in any forward-looking statement. These factors include, but are not limited
to:
| satisfaction of the conditions to the closing of the Superior Acquisition and the possibility that the Superior Acquisition will not close; | ||
| timing of the completion of the Superior Acquisition; | ||
| our ability to obtain additional financing to fund a portion of the Superior Acquisition and the final purchase price for the Superior Acquisition; | ||
| the overall demand for specialty hydrocarbon products, fuels and other refined products; | ||
| our ability to produce specialty products and fuels that meet our customers unique and precise specifications; | ||
| the impact of fluctuations and rapid increases or decreases in crude oil and crack spread prices, including the resulting impact on our liquidity; | ||
| the results of our hedging and other risk management activities; | ||
| our ability to comply with financial covenants contained in our debt instruments; | ||
| the availability of, and our ability to consummate, acquisition or combination opportunities and impact of any completed acquisitions; | ||
| labor relations; | ||
| our access to capital to fund expansions, acquisitions and our working capital needs and our ability to obtain debt or equity financing on satisfactory terms; | ||
| successful integration and future performance of acquired assets, businesses or third-party product supply and processing relationships; | ||
| environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves; | ||
| maintenance of our credit ratings and ability to receive open credit lines from our suppliers; | ||
| demand for various grades of crude oil and resulting changes in pricing conditions; |
3
Table of Contents
| fluctuations in refinery capacity; | ||
| the effects of competition; | ||
| continued creditworthiness of, and performance by, counterparties; | ||
| the impact of current and future laws, rulings and governmental regulations, including guidance related to the Dodd-Frank Wall Street Reform and Consumer Protection Act; | ||
| shortages or cost increases of power supplies, natural gas, materials or labor; | ||
| hurricane or other weather interference with business operations; | ||
| fluctuations in the debt and equity markets; | ||
| accidents or other unscheduled shutdowns; and | ||
| general economic, market or business conditions. |
Other factors described herein, or factors that are unknown or unpredictable, could also have
a material adverse effect on future results. Our forward looking statements are not guarantees of
future performance, and actual results and future performance may differ materially from those
suggested in any forward looking statement. Please also read Part I Item 3 Quantitative and
Qualitative Disclosures About Market Risk and Part II Item 1A Risk Factors of this Quarterly
Report.
All subsequent written and oral forward-looking statements attributable to us or to persons
acting on our behalf are expressly qualified in their entirety by the foregoing. We undertake no
obligation to publicly release the results of any revisions to any such forward-looking statements
that may be made to reflect events or circumstances after the date of this report or to reflect the
occurrence of unanticipated events.
References in this Quarterly Report to Calumet Specialty Products Partners, L.P., the
Company, we, our, us or like terms refer to Calumet Specialty Products Partners, L.P. and
its subsidiaries. References in this Quarterly Report to our general partner refer to Calumet GP,
LLC, the general partner of the Company.
4
Table of Contents
PART I
Item 1. Financial Statements
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS
June 30, 2011 | December 31, 2010 | |||||||
(Unaudited) | ||||||||
(In thousands, except unit data) | ||||||||
ASSETS |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 55 | $ | 37 | ||||
Accounts receivable: |
||||||||
Trade |
203,749 | 157,185 | ||||||
Other |
2,436 | 776 | ||||||
206,185 | 157,961 | |||||||
Inventories |
258,665 | 147,110 | ||||||
Prepaid expenses and other current assets |
3,656 | 1,909 | ||||||
Deposits |
14,829 | 2,094 | ||||||
Total current assets |
483,390 | 309,111 | ||||||
Property, plant and equipment, net |
607,422 | 612,433 | ||||||
Goodwill |
48,335 | 48,335 | ||||||
Other intangible assets, net |
26,170 | 29,666 | ||||||
Other noncurrent assets, net |
30,907 | 17,127 | ||||||
Total assets |
$ | 1,196,224 | $ | 1,016,672 | ||||
LIABILITIES AND PARTNERS CAPITAL |
||||||||
Current liabilities: |
||||||||
Accounts payable |
$ | 236,169 | $ | 146,730 | ||||
Accounts payable related party |
1,380 | 27,985 | ||||||
Accrued salaries, wages and benefits |
7,975 | 7,559 | ||||||
Taxes payable |
8,360 | 7,174 | ||||||
Other current liabilities |
7,146 | 16,605 | ||||||
Current portion of long-term debt |
942 | 4,844 | ||||||
Derivative liabilities |
137,885 | 32,814 | ||||||
Total current liabilities |
399,857 | 243,711 | ||||||
Pension and postretirement benefit obligations |
8,426 | 9,168 | ||||||
Other long-term liabilities |
1,069 | 1,083 | ||||||
Long-term debt, less current portion |
428,440 | 364,431 | ||||||
Total liabilities |
837,792 | 618,393 | ||||||
Commitments and contingencies (Note 4) |
||||||||
Partners capital: |
||||||||
Limited partners interest (39,779,778 units
and 35,279,778 units issued and outstanding
at June 30, 2011 and December 31, 2010,
respectively) |
462,458 | 407,773 | ||||||
General partners interest |
19,302 | 18,125 | ||||||
Accumulated other comprehensive loss |
(123,328 | ) | (27,619 | ) | ||||
Total partners capital |
358,432 | 398,279 | ||||||
Total liabilities and partners capital |
$ | 1,196,224 | $ | 1,016,672 | ||||
See accompanying notes to unaudited condensed consolidated financial statements.
5
Table of Contents
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
For the Three Months Ended | For the Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(In thousands, except per unit data) | ||||||||||||||||
Sales |
$ | 733,770 | $ | 514,652 | $ | 1,339,010 | $ | 999,269 | ||||||||
Cost of sales |
683,205 | 465,033 | 1,241,581 | 917,974 | ||||||||||||
Gross profit |
50,565 | 49,619 | 97,429 | 81,295 | ||||||||||||
Operating costs and expenses: |
||||||||||||||||
Selling, general and administrative |
10,467 | 8,321 | 20,995 | 15,491 | ||||||||||||
Transportation |
22,691 | 19,956 | 45,766 | 40,202 | ||||||||||||
Taxes other than income taxes |
1,203 | 1,098 | 2,563 | 2,123 | ||||||||||||
Insurance recoveries |
(7,910 | ) | | (8,698 | ) | | ||||||||||
Other |
703 | 480 | 1,238 | 808 | ||||||||||||
Operating income |
23,411 | 19,764 | 35,565 | 22,671 | ||||||||||||
Other income (expense): |
||||||||||||||||
Interest expense |
(10,544 | ) | (7,277 | ) | (18,025 | ) | (14,711 | ) | ||||||||
Debt extinguishment costs |
(15,130 | ) | | (15,130 | ) | | ||||||||||
Realized loss on derivative instruments |
(2,370 | ) | (5,297 | ) | (1,984 | ) | (5,858 | ) | ||||||||
Unrealized loss on derivative instruments |
(3,124 | ) | (8,008 | ) | (3,541 | ) | (15,766 | ) | ||||||||
Other |
274 | 9 | 103 | (50 | ) | |||||||||||
Total other expense |
(30,894 | ) | (20,573 | ) | (38,577 | ) | (36,385 | ) | ||||||||
Net loss before income taxes |
(7,483 | ) | (809 | ) | (3,012 | ) | (13,714 | ) | ||||||||
Income tax expense |
168 | 98 | 438 | 260 | ||||||||||||
Net loss |
$ | (7,651 | ) | $ | (907 | ) | $ | (3,450 | ) | $ | (13,974 | ) | ||||
Allocation of net loss: |
||||||||||||||||
Net loss |
$ | (7,651 | ) | $ | (907 | ) | $ | (3,450 | ) | $ | (13,974 | ) | ||||
Less: |
||||||||||||||||
General partners interest in net loss |
(153 | ) | (18 | ) | (69 | ) | (279 | ) | ||||||||
Holders of incentive distribution rights |
| | | | ||||||||||||
Net loss attributable to limited partners |
$ | (7,498 | ) | $ | (889 | ) | $ | (3,381 | ) | $ | (13,695 | ) | ||||
Weighted average limited partner units outstanding basic
and diluted |
39,886 | 35,359 | 38,373 | 35,355 | ||||||||||||
Limited partners interest basic and diluted net loss per unit |
$ | (0.19 | ) | $ | (0.03 | ) | $ | (0.09 | ) | $ | (0.39 | ) | ||||
Cash distributions declared per limited partner unit |
$ | 0.495 | $ | 0.455 | $ | 0.97 | $ | 0.91 | ||||||||
See accompanying notes to unaudited condensed consolidated financial statements.
6
Table of Contents
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS CAPITAL
Accumulated Other | Partners Capital | |||||||||||||||||||
Comprehensive | General | Limited Partners | ||||||||||||||||||
Loss | Partner | Common | Subordinated | Total | ||||||||||||||||
(In thousands) | ||||||||||||||||||||
Balance at December 31, 2010 |
$ | (27,619 | ) | $ | 18,125 | $ | 390,843 | $ | 16,930 | $ | 398,279 | |||||||||
Distributions to partners |
| (724 | ) | (29,393 | ) | (6,141 | ) | (36,258 | ) | |||||||||||
Subordinated unit conversion |
| | 10,789 | (10,789 | ) | | ||||||||||||||
Comprehensive loss: |
||||||||||||||||||||
Net loss |
| (69 | ) | (3,381 | ) | | (3,450 | ) | ||||||||||||
Cash flow hedge loss reclassified to net loss |
46,944 | | | | 46,944 | |||||||||||||||
Change in fair value of cash flow hedges |
(142,775 | ) | | | | (142,775 | ) | |||||||||||||
Defined benefit pension and retiree health benefit plans |
122 | | | | 122 | |||||||||||||||
Comprehensive loss |
(99,159 | ) | ||||||||||||||||||
Proceeds from public equity offering, net |
| | 92,290 | | 92,290 | |||||||||||||||
Contribution from Calumet GP, LLC |
| 1,970 | | | 1,970 | |||||||||||||||
Units repurchased for phantom unit grants |
| | (620 | ) | | (620 | ) | |||||||||||||
Issuance of phantom units |
| | 648 | | 648 | |||||||||||||||
Amortization of vested phantom units |
| | 1,282 | | 1,282 | |||||||||||||||
Balance at June 30, 2011 |
$ | (123,328 | ) | $ | 19,302 | $ | 462,458 | $ | | $ | 358,432 | |||||||||
See accompanying notes to unaudited condensed consolidated financial statements.
7
Table of Contents
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended | ||||||||
June 30, | ||||||||
2011 | 2010 | |||||||
(In thousands) | ||||||||
Operating activities |
||||||||
Net loss |
$ | (3,450 | ) | $ | (13,974 | ) | ||
Adjustments to reconcile net loss to net cash provided by (used in) operating activities: |
||||||||
Depreciation and amortization |
28,964 | 29,502 | ||||||
Amortization of turnaround costs |
5,746 | 4,100 | ||||||
Non-cash interest expense |
1,655 | 1,906 | ||||||
Non-cash debt extinguishment costs |
14,401 | | ||||||
Provision for doubtful accounts |
255 | (91 | ) | |||||
Unrealized loss on derivative instruments |
3,541 | 15,766 | ||||||
Other non-cash activities |
338 | 1,114 | ||||||
Changes in assets and liabilities: |
||||||||
Accounts receivable |
(48,479 | ) | (27,323 | ) | ||||
Inventories |
(111,555 | ) | (9,583 | ) | ||||
Prepaid expenses and other current assets |
(1,747 | ) | (1,324 | ) | ||||
Derivative activity |
5,699 | 1,443 | ||||||
Turnaround costs |
(7,501 | ) | (8,548 | ) | ||||
Deposits |
(12,735 | ) | 3,589 | |||||
Accounts payable |
62,834 | 48,584 | ||||||
Accrued salaries, wages and benefits |
383 | (603 | ) | |||||
Taxes payable |
1,186 | 166 | ||||||
Other liabilities |
(9,473 | ) | (2,143 | ) | ||||
Pension and postretirement benefit obligations |
(620 | ) | (14 | ) | ||||
Net cash provided by (used in) operating activities |
(70,558 | ) | 42,567 | |||||
Investing activities |
||||||||
Additions to property, plant and equipment |
(20,635 | ) | (17,017 | ) | ||||
Proceeds from insurance recoveries equipment |
1,942 | | ||||||
Proceeds from sale of equipment |
130 | 121 | ||||||
Net cash used in investing activities |
(18,563 | ) | (16,896 | ) | ||||
Financing activities |
||||||||
Proceeds from borrowings revolving credit facility |
692,543 | 489,489 | ||||||
Repayments of borrowings revolving credit facility |
(675,285 | ) | (480,249 | ) | ||||
Repayments of borrowings term loan credit facility |
(367,385 | ) | (1,925 | ) | ||||
Payments on capital lease obligations |
(534 | ) | (743 | ) | ||||
Proceeds from equity offering, net |
92,290 | 793 | ||||||
Proceeds from senior notes offering |
400,000 | | ||||||
Debt issuance costs |
(17,582 | ) | | |||||
Contribution from Calumet GP, LLC |
1,970 | 18 | ||||||
Common units repurchased for vested phantom unit grants |
(620 | ) | (248 | ) | ||||
Distributions to partners |
(36,258 | ) | (32,788 | ) | ||||
Net cash provided by (used in) financing activities |
89,139 | (25,653 | ) | |||||
Net increase in cash and cash equivalents |
18 | 18 | ||||||
Cash and cash equivalents at beginning of period |
37 | 49 | ||||||
Cash and cash equivalents at end of period |
$ | 55 | $ | 67 | ||||
Supplemental disclosure of cash flow information |
||||||||
Interest paid |
$ | 11,830 | $ | 13,074 | ||||
Income taxes paid |
$ | 116 | $ | 89 | ||||
See accompanying notes to unaudited condensed consolidated financial statements.
8
Table of Contents
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands)
1. Description of the Business
Calumet Specialty Products Partners, L.P. (the Company) is a Delaware limited partnership.
The general partner of the Company is Calumet GP, LLC, a Delaware limited liability company. As of
June 30, 2011, the Company had 39,779,778 common units and 811,832 general partner units
outstanding. The number of common units outstanding includes 13,066,000 common units that converted
from subordinated units on February 16, 2011. There are no longer any subordinated units
outstanding. Refer to Note 9 for additional information. The general partner owns 2% of the Company
while the remaining 98% is owned by limited partners. The Company is engaged in the production and
marketing of crude oil-based specialty lubricating oils, white mineral oils, solvents, petrolatums,
waxes and fuels. The Company owns facilities located in Shreveport, Louisiana (Shreveport);
Princeton, Louisiana (Princeton); Cotton Valley, Louisiana (Cotton Valley); Karns City,
Pennsylvania (Karns City) and Dickinson, Texas (Dickinson) and a terminal located in Burnham,
Illinois (Burnham).
The unaudited condensed consolidated financial statements of the Company as of June 30, 2011
and for the three and six months ended June 30, 2011 and 2010 included herein have been prepared,
without audit, pursuant to the rules and regulations of the SEC. Certain information and
disclosures normally included in the consolidated financial statements prepared in accordance with
generally accepted accounting principles (GAAP) in the United States of America (the U.S.) have
been condensed or omitted pursuant to such rules and regulations, although the Company believes
that the following disclosures are adequate to make the information presented not misleading. These
unaudited condensed consolidated financial statements reflect all adjustments that, in the opinion
of management, are necessary to present fairly the results of operations for the interim periods
presented. All adjustments are of a normal nature, unless otherwise disclosed. The results of
operations for the three and six months ended June 30, 2011 are not necessarily indicative of the
results that may be expected for the year ending December 31, 2011. These unaudited condensed
consolidated financial statements should be read in conjunction with the Companys 2010 Annual
Report. The Company issued these unaudited condensed consolidated financial statements by filing
them with the SEC and has evaluated subsequent events up to the time of filing. Refer to Note 15
for additional information on these subsequent events.
2. New Accounting Pronouncements
In January 2010, the FASB issued ASU No. 2010-06, Improving Disclosures About Fair Value
Measurements ( ASU 2010-06), which amends ASC No. 820, Fair Value Measurements and Disclosures
to add new requirements for disclosures about transfers into and out of Levels 1 and 2 and separate
disclosures about purchases, sales, issuances and settlements relating to Level 3 measurements. ASU
2010-06 also clarifies existing fair value disclosures about the level of disaggregation and about
inputs and valuation techniques used to measure fair value. ASU 2010-06 is effective for the first
reporting period (including interim periods) beginning after December 15, 2009, except for the
requirement to provide the Level 3 activity of purchases, sales, issuances and settlements on a
gross basis, which is effective for fiscal years (including interim periods) beginning after
December 15, 2010. Effective January 1, 2010, the Company adopted ASU 2010-06 standard relating to
disclosures about transfers in and out of Level 1 and 2 and the inputs and valuation techniques
used to measure fair value. Effective January 1, 2011, the Company adopted ASU 2010-06 standard
relating to the requirement to provide the Level 3 activity of purchases, sales, issuances and
settlements on a gross basis. The adoption of ASU 2010-06 did not have a material impact on the
Companys financial position, results of operations or cash flows.
In May 2011, the FASB issued ASU No. 2011-04, Amendments to Achieve Common Fair Value
Measurements and Disclosure Requirements in U.S. GAAP and IFRS (ASU 2011-04). ASU 2011-04 is
intended to improve the comparability of fair value measurements presented and disclosed in
financial statements prepared in accordance with U.S. GAAP and IFRS. The amendments are of two
types: (i) those that clarify the Boards intent about the application of existing fair value
measurement and disclosure requirements and (ii) those that change a particular principle or
requirement for measuring fair value or for disclosing information about fair value measurements.
ASU 2011-04 is effective for the first reporting period (including interim periods) beginning after
December 15, 2011. The Company is in process of evaluating the impact of the adoption of ASU
2011-04 on the Companys financial statements.
9
Table of Contents
In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (ASC Topic 220):
Presentation of Comprehensive Income, (ASU 2011-05) which amends current comprehensive income
guidance. This accounting update eliminates the option to present the components of other
comprehensive income as part of the statement of partners capital. Instead, the Company must
report comprehensive income in either a single continuous statement of comprehensive income which
contains two sections, net income and other comprehensive income, or in two separate but
consecutive statements. ASU 2011-05 will be effective for public companies during the interim and
annual periods beginning after December 15, 2011 with early adoption permitted. The adoption of
ASU 2011-05 will not have an impact on the Companys consolidated financial position, results of
operations or cash flows as it only requires a change in the format of the current
presentation.
3. Inventories
The cost of inventories is determined using the last-in, first-out (LIFO) method. Costs
include crude oil and other feedstocks, labor, processing costs and refining overhead costs.
Inventories are valued at the lower of cost or market value.
Inventories consist of the following:
June 30, | December 31, | |||||||
2011 | 2010 | |||||||
Raw materials |
$ | 82,301 | $ | 12,885 | ||||
Work in process |
59,807 | 49,006 | ||||||
Finished goods |
116,557 | 85,219 | ||||||
$ | 258,665 | $ | 147,110 | |||||
The replacement cost of these inventories, based on current market values, would have been
$85,775 and $55,855 higher as of June 30, 2011 and December 31, 2010, respectively. For the three
and six months ended June 30, 2011 and 2010, the Company recorded $0 and $883, respectively, of
gains in cost of sales in the unaudited condensed consolidated statements of operations due to the
liquidation of lower cost inventory layers.
4. Commitments and Contingencies
From time to time, the Company is a party to certain claims and litigation incidental to its
business, including claims made by various taxation and regulatory authorities, such as the LDEQ,
the U.S. Environmental Protection Agency (EPA), the Internal Revenue Service and the Occupational
Safety and Health Administration (OSHA), as the result of audits or reviews of the Companys
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.
Insurance Recoveries
During the second quarter, the Company reached a final settlement of its insurance claim
related to the failure of an environmental operating unit at its Shreveport refinery in 2010,
resulting in a gain of $7,910 recorded in the second quarter of 2011. This claim related to both
property damage and business interruption. Recoveries of $1,942 related to property damage have
been reflected within investing activities (with the remainder in operating activities) in the unaudited condensed consolidated statement of
cash flows.
Environmental
The Company operates crude oil and specialty hydrocarbon refining and terminal operations,
which are subject to stringent and complex federal, state, and local laws and regulations governing
the discharge of materials into the environment or otherwise relating to environmental protection.
These laws and regulations can impair the Companys operations that affect the environment in many
ways, such as requiring the acquisition of permits to conduct regulated activities, restricting the
manner in which the Company can release materials into the environment, requiring remedial
activities or capital expenditures to mitigate pollution from former or current operations, and
imposing substantial liabilities for pollution resulting from its operations. Certain environmental
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.
Failure to comply with environmental laws and regulations may result in the triggering of
administrative, civil and criminal measures, including the assessment of monetary penalties, the
imposition of remedial obligations and the issuance of injunctions
10
Table of Contents
limiting or prohibiting some or all of the Companys operations. On occasion, the Company
receives notices of violation, enforcement and other complaints from regulatory agencies alleging
non-compliance with applicable environmental laws and regulations. For example, the LDEQ initiated
enforcement actions in prior years for the following alleged violations: (i) a May 2001
notification received by the Cotton Valley refinery from the LDEQ regarding several alleged
violations of various air emission regulations, as identified in the course of the Companys Leak
Detection and Repair program, and also for failure to submit various reports related to the
facilitys air emissions; (ii) a December 2002 notification received by the Companys Cotton Valley
refinery from the LDEQ regarding alleged violations for excess emissions, as identified in the
LDEQs file review of the Cotton Valley refinery; (iii) a December 2004 notification received by
the Cotton Valley refinery from the LDEQ regarding alleged violations for the construction of a
multi-tower pad and associated pump pads without a permit issued by the agency; and (iv) an August
2005 notification received by the Princeton refinery from the LDEQ regarding alleged violations of
air emissions regulations, as identified by the LDEQ following performance of a compliance review,
due to excess emissions and failures to continuously monitor and record air emissions levels. On
December 23, 2010, the Company entered into a settlement agreement with the LDEQ that consolidated
the terms of its settlement of the aforementioned violations with the Companys agreement to
voluntarily participate in the LDEQs Small Refinery and Single Site Refinery Initiative
described below.
In 2010, the Company entered into a settlement agreement with the LDEQ regarding the Companys
voluntary participation in the LDEQs Small Refinery and Single Site Refinery Initiative. This
state initiative is patterned after the EPAs National Petroleum Refinery Initiative, which is a
coordinated, integrated compliance and enforcement strategy to address federal Clean Air Act
compliance issues at the nations largest petroleum refineries. The agreement, voluntarily entered
into by the Company, requires the Company to make a $1,000 payment to the LDEQ and complete
beneficial environmental programs and implement emissions reduction projects at the Companys
Shreveport, Cotton Valley and Princeton refineries. The Company estimates implementation of these
requirements will result in approximately $11,000 to $15,000 of capital expenditures, expenditures
related to additional personnel and environmental studies over the next five years. This agreement
also fully settles the aforementioned alleged environmental and permit violations at the Companys
Shreveport, Cotton Valley and Princeton refineries and stipulates that no further civil penalties
over alleged past violations at those refineries will be pursued by the LDEQ. The required
investments are expected to include projects resulting in (i) nitrogen oxide and sulfur dioxide
emission reductions from heaters and boilers and the application of New Source Performance
Standards for sulfur recovery plants and flaring devices, (ii) control of incidents related to acid
gas flaring, tail gas and hydrocarbon flaring, (iii) electrical reliability improvements to reduce
flaring, (iv) flare refurbishment at the Shreveport refinery, (v) enhancement of the Benzene Waste
National Emissions Standards for Hazardous Air Pollutants programs and the Leak Detection and
Repair programs at the Companys three Louisiana refineries and (vi) Title V audits and targeted
audits of certain regulatory compliance programs. During negotiations with the LDEQ, the Company
voluntarily initiated projects for certain of these requirements prior to the settlement with the
LDEQ, and currently anticipates completion of these projects over the next five years. These
capital investment requirements will be incorporated into the Companys 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 settlement to have a material
adverse effect on the Companys financial results or
operations. Before the terms of this
settlement agreement are deemed final, they will require the concurrence of the Louisiana Attorney
General, which concurrence is anticipated to be granted during 2011.
Voluntary remediation of subsurface contamination is in process at each of the Companys
refinery sites. The remedial projects are being overseen by the appropriate state agencies. Based
on current investigative and remedial activities, the Company believes that the groundwater
contamination at these refineries can be controlled or remedied without having a material adverse
effect on the Companys financial condition. However, such costs are often unpredictable and,
therefore, there can be no assurance that the future costs will not become material. The Company
incurred approximately $261 of such capital expenditures at its Cotton Valley refinery during the
first six months of 2011 and estimates that it will incur another $489 of capital expenditures at
its Cotton Valley refinery during the remainder of 2011 in connection with these activities. The
Company incurred approximately $541 of such capital expenditures at its Cotton Valley refinery
during 2010.
The Company is indemnified by Shell Oil Company, as successor to Pennzoil-Quaker State Company
and Atlas Processing Company, for specified environmental liabilities arising from the operations
of the Shreveport refinery prior to the Companys acquisition of the facility. The indemnity is
unlimited in amount and duration, but requires the Company to contribute up to $1,000 of the first
$5,000 of indemnified costs for certain of the specified environmental liabilities.
11
Table of Contents
Health, Safety and Maintenance
The Company is subject to various laws and regulations relating to occupational health and
safety, including OSHA and comparable state laws. These laws and the implementing regulations
strictly govern the protection of the health and safety of employees. In addition, OSHAs hazard
communication standard requires that information be maintained about hazardous materials used or
produced in the Companys operations and that this information be provided to employees,
contractors, state and local government authorities and customers. The Company maintains safety,
training and maintenance programs as part of its ongoing efforts to ensure compliance with
applicable laws and regulations. The Companys compliance with applicable health and safety laws
and regulations has required, and continues to require, substantial expenditures. The Company has
implemented an internal program of inspection designed to monitor and enforce compliance with
worker safety requirements as well as a quality system that meets the requirements of the
ISO-9001-2008 Standard. The integrity of the Companys ISO-9001-2008 Standard certification is
maintained through surveillance audits by its registrar at regular intervals designed to ensure
adherence to the standards.
The Company has completed studies to assess the adequacy of its process safety management
practices at its Shreveport refinery with respect to certain consensus codes and standards. The
Company expects to incur between $5,000 and $8,000 of capital expenditures in total during 2011,
2012 and 2013 to address OSHA compliance issues identified in these studies. The Company expects
these capital expenditures will enhance its equipment such that the equipment maintains compliance
with applicable consensus codes and standards. The Company believes that its operations are in
substantial compliance with OSHA and similar state laws.
Beginning in February 2010, OSHA conducted an inspection of the Shreveport refinerys process
safety management program under OSHAs National Emphasis Program, which is targeting all U.S.
refineries for review. On August 19, 2010, OSHA issued a Citation and Notification of Penalty (the
Shreveport Citation) to the Company as a result of the
Shreveport inspection, which included a
proposed civil penalty amount of $173. The Company contested the Shreveport Citation and associated
penalty amount and agreed to a final penalty amount of $119 that was paid in January 2011.
Similarly, OSHA conducted an inspection of the Cotton Valley refinerys process safety management
program under OSHAs National Emphasis Program in the first quarter of 2011. On March 14, 2011,
OSHA issued a Citation and Notification of Penalty (the Cotton Valley Citation) to the Company as
a result of the Cotton Valley inspection, which included a proposed penalty amount of $208. The
Company has contested the Cotton Valley Citation and associated penalties and is currently in
negotiations with OSHA to reach a settlement allowing an extended abatement period for a new
refinery flare system study and for completion of facility siting modifications, including
relocation and hardening of structures.
Standby Letters of Credit
The Company has agreements with various financial institutions for standby letters of credit
which have been issued to domestic vendors. As of June 30, 2011 and December 31, 2010, the Company
had outstanding standby letters of credit of $179,473 and $90,725, respectively, under its senior
secured revolving credit facility (the revolving credit facility), which was amended and restated
on June 24, 2011. Refer to Note 5 for additional information. The maximum amount of letters of
credit the Company can issue at June 30, 2011 is limited to its borrowing capacity under its
revolving credit facility or $550,000, whichever is lower. At December 31, 2010, the limitation was
the lower of the Companys borrowing capacity or $375,000. As of June 30, 2011 and December 31,
2010, the Company had availability to issue letters of credit of $194,668 and $145,454,
respectively, under its revolving credit facility. As discussed in Note 5, as of June 30, 2011 the
outstanding standby letters of credit issued under the revolving credit facility included a $25,000
letter of credit to support a portion of its fuel products hedging program.
12
Table of Contents
5. Long-Term Debt
Long-term debt consisted of the following:
June 30, | December 31, | |||||||
2011 | 2010 | |||||||
Borrowings under senior secured first lien term loan with third-party lenders, extinguished in 2011 |
$ | | $ | 367,385 | ||||
Borrowings
under senior secured revolving credit agreement with third-party lenders, amended and
restated in June 2011 |
| 10,832 | ||||||
Borrowings under amended and restated senior secured revolving credit agreement with third-party
lenders, interest at prime plus 1.25% (4.50% at June 30, 2011), interest payments monthly, borrowings
due June 2016 |
28,090 | | ||||||
Borrowings under 2019 Notes, interest at a fixed rate of 9.375% at June 30, 2011, interest
payments semiannually, borrowings due May 2019, effective interest rate of 9.95% for the quarter ended
June 30, 2011 |
400,000 | | ||||||
Capital lease obligations, at various interest rates, interest and principal payments quarterly
through November 2013 |
1,292 | 1,781 | ||||||
Less unamortized discount on senior secured first lien term loan with third-party lenders, extinguished
in 2011 |
| (10,723 | ) | |||||
Total long-term debt |
429,382 | 369,275 | ||||||
Less current portion of long-term debt |
942 | 4,844 | ||||||
$ | 428,440 | $ | 364,431 | |||||
During the quarter ended June 30, 2011, the Company restructured the majority of its
outstanding long-term debt. The Company issued $400,000 in aggregate principal amount 9 3/8% senior notes due
May 1, 2019 (the 2019 Notes), amended its then current senior
secured revolving credit agreement to allow for the issuance of the 2019 Notes, and used the majority
of the proceeds from the 2019 Notes to repay borrowings under, and subsequently extinguish, the
senior secured first lien term loan. The Company also amended certain of its master derivative
contracts and entered into a collateral sharing agreement with its hedging counterparties. Further,
the Company amended and restated its revolving credit agreement to increase the credit facility
from $375,000 to $550,000, as well as amend covenants and contractual terms. Each of these
activities is discussed in further detail in the following paragraphs.
9 3/8% Senior Notes
On April 21, 2011, the Company issued and sold the 2019 Notes in a private placement pursuant
to Rule 144A under the Securities Act to eligible purchasers. The 2019 Notes were resold to
qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons
outside the United States pursuant to Regulation S under the Securities Act. The Company received
proceeds of $389,038 net of underwriters fees and expenses, which the Company used to repay in
full borrowings outstanding under its existing senior secured first lien term loan, as well as all
accrued interest and fees, and for general partnership purposes. Interest on the 2019 Notes will be
paid semiannually in arrears on May 1 and November 1 of each year, beginning on November 1, 2011.
The 2019 Notes will mature on May 1, 2019, unless redeemed prior to maturity. The 2019 Notes are
guaranteed on a senior unsecured basis by all of the Companys operating subsidiaries and the
Companys future operating subsidiaries.
At any time prior to May 1, 2014, the Company may on any one or more occasions redeem up to
35% of the aggregate principal amount of the 2019 Notes with the net proceeds of a public or
private equity offering at a redemption price of 109.375% of the principal amount, plus any accrued
and unpaid interest to the date of redemption, provided that: (1) at least 65% of the aggregate
principal amount of 2019 Notes issued remains outstanding immediately after the occurrence of such
redemption and (2) the redemption occurs within 120 days of the date of the closing of such public
or private equity offering.
On and after May 1, 2015, the Company may on any one or more occasions redeem all or a part of
the 2019 Notes at the redemption prices (expressed as percentages of principal amount) set forth
below, plus any accrued and unpaid interest to the applicable redemption date on such 2019 Notes,
if redeemed during the twelve-month period beginning on May 1 of the years indicated below:
13
Table of Contents
Year | Percentage | |||
2015 |
104.688 | % | ||
2016 |
102.344 | % | ||
2017 and at any time thereafter |
100.000 | % |
Prior to May 1, 2015, the Company may on any one or more occasions redeem all or part of the
2019 Notes at a redemption price equal to the sum of: (1) the principal amount thereof, plus (2) a
make-whole premium (as set forth in the indenture governing the 2019 Notes) at the redemption date,
plus any accrued and unpaid interest to the applicable redemption date.
The indenture governing the 2019 Notes contains covenants that, among other things, restrict
the Companys ability and the ability of certain of the Companys subsidiaries to: (i) sell assets;
(ii) pay distributions on, redeem or repurchase the Companys 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 Companys restricted subsidiaries to the Company; (vii)
consolidate, merge or transfer all or substantially all of the Companys assets; (viii) engage in
transactions with affiliates and (ix) create unrestricted subsidiaries. These covenants are subject
to important exceptions and qualifications. At any time when the 2019 Notes are rated investment
grade by either of Moodys Investors Service, Inc. or Standard & Poors Ratings Services and no
Default or Event of Default, each as defined in the indenture governing the 2019 Notes, has
occurred and is continuing, many of these covenants will be suspended.
Upon the occurrence of certain change of control events, each holder of the 2019 Notes will
have the right to require that the Company repurchase all or a portion of such holders 2019 Notes
in cash at a purchase price equal to 101% of the principal amount thereof, plus any accrued and
unpaid interest to the date of repurchase.
In connection with the notes offering on April 21, 2011, the Companys then current senior
secured revolving credit agreement was amended on April 15, 2011, to among other things, (i) permit
the issuance of the 2019 Notes; (ii) upon consummation of the issuance of the 2019 Notes and the
termination of the senior secured first lien credit agreement, release the revolving credit
facility lenders second priority lien on the collateral securing the senior secured first lien
credit facility; and (iii) change the interest rate pricing on the revolving credit facility.
Registration Rights Agreement
On April 21, 2011, in connection with the issuance and sale of the 2019 Notes, the Company
entered into a registration rights agreement (the Registration Rights Agreement) with the initial
purchasers of the 2019 Notes obligating the Company to use reasonable best efforts to file an
exchange registration statement with the SEC, so that holders of the 2019 Notes can offer to
exchange the 2019 Notes issued in the April 2011 offering for registered notes having substantially
the same terms as the 2019 Notes and evidencing the same indebtedness as the 2019 Notes. The
Company must use reasonable best efforts to cause the exchange offer registration statement to
become effective by April 20, 2012 and remain effective until 180 days after the closing of the
exchange. Additionally, the Company has agreed to commence the exchange offer promptly after the
exchange offer registration statement is declared effective by the SEC and use reasonable best
efforts to complete the exchange offer not later than 60 days after such effective date. Under
certain circumstances, in lieu of a registered exchange offer, the Company must use reasonable best
efforts to file a shelf registration statement for the resale of the 2019 Notes. If the Company
fails to satisfy these obligations on a timely basis, the annual interest borne by the 2019 Notes
will be increased by up to 1.0% per annum until the exchange offer is completed or the shelf
registration statement is declared effective.
Senior Secured First Lien Credit Agreement
The Companys $435,000 senior secured first lien credit facility (the term loan facility)
included a $385,000 term loan and a $50,000 prefunded letter of credit facility to support crack
spread hedging. The Company extinguished this facility on April 21, 2011 in connection with the
issuance and sale of the 2019 Notes, as further discussed above. The term loan bore interest at a
rate equal to (i) with respect to a LIBOR Loan, the LIBOR Rate (as defined in the senior secured
first lien credit agreement) plus 400 basis points and (ii) with respect to a Base Rate Loan, the
Base Rate (as defined in the senior secured first lien credit agreement) plus 300 basis points. At
December 31, 2010, the term loan bore interest at 4.29%. Please refer to Amendments to Master
Derivative Contracts below for information on termination of the $50,000 prefunded letter of
credit to support crack spread hedging.
14
Table of Contents
Lenders under the term loan facility generally had a first priority lien on the Companys
fixed assets and a second priority lien on its cash, accounts receivable, inventory and certain
other personal property. The term loan facility required quarterly principal payments of $963
through September 30, 2014, with the remaining balance due at maturity on January 3, 2015.
On April 21, 2011, the Company used approximately $369,486 of the net proceeds from the
issuance and sale of the 2019 Notes to repay in full its term loan, as well as accrued interest and fees, and terminated the entire senior
secured first lien credit facility, including the term loan and $50,000 prefunded letter of credit.
The Company did not incur any material early termination penalties in connection with its
termination of the senior secured first lien credit facility. Further, in the second quarter of
2011 the Company recorded approximately $15,130 of extinguishment charges related to the writeoff
of the unamortized debt issuance costs and the unamortized discount associated with the term loan.
Amendments to Master Derivative Contracts
In connection with the termination of the term loan facility and the amendment
of the senior secured revolving credit agreement, on April 21, 2011, the Company entered into
amendments to certain of the Companys master derivatives contracts (Amendments) to provide new
credit support arrangements to secure the Companys payment obligations under these contracts
following the termination of the term loan facility and the amendment and restatement of the senior
secured revolving credit agreement. Under the new credit support arrangements, the Companys
payment obligations under all of the Companys master derivatives contracts for commodity hedging
generally are secured by a first priority lien on the Companys real property, plant and equipment,
fixtures, intellectual property, certain financial assets, certain investment property, commercial
tort claims, chattel paper, documents, instruments and proceeds of the foregoing (including
proceeds of hedge arrangements). The Company also issued to one counterparty a $25,000 standby
letter of credit under the amended and restated senior secured revolving credit facility to replace
a prefunded $50,000 letter of credit previously issued under the senior secured first lien credit
facility. In the event that such counterpartys exposure to the Company exceeds $150,000, the
Company will be required to post additional collateral support in the form of either cash or
letters of credit with the counterparty to enter into additional crack spread hedges. In addition
to the $25,000 standby letter of credit posted to one counterparty, as of June 30, 2011 the Company
had cash collateral posted with another counterparty of $11,900. The Companys master derivatives
contracts continue to impose a number of covenant limitations on the Companys operating and
financing activities, including limitations on liens on collateral, limitations on dispositions of
collateral and collateral maintenance and insurance requirements.
In connection with the Amendments, on April 21, 2011, the Company entered into a collateral
sharing agreement among each of its secured hedging counterparties and an administrative agent for
the benefit of the secured hedging counterparties, which governs how the secured hedging
counterparties will share collateral pledged as security for the payment obligations owed by the
Company to the secured hedging counterparties under their respective master derivatives contracts.
Subject to certain conditions set forth in the collateral trust agreement, the Company has the
ability to add secured hedging counterparties thereto.
Amended and Restated Senior Secured Revolving Credit Agreement
On June 24, 2011, the Company entered into an amended and restated senior secured revolving
credit agreement which increased the maximum availability of credit from $375,000 to $550,000,
subject to borrowing base limitations, and includes a $300,000 incremental uncommitted expansion
feature. The revolving credit agreement, which is the Companys primary source of liquidity for
cash needs in excess of cash generated from operations, matures in June 2016 and currently bears
interest at a rate equal to prime plus a basis points margin or LIBOR plus a basis points margin,
at the Companys option. As of June 30, 2011, the margin was 125 basis points for prime and 250
basis points for LIBOR; however the margin fluctuates quarterly based on the Companys average
availability for additional borrowings under the revolving credit agreement in the preceding
calendar quarter as follows:
Quarterly Average | Margin on Base Rate | Margin on LIBOR | ||||||
Availability Percentage | Revolving Loans | Revolving Loans | ||||||
≥ 66% |
1.00 | % | 2.25 | % | ||||
≥ 33% and < 66% |
1.25 | % | 2.50 | % | ||||
< 33% |
1.50 | % | 2.75 | % |
The borrowing capacity at June 30, 2011 under the revolving credit facility was $402,231. As
of June 30, 2011, the Company borrowed $28,090, leaving $194,668 available for additional
borrowings based on collateral and specified availability limitations. The lenders under the
revolving credit agreement have a first priority lien on the Companys cash, accounts receivable,
inventory and certain other personal property.
In addition, the amended and restated senior secured revolving credit agreement contains
various covenants that limit, among other things, the Companys ability to: incur indebtedness;
grant liens; dispose of certain assets; make certain acquisitions and investments;
15
Table of Contents
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 amended and restated senior secured revolving credit agreement
contains one springing financial covenant which provides that only if the Companys availability
under the amended and restated senior secured revolving credit agreement falls below the greater of
(i) 12.5% of the lesser of (a) the Borrowing Base (as defined in the credit agreement) (without
giving effect to the LC Reserve (as defined in the credit agreement)) and (b) the credit agreement
commitments then in effect and (ii) $30,000, 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 Credit Agreement)
of at least 1.0 to 1.0.
As of June 30, 2011, maturities of the Companys long-term debt are as follows:
Year | Maturity | |||
2011 |
$ | 505 | ||
2012 |
551 | |||
2013 |
236 | |||
2014 |
| |||
2015 |
| |||
Thereafter |
428,090 | |||
Total |
$ | 429,382 | ||
6. Derivatives
The Company utilizes derivative instruments to minimize its price risk and volatility of cash
flows associated with the purchase of crude oil and natural gas, the sale of fuel products and
interest payments. The Company employs various hedging strategies, which are further discussed
below. The Company does not hold or issue derivative instruments for trading purposes.
The Company recognizes all derivative instruments at their fair values (see Note 8) as either
assets or liabilities on the condensed consolidated balance sheets. Fair value includes any
premiums paid or received and unrealized gains and losses. Fair value does not include any amounts
receivable from or payable to counterparties, or collateral provided to counterparties. Derivative
asset and liability amounts with the same counterparty are netted against each other for financial
reporting purposes. The Company recorded the following derivative assets and liabilities at their
fair values as of June 30, 2011 and December 31, 2010:
Derivative Assets | Derivative Liabilities | |||||||||||||||
June 30, 2011 | December 31, 2010 | June 30, 2011 | December 31, 2010 | |||||||||||||
Derivative instruments designated as hedges: |
||||||||||||||||
Fuel products segment: |
||||||||||||||||
Crude oil swaps |
$ | | $ | | $ | 126,090 | $ | 134,916 | ||||||||
Gasoline swaps |
| | (12,815 | ) | (14,149 | ) | ||||||||||
Diesel swaps |
| | (75,698 | ) | (53,744 | ) | ||||||||||
Jet fuel swaps |
| | (173,134 | ) | (96,556 | ) | ||||||||||
Interest rate swaps: |
| | | (2,681 | ) | |||||||||||
Total derivative instruments designated as hedges |
| | (135,557 | ) | (32,214 | ) | ||||||||||
Derivative instruments not designated as hedges: |
||||||||||||||||
Fuel products segment: |
||||||||||||||||
Jet fuel crack spread collars (1) |
| | | 20 | ||||||||||||
Specialty products segment: (2) |
||||||||||||||||
Crude oil collars |
| | | | ||||||||||||
Natural gas swaps |
| | | | ||||||||||||
Crude oil swaps |
| | | 662 | ||||||||||||
Interest rate swaps: (3) |
| | (2,328 | ) | (1,282 | ) | ||||||||||
Total derivative instruments not designated as hedges |
| | (2,328 | ) | (600 | ) | ||||||||||
Total derivative instruments |
$ | | $ | | $ | (137,885 | ) | $ | (32,814 | ) | ||||||
(1) | The Company entered into jet fuel crack spread collars, which do not qualify for hedge accounting, to economically hedge its exposure to changes in the jet fuel crack spread. | |
(2) | The Company enters into combinations of crude oil options and swaps and natural gas swaps to economically hedge its exposures to price risk related to these commodities in its specialty products segment. The Company has not designated these derivative instruments as hedges. |
16
Table of Contents
(3) | The Company refinanced its long-term debt in April 2011 and, as a result, all of its interest rate swaps that were designated as a cash flow hedge for the interest payments under the previous debt agreement are no longer designated as hedges. |
To the extent a derivative instrument 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 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. The Company accounts for certain
derivatives hedging purchases of crude oil and natural gas, sales of gasoline, diesel and jet fuel
and the payment of interest as cash flow hedges. The derivatives hedging sales and purchases are
recorded to sales and cost of sales, respectively, in the unaudited condensed consolidated
statements of operations upon recording the related hedged transaction in sales or cost of sales.
The derivatives designated as hedging payments of interest are recorded in interest expense in the
unaudited condensed consolidated statements of operations upon payment of interest. The Company
assesses, both at inception of the hedge and on an ongoing basis, whether the derivatives that are
used in hedging transactions are highly effective in offsetting changes in cash flows of hedged
items.
For derivative instruments not designated as cash flow hedges and the portion of any cash flow
hedge that is determined to be ineffective, the change in fair value of the asset or liability for
the period is recorded to unrealized gain (loss) on derivative instruments in the unaudited
condensed consolidated statements of operations. Upon the settlement of a derivative not designated
as a cash flow hedge, the gain or loss at settlement is recorded to realized gain (loss) on
derivative instruments in the unaudited condensed consolidated statements of operations.
17
Table of Contents
The Company recorded the following amounts in its condensed consolidated balance sheets,
unaudited condensed consolidated statements of operations and its unaudited condensed consolidated
statements of partners capital as of, and for the three months ended, June 30, 2011 and 2010
related to its derivative instruments that were designated as cash flow hedges:
Amount of (Gain) | ||||||||||||||||||||||||||||||||
Amount of Gain (Loss) | Loss Reclassified | |||||||||||||||||||||||||||||||
Recognized in | from Accumulated | |||||||||||||||||||||||||||||||
Accumulated Other | Other Comprehensive | Amount of Gain (Loss) | ||||||||||||||||||||||||||||||
Comprehensive Loss | Loss into | Recognized in Net | ||||||||||||||||||||||||||||||
on Derivatives | Net Loss | Loss on Derivatives | ||||||||||||||||||||||||||||||
(Effective Portion) | (Effective Portion) | (Ineffective Portion) | ||||||||||||||||||||||||||||||
Three Months Ended | Location of | Three Months Ended | Three Months Ended | |||||||||||||||||||||||||||||
June 30, | (Gain) | June 30, | Location of Gain | June 30, | ||||||||||||||||||||||||||||
Type of Derivative | 2011 | 2010 | Loss | 2011 | 2010 | (Loss) | 2011 | 2010 | ||||||||||||||||||||||||
Fuel products segment: |
||||||||||||||||||||||||||||||||
Crude oil swaps |
$ | (75,758 | ) | $ | (95,836 | ) | Cost of sales | $ | (39,333 | ) | $ | (18,178 | ) | Unrealized/ Realized | $ | (1,716 | ) | $ | (3,500 | ) | ||||||||||||
Gasoline swaps |
1,374 | 25,491 | Sales | 12,576 | 5,874 | Unrealized/ Realized | (878 | ) | (3,016 | ) | ||||||||||||||||||||||
Diesel swaps |
27,530 | 41,122 | Sales | 25,074 | 10,002 | Unrealized/ Realized | 19 | (43 | ) | |||||||||||||||||||||||
Jet fuel swaps |
31,169 | 24,847 | Sales | 29,113 | | Unrealized/ Realized | (1,128 | ) | 166 | |||||||||||||||||||||||
Specialty products segment: |
||||||||||||||||||||||||||||||||
Crude oil collars |
| | Cost of sales | | | Unrealized/ Realized | | | ||||||||||||||||||||||||
Crude oil swaps |
| | Cost of sales | | | Unrealized/ Realized | | | ||||||||||||||||||||||||
Natural gas swaps |
| | Cost of sales | | | Unrealized/ Realized | | | ||||||||||||||||||||||||
Interest rate swaps: |
1,634 | (449 | ) | Interest expense | | 511 | Unrealized/ Realized | | | |||||||||||||||||||||||
Total |
$ | (14,051 | ) | $ | (4,825 | ) | $ | 27,430 | $ | (1,791 | ) | $ | (3,703 | ) | $ | (6,393 | ) | |||||||||||||||
The Company recorded the following gains (losses) in its unaudited condensed consolidated
statements of operations and its unaudited condensed consolidated statements of partners capital for the three months
ended June 30, 2011 and 2010 related to its derivative instruments not designated as cash flow
hedges:
Amount of Gain (Loss) | Amount of Gain (Loss) | |||||||||||||||
Recognized in | Recognized | |||||||||||||||
Realized Loss on | in Unrealized Loss on | |||||||||||||||
Derivatives | Derivatives | |||||||||||||||
Three Months Ended | Three Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
Type of Derivative | 2011 | 2010 | 2011 | 2010 | ||||||||||||
Fuel products segment: |
||||||||||||||||
Crude oil swaps |
$ | | $ | (2,155 | ) | $ | | $ | 5,366 | |||||||
Gasoline swaps |
| 3,709 | | (7,161 | ) | |||||||||||
Diesel swaps |
| (325 | ) | | 325 | |||||||||||
Jet fuel swaps |
| | | | ||||||||||||
Jet fuel collars |
| | | (162 | ) | |||||||||||
Specialty products segment: |
||||||||||||||||
Crude oil collars |
| (2,188 | ) | | (2,245 | ) | ||||||||||
Crude oil swaps |
| (1,686 | ) | | (298 | ) | ||||||||||
Natural gas swaps |
| | | (76 | ) | |||||||||||
Interest rate swaps: |
(553 | ) | (205 | ) | (1,238 | ) | 189 | |||||||||
Total |
$ | (553 | ) | $ | (2,850 | ) | $ | (1,238 | ) | $ | (4,062 | ) | ||||
18
Table of Contents
The Company recorded the following amounts in its condensed consolidated balance sheets, unaudited
condensed consolidated statements of operations and its unaudited condensed consolidated statements
of partners capital as of, and for the six months ended, June 30, 2011 and 2010 related to its
derivative instruments that were designated as cash flow hedges:
Amount of (Gain) | ||||||||||||||||||||||||||||||||
Amount of Gain (Loss) | Loss Reclassified | |||||||||||||||||||||||||||||||
Recognized in | from Accumulated | |||||||||||||||||||||||||||||||
Accumulated Other | Other Comprehensive | Amount of Gain (Loss) | ||||||||||||||||||||||||||||||
Comprehensive Loss | Loss into | Recognized in Net | ||||||||||||||||||||||||||||||
on Derivatives | Net Loss | Loss on Derivatives | ||||||||||||||||||||||||||||||
(Effective Portion) | (Effective Portion) | (Ineffective Portion) | ||||||||||||||||||||||||||||||
Six Months Ended | Location of | Six Months Ended | Six Months Ended | |||||||||||||||||||||||||||||
June 30, | (Gain) | June 30, | Location of Gain | June 30, | ||||||||||||||||||||||||||||
Type of Derivative | 2011 | 2010 | Loss | 2011 | 2010 | (Loss) | 2011 | 2010 | ||||||||||||||||||||||||
Fuel products segment: |
||||||||||||||||||||||||||||||||
Crude oil swaps |
$ | 61,188 | $ | (79,355 | ) | Cost of sales | $ | (58,434 | ) | $ | (35,686 | ) | Unrealized/ Realized | $ | (497 | ) | $ | (9,973 | ) | |||||||||||||
Gasoline swaps |
(17,736 | ) | 19,650 | Sales | 18,815 | 11,058 | Unrealized/ Realized | (1,339 | ) | (4,551 | ) | |||||||||||||||||||||
Diesel swaps |
(68,792 | ) | 32,556 | Sales | 43,187 | 15,810 | Unrealized/ Realized | (538 | ) | (1,224 | ) | |||||||||||||||||||||
Jet fuel swaps |
(119,414 | ) | 17,623 | Sales | 42,674 | | Unrealized/ Realized | (1,604 | ) | 166 | ||||||||||||||||||||||
Specialty products
segment: |
||||||||||||||||||||||||||||||||
Crude oil collars |
| | Cost of sales | | | Unrealized/ Realized | | | ||||||||||||||||||||||||
Crude oil swaps |
| | Cost of sales | | | Unrealized/ Realized | | | ||||||||||||||||||||||||
Natural gas swaps |
| | Cost of sales | | | Unrealized/ Realized | | | ||||||||||||||||||||||||
Interest rate swaps: |
1,979 | (1,398 | ) | Interest expense | 702 | 1,297 | Unrealized/ Realized | | | |||||||||||||||||||||||
Total |
$ | (142,775 | ) | $ | (10,924 | ) | $ | 46,944 | $ | (7,521 | ) | $ | (3,978 | ) | $ | (15,582 | ) | |||||||||||||||
The Company recorded the following gains (losses) in its unaudited condensed consolidated
statements of operations and its unaudited condensed consolidated statements of partners capital for the six months
ended June 30, 2011 and 2010 related to its derivative instruments not designated as cash flow
hedges:
Amount of Gain (Loss) | Amount of Gain (Loss) | |||||||||||||||
Recognized in | Recognized | |||||||||||||||
Realized Loss on | in Unrealized Loss | |||||||||||||||
Derivatives | on Derivatives | |||||||||||||||
Six Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
Type of Derivative | 2011 | 2010 | 2011 | 2010 | ||||||||||||
Fuel products segment: |
||||||||||||||||
Crude oil swaps |
$ | | $ | (4,390 | ) | $ | | $ | 6,938 | |||||||
Gasoline swaps |
| 7,103 | | (9,203 | ) | |||||||||||
Diesel swaps |
| (650 | ) | | 650 | |||||||||||
Jet fuel swaps |
| | | | ||||||||||||
Jet fuel collars |
(562 | ) | | 543 | (288 | ) | ||||||||||
Specialty products segment: |
||||||||||||||||
Crude oil collars |
| (2,959 | ) | | (1,268 | ) | ||||||||||
Crude oil swaps |
932 | (1,662 | ) | (662 | ) | (247 | ) | |||||||||
Natural gas swaps |
| (35 | ) | | (76 | ) | ||||||||||
Interest rate swaps: |
(752 | ) | (405 | ) | (1,046 | ) | 450 | |||||||||
Total |
$ | (382 | ) | $ | (2,998 | ) | $ | (1,165 | ) | $ | (3,044 | ) | ||||
The cash flow impact of the Companys derivative activities is classified as a change in
derivative activity in the operating activities section in the unaudited condensed consolidated
statements of cash flows.
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 Companys credit exposure related to these
derivative instruments is represented by the fair value of contracts reported as derivative assets.
To manage credit risk, the Company selects and periodically reviews counterparties based on credit
ratings. The Company executes all of its derivative instruments with large financial institutions
that have ratings of at least A2 and A by Moodys 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 contracts with these counterparties. No such
collateral was held by the Company as of June 30, 2011 or December 31, 2010. The Companys
contracts with these counterparties allow for netting of derivative instrument positions 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 Companys
condensed consolidated balance sheets and not netted against derivative assets or liabilities. As
of June 30, 2011, the Company had provided its counterparties with $11,900 cash collateral above
the $25,000 letter of credit provided to one
19
Table of Contents
counterparty to support crack spread hedging. As of December 31, 2010, the Company had
provided its counterparties with no cash collateral or letters of credit above the $50,000
prefunded letter of credit then in effect and provided to one counterparty to support crack spread
hedging. For financial reporting purposes, the Company does not offset the collateral provided to a
counterparty against the fair value of its obligation to that counterparty. Any outstanding
collateral is released to the Company upon settlement of the related derivative instrument
liability.
Certain of the Companys 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 Companys mark-to-market net
liability, if any, on all outstanding derivatives exceeds the credit threshold amount per such
credit support agreement. In certain cases, the Companys credit threshold is dependent upon the
Companys maintenance of certain corporate credit ratings with Moodys and S&P. In the event that
the Companys corporate credit rating was lowered below its current level by either Moodys or S&P,
such counterparties would have the right to reduce the applicable threshold to zero and demand full
collateralization of the Companys net liability position on outstanding derivative instruments. As
of June 30, 2011 and December 31, 2010, there was a net liability of $753 and $388, respectively,
associated with the Companys outstanding derivative instruments subject to such requirements. In
addition, the majority of the credit support agreements covering the Companys 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
Companys credit threshold could be lowered by such counterparty. The Company does not expect that
it will experience a material adverse change in its business.
The effective portion of the hedges classified in accumulated other comprehensive loss is
$118,598 as of June 30, 2011, and absent a change in the fair market value of the underlying
transactions, will be reclassified to earnings by December 31, 2013 with balances being recognized
as follows:
Accumulated Other | ||||
Comprehensive | ||||
Year | Loss | |||
2011 |
$ | 35,586 | ||
2012 |
80,630 | |||
2013 |
2,382 | |||
Total |
$ | 118,598 | ||
Based on fair values as of June 30, 2011, the Company expects to reclassify $79,666 of net
losses on derivative instruments from accumulated other comprehensive loss to earnings during the
next twelve months due to actual crude oil purchases, gasoline and diesel and jet fuel sales.
However, the amounts actually realized will be dependent on the fair values as of the date of
settlements.
Crude Oil Swap and Collar Contracts Specialty Products Segment
The Company is exposed to fluctuations in the price of crude oil, its principal raw material.
The Company utilizes combinations of options and swaps to manage crude oil price risk and
volatility of cash flows in its specialty products segment. These derivatives may be designated as
cash flow hedges of the future purchase of crude oil if they meet the hedge criteria. The Companys
general policy is to enter into crude oil derivative contracts that mitigate the Companys exposure
to price risk associated with crude oil purchases related to specialty products production (for up
to 70% of expected purchases). While the Companys policy generally requires that these positions
be short term in nature and expire within three to nine months from execution, the Company may
execute derivative contracts for up to two years forward, if a change in the risks supports
lengthening the Companys position. As of June 30, 2011, the Company did not have any crude oil
derivatives related to future crude oil purchases in its specialty products segment.
At December 31, 2010, the Company had the following crude oil derivatives related to crude oil
purchases in its specialty products segment, none of which were designated as hedges.
Average | ||||||||||||
Barrels | Swap | |||||||||||
Crude Oil Swap Contracts by Expiration Dates | Purchased | BPD | ($/Bbl) | |||||||||
February 2011 |
33,600 | 1,200 | $ | 83.10 | ||||||||
March 2011 |
37,200 | 1,200 | 83.55 | |||||||||
Totals |
70,800 | |||||||||||
Average price |
$ | 83.34 |
20
Table of Contents
Crude Oil Swap Contracts Fuel Products Segment
The Company is exposed to fluctuations in the price of crude oil, its principal raw material.
The Company utilizes swap contracts to manage crude oil price risk and volatility of cash flows in
its fuel products segment. The Companys policy is generally to enter into crude oil swap contracts
for a period no greater than five years forward and for no more than 75% of crude oil purchases
used in fuels production. At June 30, 2011, the Company had the following derivatives related to
crude oil purchases in its fuel products segment, all of which are designated as hedges.
Average | ||||||||||||
Barrels | Swap | |||||||||||
Crude Oil Swap Contracts by Expiration Dates | Purchased | BPD | ($/Bbl) | |||||||||
Third Quarter 2011 |
1,610,000 | 17,500 | $ | 77.38 | ||||||||
Fourth Quarter 2011 |
1,334,000 | 14,500 | 77.71 | |||||||||
Calendar Year 2012 |
5,626,000 | 15,372 | 87.43 | |||||||||
Calendar Year 2013 |
2,864,000 | 7,847 | 100.71 | |||||||||
Totals |
11,434,000 | |||||||||||
Average price |
$ | 88.21 |
At December 31, 2010, the Company had the following derivatives related to crude oil purchases
in its fuel products segment, all of which are designated as hedges.
Average | ||||||||||||
Barrels | Swap | |||||||||||
Crude Oil Swap Contracts by Expiration Dates | Purchased | BPD | ($/Bbl) | |||||||||
First Quarter 2011 |
1,215,000 | 13,500 | $ | 75.32 | ||||||||
Second Quarter 2011 |
1,729,000 | 19,000 | 76.62 | |||||||||
Third Quarter 2011 |
1,610,000 | 17,500 | 77.38 | |||||||||
Fourth Quarter 2011 |
1,334,000 | 14,500 | 77.71 | |||||||||
Calendar Year 2012 |
5,535,000 | 15,123 | 86.30 | |||||||||
Totals |
11,423,000 | |||||||||||
Average price |
$ | 81.41 |
Fuel Products Swap Contracts
The Company is exposed to fluctuations in the prices of gasoline, diesel and jet fuel. The
Company utilizes swap contracts to manage diesel, gasoline and jet fuel price risk and volatility
of cash flows in its fuel products segment. The Companys policy is generally to enter into diesel,
jet fuel and gasoline swap contracts for a period no longer than five years forward and for no more
than 75% of forecasted fuel sales.
Diesel Swap Contracts
At June 30, 2011, the Company had the following derivatives related to diesel and jet fuel
sales in its fuel products segment, all of which are designated as hedges.
Average | ||||||||||||
Swap | ||||||||||||
Diesel Swap Contracts by Expiration Dates | Barrels Sold | BPD | ($/Bbl) | |||||||||
Third Quarter 2011 |
552,000 | 6,000 | $ | 91.74 | ||||||||
Fourth Quarter 2011 |
552,000 | 6,000 | 91.74 | |||||||||
Calendar Year 2012 |
1,651,000 | 4,511 | 103.79 | |||||||||
Calendar Year 2013 |
824,000 | 2,258 | 125.69 | |||||||||
Totals |
3,579,000 | |||||||||||
Average price |
$ | 105.12 |
21
Table of Contents
At December 31, 2010, the Company had the following derivatives related to diesel and jet fuel
sales in its fuel products segment, all of which are designated as hedges.
Average | ||||||||||||
Swap | ||||||||||||
Diesel Swap Contracts by Expiration Dates | Barrels Sold | BPD | ($/Bbl) | |||||||||
First Quarter 2011 |
630,000 | 7,000 | $ | 89.57 | ||||||||
Second Quarter 2011 |
637,000 | 7,000 | 89.57 | |||||||||
Third Quarter 2011 |
552,000 | 6,000 | 91.74 | |||||||||
Fourth Quarter 2011 |
552,000 | 6,000 | 91.74 | |||||||||
Calendar Year 2012 |
1,560,000 | 4,262 | 99.27 | |||||||||
Totals |
3,931,000 | |||||||||||
Average price |
$ | 94.03 |
Jet Fuel Swap Contracts
At June 30, 2011, the Company had the following derivatives related to diesel and jet fuel
sales in its fuel products segment, all of which are designated as hedges.
Average | ||||||||||||
Swap | ||||||||||||
Jet Fuel Swap Contracts by Expiration Dates | Barrels Sold | BPD | ($/Bbl) | |||||||||
Third Quarter 2011 |
920,000 | 10,000 | $ | 89.86 | ||||||||
Fourth Quarter 2011 |
644,000 | 7,000 | 89.21 | |||||||||
Calendar Year 2012 |
3,838,500 | 10,488 | 99.78 | |||||||||
Calendar Year 2013 |
1,860,000 | 5,096 | 125.50 | |||||||||
Totals |
7,262,500 | |||||||||||
Average price |
$ | 104.17 |
At December 31, 2010, the Company had the following derivatives related to diesel and jet fuel
sales in its fuel products segment, all of which are designated as hedges.
Average | ||||||||||||
Swap | ||||||||||||
Jet Fuel Swap Contracts by Expiration Dates | Barrels Sold | BPD | ($/Bbl) | |||||||||
First Quarter 2011 |
405,000 | 4,500 | $ | 86.12 | ||||||||
Second Quarter 2011 |
819,000 | 9,000 | 89.58 | |||||||||
Third Quarter 2011 |
920,000 | 10,000 | 89.86 | |||||||||
Fourth Quarter 2011 |
644,000 | 7,000 | 89.21 | |||||||||
Calendar Year 2012 |
3,838,500 | 10,488 | 99.78 | |||||||||
Totals |
6,626,500 | |||||||||||
Average price |
$ | 95.28 |
Gasoline Swap Contracts
At June 30, 2011, the Company had the following derivatives related to gasoline sales in its
fuel products segment, all of which are designated as hedges.
Average | ||||||||||||
Swap | ||||||||||||
Gasoline Swap Contracts by Expiration Dates | Barrels Sold | BPD | ($/Bbl) | |||||||||
Third Quarter 2011 |
138,000 | 1,500 | $ | 85.50 | ||||||||
Fourth Quarter 2011 |
138,000 | 1,500 | 85.50 | |||||||||
Calendar Year 2012 |
136,500 | 373 | 89.04 | |||||||||
Calendar Year 2013 |
180,000 | 493 | 110.38 | |||||||||
Totals |
592,500 | |||||||||||
Average price |
$ | 93.87 |
22
Table of Contents
At December 31, 2010, the Company had the following derivatives related to gasoline sales
in its fuel products segment, all of which are designated as hedges.
Average | ||||||||||||
Swap | ||||||||||||
Gasoline Swap Contracts by Expiration Dates | Barrels Sold | BPD | ($/Bbl) | |||||||||
First Quarter 2011 |
180,000 | 2,000 | $ | 81.84 | ||||||||
Second Quarter 2011 |
273,000 | 3,000 | 82.66 | |||||||||
Third Quarter 2011 |
138,000 | 1,500 | 85.50 | |||||||||
Fourth Quarter 2011 |
138,000 | 1,500 | 85.50 | |||||||||
Calendar Year 2012 |
136,500 | 373 | 89.04 | |||||||||
Totals |
865,500 | |||||||||||
Average price |
$ | 84.40 |
Jet Fuel Put Spread Contracts
At June 30, 2011, the Company had the following jet fuel put options related to jet fuel crack
spreads in its fuel products segment, none of which are designated as hedges.
Average | Average | |||||||||||||||
Sold Put | Bought Put | |||||||||||||||
Jet Fuel Put Option Crack Spread Contracts by Expiration Dates | Barrels | BPD | ($/Bbl) | ($/Bbl) | ||||||||||||
Fourth Quarter 2011 |
184,000 | 2,000 | $ | 4.75 | $ | 7.00 | ||||||||||
Totals |
184,000 | |||||||||||||||
Average price |
$ | 4.75 | $ | 7.00 |
At December 31, 2010, the Company had the following jet fuel put options related to jet fuel
crack spreads in its fuel products segment, none of which are designated as hedges.
Average | Average | |||||||||||||||
Sold Put | Bought Put | |||||||||||||||
Jet Fuel Put Option Crack Spread Contracts by Expiration Dates | Barrels | BPD | ($/Bbl) | ($/Bbl) | ||||||||||||
First Quarter 2011 |
630,000 | 7,000 | $ | 4.00 | $ | 6.00 | ||||||||||
Fourth Quarter 2011 |
184,000 | 2,000 | 4.75 | 7.00 | ||||||||||||
Totals |
814,000 | |||||||||||||||
Average price |
$ | 4.17 | $ | 6.23 |
Natural Gas Swap Contracts
Natural gas purchases comprise a significant component of the Companys cost of sales;
therefore, changes in the price of natural gas also significantly affect its profitability and cash
flows. The Company utilizes swap contracts to manage natural gas price risk and volatility of cash
flows. The Companys policy is generally to enter into natural gas derivative contracts to hedge no
more than 75% of its upcoming fall and winter months anticipated natural gas requirement for a
period no greater than three years forward. At June 30, 2011 and December 31, 2010, the Company had
no derivatives outstanding related to natural gas purchases.
Interest Rate Swap Contracts
The Companys profitability and cash flows are affected by changes in interest rates,
specifically LIBOR and prime rates. The primary purpose of the Companys interest rate risk
management activities is to hedge its exposure to changes in interest rates. Historically, the
Companys policy has been to enter into interest rate swap agreements to hedge up to 75% of its
interest rate risk related to variable rate debt. With the completion of its 2019 Notes offering,
the Company does not expect to enter into additional hedges to fix its interest rates.
During 2010, the Company entered into forward swap contracts to manage interest rate risk
related to a portion of its then existing variable rate senior secured first lien term loan. The
Company hedged the future interest payments related to $100,000 of the total outstanding term loan
indebtedness for the period from February 15, 2011 to February 15, 2012 pursuant to these forward
swap contracts. These swap contracts were designated as cash flow hedges of the future payments of
interest with three-month LIBOR fixed at an average rate during the hedge period of 2.03%. Due to
the repayment of the variable rate senior secured first lien term loan in April 2011 with proceeds
from the issuance of the 2019 Notes, the interest rate swap contract was discontinued as a cash
flow hedge
23
Table of Contents
for the future payment of interest. For the three and six months ended June 30,
2011, the Company reclassified approximately $1,435 into unrealized loss on derivative instruments
in the unaudited condensed consolidated statements of operations.
In 2009, the Company hedged the future interest payments related to $200,000 of its total
outstanding term loan indebtedness for the period from February 15, 2010 to February 15, 2011. This
swap contract was designated as a cash flow hedge of the future payment of interest with
three-month LIBOR fixed at an average rate during the hedge period of 0.94%. The cash flow hedge
settled during the first quarter of 2011.
In 2008, the Company entered into a forward swap contract to manage interest rate risk related
to a portion of its then existing variable rate senior secured first lien term loan which closed
January 3, 2008. The Company hedged the future interest payments related to $50,000 of the total
outstanding term loan indebtedness in 2010, pursuant to this forward swap contract. This swap
contract was designated as a cash flow hedge of the future payment of interest with three-month
LIBOR fixed at 3.66% per annum in 2010 and the first quarter of 2011. The cash flow hedge settled
during the first quarter of 2011.
In 2006, the Company entered into a forward swap contract to manage interest rate risk related
to a portion of its then existing variable rate senior secured first lien term loan. Due to the
repayment of $19,000 of the outstanding balance of the Companys then existing term loan facility
in August 2007 and subsequent refinancing of the remaining term loan balance, this swap contract
was not designated as a cash flow hedge of the future payment of interest. The entire change in the
fair value of this interest rate swap is recorded to unrealized loss on derivative instruments in
the unaudited condensed consolidated statements of operations. In the first quarter of 2008, the
Company fixed its unrealized loss on this interest rate swap derivative instrument by entering into
an offsetting interest rate swap expiring December 2012, which is not designated as a cash flow
hedge.
7. Fair Value of Financial Instruments
The Companys financial instruments which require fair value disclosure consist primarily of
cash and cash equivalents, accounts receivable, financial derivatives, accounts payable and
indebtedness. The carrying values of cash and cash equivalents, accounts receivable and accounts
payable are considered to be representative of their respective fair values, due to the short
maturity of these instruments. Derivative instruments are reported in the accompanying unaudited
condensed consolidated financial statements at fair value. The fair value of the Companys 2019
Notes was $412,000 at June 30, 2011, using quoted market prices. The fair value of the Companys
term loan was $355,445 at December 31, 2010, using quoted market prices. The carrying values of
borrowings under the Companys senior secured revolving credit facility were $28,090 and $10,832 at
June 30, 2011 and December 31, 2010, respectively, and approximate their fair values.
8. Fair Value Measurements
The Company uses a three-tier fair value hierarchy, which prioritizes the inputs used in
measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted
prices in active markets; Level 2, defined as inputs other than quoted prices in active markets
that are either directly or indirectly observable; and Level 3, defined as 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.
As of June 30, 2011, the Company held certain assets and liabilities that are required to be
measured at fair value on a recurring basis. These included the Companys derivative instruments
related to crude oil, gasoline, diesel, jet fuel and interest rates and investments associated with
the Companys non-contributory defined benefit plan (Pension Plan).
The Companys derivative instruments consist of over-the-counter (OTC) contracts, which are
not traded on a public exchange. Substantially all of the Companys derivative instruments are with
counterparties that have long-term credit ratings of at least A2 and A by Moodys and S&P,
respectively. To estimate the fair values of the Companys derivative instruments, the Company uses
the market approach. Under this approach, the fair values of the Companys derivative instruments
for crude oil, gasoline, diesel, jet fuel and interest rates are determined primarily based on
inputs that are readily available in public markets or can be derived from information available in
publicly quoted markets. Generally, the Company obtains this data through surveying its
counterparties and
24
Table of Contents
performing various analytical tests to validate the data. The Company determines the fair
value of its crude oil option contracts utilizing a standard option pricing model based on inputs
that can be derived from information available in publicly quoted markets, or are quoted by
counterparties to these contracts. In situations where the Company obtains inputs via quotes from
its counterparties, it verifies the reasonableness of these quotes via similar quotes from another
counterparty as of each date for which financial statements are prepared. The Company also includes
an adjustment for non-performance risk in the recognized measure of fair value of all of the
Companys derivative instruments. The adjustment reflects the full credit default spread (CDS)
applied to a net exposure by counterparty. When the Company is in a net asset position, it uses its
counterpartys CDS, or a peer groups estimated CDS when a CDS for the counterparty is not
available. The Company uses its own peer groups estimated CDS when it is in a net liability
position. As a result of applying the applicable CDS, at June 30, 2011 and December 31, 2010, the
Companys liability was reduced by approximately $2,025 and $687, respectively. Based on the use of
various unobservable inputs, principally non-performance risk and unobservable inputs in forward
years for gasoline, jet fuel and diesel, the Company has categorized these derivative instruments
as Level 3. The Company has consistently applied these valuation techniques in all periods
presented and believes it has obtained the most accurate information available for the types of
derivative instruments it holds.
The Companys investments associated with its Pension Plan primarily consist of (i) mutual
funds that are publicly traded and (ii) a commingled fund. The mutual funds are publicly traded and
market prices of the mutual funds are readily available; thus, these investments are categorized as
Level 1. The commingled fund is categorized as Level 2 because inputs used in its valuation are not
quoted prices in active markets that are indirectly observable and is valued at the net asset value
of shares held by the Pension Plan at quarter end.
The Companys assets and liabilities measured at fair value at June 30, 2011 were as follows:
Fair Value Measurements | ||||||||||||||||
Level 1 | Level 2 (a) | Level 3 | Total | |||||||||||||
Assets: |
||||||||||||||||
Cash and cash equivalents |
$ | 55 | $ | | $ | | $ | 55 | ||||||||
Crude oil swaps |
| | 126,090 | 126,090 | ||||||||||||
Gasoline swaps |
| | | | ||||||||||||
Diesel swaps |
| | | | ||||||||||||
Jet fuel swaps |
| | | | ||||||||||||
Crude oil options |
| | | | ||||||||||||
Jet fuel options |
| | | | ||||||||||||
Pension plan investments |
15,018 | 2,095 | | 17,113 | ||||||||||||
Total assets at fair value |
$ | 15,073 | $ | 2,095 | $ | 126,090 | $ | 143,258 | ||||||||
Liabilities: |
||||||||||||||||
Crude oil swaps |
$ | | $ | | $ | | $ | | ||||||||
Gasoline swaps |
| | (12,815 | ) | (12,815 | ) | ||||||||||
Diesel swaps |
| | (75,698 | ) | (75,698 | ) | ||||||||||
Jet fuel swaps |
| | (173,134 | ) | (173,134 | ) | ||||||||||
Crude oil options |
| | | | ||||||||||||
Jet fuel options |
| | | | ||||||||||||
Interest rate swaps |
| | (2,328 | ) | (2,328 | ) | ||||||||||
Pension plan investments |
| | | | ||||||||||||
Total liabilities at fair value |
$ | | $ | | $ | (263,975 | ) | $ | (263,975 | ) | ||||||
(a) | Transferred from Level 1 to Level 2 in the first quarter of 2011 because of lack of observable market data in the underlying investments. |
25
Table of Contents
The Companys financial assets and liabilities measured at fair value at December 31, 2010
were as follows:
Fair Value Measurements | ||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
Assets: |
||||||||||||||||
Cash and cash equivalents |
$ | 37 | $ | | $ | | $ | 37 | ||||||||
Crude oil swaps |
| | 135,578 | 135,578 | ||||||||||||
Gasoline swaps |
| | | | ||||||||||||
Diesel swaps |
| | | | ||||||||||||
Jet fuel swaps |
| | | | ||||||||||||
Crude oil options |
| | | | ||||||||||||
Jet fuel options |
| | 20 | 20 | ||||||||||||
Pension plan investments |
16,039 | | | 16,039 | ||||||||||||
Total assets at fair value |
$ | 16,076 | $ | | $ | 135,598 | $ | 151,674 | ||||||||
Liabilities: |
||||||||||||||||
Crude oil swaps |
$ | | $ | | $ | | $ | | ||||||||
Gasoline swaps |
| | (14,149 | ) | (14,149 | ) | ||||||||||
Diesel swaps |
| | (53,744 | ) | (53,744 | ) | ||||||||||
Jet fuel swaps |
| | (96,556 | ) | (96,556 | ) | ||||||||||
Crude oil options |
| | | | ||||||||||||
Jet fuel options |
| | | | ||||||||||||
Interest rate swaps |
| | (3,963 | ) | (3,963 | ) | ||||||||||
Pension plan investments |
| | | | ||||||||||||
Total liabilities at fair value |
$ | | $ | | $ | (168,412 | ) | $ | (168,412 | ) | ||||||
The table below sets forth a summary of net changes in fair value of the Companys Level 3
financial assets and liabilities for the six months ended June 30, 2011 and 2010:
Six Months Ended | ||||||||
June 30, | ||||||||
2011 | 2010 | |||||||
Fair value at January 1, |
$ | (32,814 | ) | $ | 26,138 | |||
Realized losses |
1,984 | 5,858 | ||||||
Unrealized losses |
(3,541 | ) | (15,766 | ) | ||||
Change in fair value of cash flow hedges |
(142,775 | ) | (10,924 | ) | ||||
Settlements |
39,261 | (14,823 | ) | |||||
Transfers in (out) of Level 3 |
| | ||||||
Fair value at June 30, |
$ | (137,885 | ) | $ | (9,517 | ) | ||
Total losses included in net loss
attributable to changes in unrealized
losses relating to financial assets and
liabilities held as of June 30, |
$ | (3,541 | ) | $ | (15,766 | ) | ||
All settlements from derivative instruments that are deemed effective and were designated as
cash flow hedges are included in sales for gasoline, diesel and jet fuel derivatives, cost of sales
for crude oil and natural gas derivatives, and interest expense for interest rate derivatives in
the unaudited condensed consolidated financial statements of operations in the period that the
hedged cash flow occurs. Any ineffectiveness associated with these derivative instruments are
recorded in earnings immediately in unrealized loss on derivative instruments in the unaudited
condensed consolidated statements of operations. All settlements from derivative instruments not
designated as cash flow hedges are recorded in realized loss on derivative instruments in the
unaudited condensed consolidated statements of operations. See Note 6 for further information on
derivative instruments.
9. Partners Capital
In February 2011, the Company satisfied the last of the earnings and distributions tests
contained in its partnership agreement for the automatic conversion of all 13,066,000 outstanding
subordinated units into common units on a one-for-one basis. The last of these requirements was met
upon payment of the quarterly distribution paid on February 14, 2011. Two days following this
quarterly distribution to unitholders, or February 16, 2011, all of the outstanding subordinated
units automatically converted to common units.
On February 24, 2011, the Company completed an equity offering of its common units in which it
sold 4,500,000 common units to the underwriters of the offering at a price to the public of $21.45
per common unit. The proceeds received by the Company from this offering (net of underwriting
discounts, commissions and expenses but before its general partners capital contribution) were
$92,290 and were used to repay borrowings under its revolving credit facility. Underwriting
discounts totaled $3,915. The Companys general
26
Table of Contents
partner contributed $1,970 to retain its 2% general partner interest.
10. Comprehensive Income (Loss)
Comprehensive income (loss) for the Company includes the change in fair value of cash flow
hedges and the minimum pension liability adjustment that have not been recognized in net loss.
Comprehensive income (loss) for the three and six months ended June 30, 2011 and 2010 was as follows:
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Net loss |
$ | (7,651 | ) | $ | (907 | ) | $ | (3,450 | ) | $ | (13,974 | ) | ||||
Cash flow hedge (gain) loss reclassified to net loss |
27,430 | (1,791 | ) | 46,944 | (7,521 | ) | ||||||||||
Change in fair value of cash flow hedges |
(14,051 | ) | (4,825 | ) | (142,775 | ) | (10,924 | ) | ||||||||
Defined benefit pension and retiree health benefit plans |
61 | 59 | 122 | 464 | ||||||||||||
Total comprehensive income (loss) |
$ | 5,789 | $ | (7,464 | ) | $ | (99,159 | ) | $ | (31,955 | ) | |||||
11. Unit-Based Compensation and Distributions
A summary of the Companys nonvested phantom units as of June 30, 2011 and the changes during
the six months ended June 30, 2011is presented below:
Weighted Average | ||||||||
Grant Date | ||||||||
Nonvested Phantom Units | Grant | Fair Value | ||||||
Nonvested at December 31, 2010 |
105,492 | $ | 17.68 | |||||
Granted |
47,927 | 21.31 | ||||||
Vested |
(48,900 | ) | 19.58 | |||||
Forfeited |
| | ||||||
Nonvested at June 30, 2011 |
104,519 | $ | 18.46 | |||||
For the three months ended June 30, 2011 and 2010, compensation expense of $653 and $145,
respectively, was recognized in the unaudited condensed consolidated statements of operations
related to vested phantom unit grants. For the six months ended June 30, 2011 and 2010,
compensation expense of $1,282 and $292, respectively, was recognized in the unaudited condensed
statements of operations related to vested phantom unit grants. As of June 30, 2011 and 2010,
there was a total of $1,929 and $899, respectively, of unrecognized compensation costs related to
nonvested phantom unit grants. These costs are expected to be recognized over a weighted-average
period of approximately three years.
The Companys distribution policy is as defined in its partnership agreement. For the three
months ended June 30, 2011 and 2010, the Company made distributions of $19,311 and $16,391,
respectively, to its partners. For the six months ended June 30, 2011 and 2010, the Company made
distributions of $36,258 and $32,788, respectively, to its partners.
12. Employee Benefit Plans
The components of net periodic pension and other post retirement benefits cost for the three
months ended June 30, 2011 and 2010 were as follows:
For the Three Months Ended June 30, | ||||||||||||||||
2011 | 2010 | |||||||||||||||
Other Post | Other Post | |||||||||||||||
Pension | Retirement | Pension | Retirement | |||||||||||||
Benefits | Employee Benefits | Benefits | Employee Benefits | |||||||||||||
Service cost |
$ | 25 | $ | | $ | 21 | $ | | ||||||||
Interest cost |
333 | 4 | 334 | 6 | ||||||||||||
Expected return on assets |
(265 | ) | | (258 | ) | | ||||||||||
Amortization of net (gain) loss |
70 | | 68 | | ||||||||||||
Prior service cost |
| (9 | ) | | (9 | ) | ||||||||||
Net periodic benefit cost |
$ | 163 | $ | (5 | ) | $ | 165 | $ | (3 | ) | ||||||
27
Table of Contents
The components of net periodic pension and other post retirement benefits cost for the six
months ended June 30, 2011 and 2010 were as follows:
For the Six Months Ended June 30, | ||||||||||||||||
2011 | 2010 | |||||||||||||||
Other Post | Other Post | |||||||||||||||
Pension | Retirement | Pension | Retirement | |||||||||||||
Benefits | Employee Benefits | Benefits | Employee Benefits | |||||||||||||
Service cost |
$ | 49 | $ | | $ | 42 | $ | | ||||||||
Interest cost |
666 | 9 | 668 | 12 | ||||||||||||
Expected return on assets |
(529 | ) | | (517 | ) | | ||||||||||
Amortization of net (gain) loss |
140 | (1 | ) | 137 | (1 | ) | ||||||||||
Prior service cost |
| (18 | ) | | (18 | ) | ||||||||||
Net periodic benefit cost |
$ | 326 | $ | (10 | ) | $ | 330 | $ | (7 | ) | ||||||
During the three months ended June 30, 2011 and 2010, the Company made contributions of $374
and $337, respectively, to its non-contributory defined benefit plan (the Pension Plan). During
the six months ended June 30, 2011 and 2010, the Company made contributions of $936 and $337,
respectively, and expects to make total contributions to its Pension Plan in 2011 of $1,685.
The Companys investments associated with its Pension Plan primarily consist of (i) mutual
funds that are publicly traded and (ii) a commingled fund. The mutual funds are publicly traded and
market prices of the mutual funds are readily available; thus, these investments are categorized as
Level 1. The commingled fund is categorized as Level 2 because inputs used in its valuation are not
quoted prices in active markets that are indirectly observable and is valued at the net asset value
of the shares held by the Pension Plan at quarter end. The Companys Pension Plan assets measured
at fair value at June 30, 2011 and December 31, 2010 were as follows:
June 30, 2011 | December 31, 2010 | |||||||||||||||
Pension Benefits | Pension Benefits | |||||||||||||||
Level 1 | Level 2 | Level 1 | Level 2 | |||||||||||||
Cash |
$ | 3,747 | $ | | $ | 347 | $ | | ||||||||
Equity |
4,208 | | 7,784 | | ||||||||||||
Foreign equities |
839 | | 1,890 | | ||||||||||||
Commingled fund |
| 2,095 | | | ||||||||||||
Fixed income |
6,224 | | 6,018 | | ||||||||||||
$ | 15,018 | $ | 2,095 | $ | 16,039 | $ | | |||||||||
13. Transactions with Related Parties
On March 24, 2011, Calumet Lubricants Co., Limited Partnership (Calumet Lubricants), a
wholly owned subsidiary of the Company, entered into Amendment No. 5 (the Princeton Amendment) to
that certain Crude Oil Supply Agreement, effective as of April 30, 2008 (as amended since such
date, the Princeton Crude Oil Supply Agreement), by and between Calumet Lubricants and Legacy
Resources Co., L.P. (Legacy), under which Legacy supplies the Companys Princeton refinery with
all of the refinerys crude oil requirements on a just-in-time basis. The Princeton Amendment,
effective as of March 1, 2011, modified the market-based pricing mechanism established in the
Princeton Crude Oil Supply Agreement and shortened the termination notice period set forth in the
Princeton Crude Oil Supply Agreement from approximately 90 days to approximately 60 days.
Concurrent with entering into the Princeton Amendment, on March 24, 2011, Calumet Lubricants
provided notice to Legacy that it was exercising its contractual rights under the Princeton Crude
Oil Supply Agreement, as amended by the Princeton Amendment, to terminate the Princeton Crude Oil
Supply Agreement on May 31, 2011. The Company did not incur any material early termination
penalties in connection with its termination of the Princeton Crude Oil Supply Agreement.
On March 24, 2011, Calumet Shreveport Fuels, LLC (Calumet Shreveport Fuels), a wholly owned
subsidiary of the Company, entered into Amendment No. 5 (the Shreveport Amendment) to that
certain Crude Oil Supply Agreement, effective as of September 1, 2009 (as amended since such date,
the Shreveport Crude Oil Supply Agreement), by and between Calumet Shreveport Fuels and Legacy,
under which Legacy supplies the Companys Shreveport refinery with a portion of the refinerys
crude oil requirements on a just-in-time basis. The Shreveport Amendment, effective as of March 1,
2011, modified the market-based pricing mechanism established in the Shreveport Crude Oil Supply
Agreement and shortened the termination notice period set forth in the Shreveport Crude Oil Supply
Agreement from approximately 90 days to approximately 60 days. Concurrent with entering into the
Shreveport Amendment, on March 24, 2011, Calumet Shreveport Fuels provided notice to Legacy that it
was exercising its contractual rights under the Shreveport Crude Oil Supply Agreement, as amended
by the Shreveport Amendment, to terminate the Shreveport Crude Oil
28
Table of Contents
Supply Agreement on May 31, 2011. The Company did not incur any material early termination
penalties in connection with its termination of the Shreveport Crude Oil Supply Agreement.
With the termination of the agreements, the Company has one remaining crude oil supply
agreement with Legacy, the Master Crude Oil Purchase and Sale Agreement, that was entered into on
January 26, 2009. No crude oil is currently being purchased by the Company under this agreement.
Legacy is owned in part by three of the Companys limited partners, an affiliate of the
Companys general partner, the Companys chief executive officer and vice chairman, F. William
Grube, and the Companys president and chief operating officer, Jennifer G. Straumins. During the
three and six months ended June 30, 2011, the Company had crude oil purchases of $48,036 and
$241,287, respectively, from Legacy. Accounts payable to Legacy at June 30, 2011 were $95.
14. Segments and Related Information
a. Segment Reporting
The Company has two reportable segments: Specialty Products and Fuel Products. The Specialty
Products segment produces a variety of lubricating oils, solvents, waxes and asphalt and other
by-products. These products are sold to customers who purchase these products primarily as raw
material components for basic automotive, industrial and consumer goods. The Fuel Products segment
produces a variety of fuel and fuel-related products including gasoline, diesel and jet fuel.
Because of the similar economic characteristics, certain operations have been aggregated for
segment reporting purposes.
The accounting policies of the segments are the same as those described in the summary of
significant accounting policies except that the Company evaluates segment performance based on
income (loss) from operations. The Company accounts for intersegment sales and transfers at cost
plus a specified mark-up. Reportable segment information is as follows:
29
Table of Contents
Specialty | Fuel | Combined | Consolidated | |||||||||||||||||
Three Months Ended June 30, 2011 | Products | Products | Segments | Eliminations | Total | |||||||||||||||
Sales: |
||||||||||||||||||||
External customers |
$ | 466,414 | $ | 267,356 | $ | 733,770 | $ | | $ | 733,770 | ||||||||||
Intersegment sales |
291,351 | 15,272 | 306,623 | (306,623 | ) | | ||||||||||||||
Total sales |
$ | 757,765 | $ | 282,628 | $ | 1,040,393 | $ | (306,623 | ) | $ | 733,770 | |||||||||
Depreciation and amortization |
17,722 | | 17,722 | | 17,722 | |||||||||||||||
Operating income (loss) |
35,485 | (12,074 | ) | 23,411 | | 23,411 | ||||||||||||||
Reconciling items to net loss: |
||||||||||||||||||||
Interest expense |
(10,544 | ) | ||||||||||||||||||
Debt extinguishment costs |
(15,130 | ) | ||||||||||||||||||
Loss on derivative instruments |
(5,494 | ) | ||||||||||||||||||
Other |
274 | |||||||||||||||||||
Income tax expense |
(168 | ) | ||||||||||||||||||
Net loss |
$ | (7,651 | ) | |||||||||||||||||
Capital expenditures |
$ | 14,069 | $ | | $ | 14,069 | $ | | $ | 14,069 |
Specialty | Fuel | Combined | Consolidated | |||||||||||||||||
Three Months Ended June 30, 2010 | Products | Products | Segments | Eliminations | Total | |||||||||||||||
Sales: |
||||||||||||||||||||
External customers |
$ | 329,423 | $ | 185,229 | $ | 514,652 | $ | | $ | 514,652 | ||||||||||
Intersegment sales |
188,654 | 16,427 | 205,081 | (205,081 | ) | | ||||||||||||||
Total sales |
$ | 518,077 | $ | 201,656 | $ | 719,733 | $ | (205,081 | ) | $ | 514,652 | |||||||||
Depreciation and amortization |
18,017 | | 18,017 | | 18,017 | |||||||||||||||
Operating income |
19,472 | 292 | 19,764 | | 19,764 | |||||||||||||||
Reconciling items to net loss: |
||||||||||||||||||||
Interest expense |
(7,277 | ) | ||||||||||||||||||
Loss on derivative instruments |
(13,305 | ) | ||||||||||||||||||
Other |
9 | |||||||||||||||||||
Income tax expense |
(98 | ) | ||||||||||||||||||
Net loss |
$ | (907 | ) | |||||||||||||||||
Capital expenditures |
$ | 11,348 | $ | | $ | 11,348 | $ | | $ | 11,348 |
Specialty | Fuel | Combined | Consolidated | |||||||||||||||||
Six Months Ended June 30, 2011 | Products | Products | Segments | Eliminations | Total | |||||||||||||||
Sales: |
||||||||||||||||||||
External customers |
$ | 863,516 | $ | 475,494 | $ | 1,339,010 | $ | | $ | 1,339,010 | ||||||||||
Intersegment sales |
507,428 | 18,907 | 526,335 | (526,335 | ) | | ||||||||||||||
Total sales |
$ | 1,370,944 | $ | 494,401 | $ | 1,865,345 | $ | (526,335 | ) | $ | 1,339,010 | |||||||||
Depreciation and amortization |
36,365 | | 36,365 | | 36,365 | |||||||||||||||
Operating income (loss) |
51,955 | (16,390 | ) | 35,565 | | 35,565 | ||||||||||||||
Reconciling items to net loss: |
||||||||||||||||||||
Interest expense |
(18,025 | ) | ||||||||||||||||||
Debt extinguishment costs |
(15,130 | ) | ||||||||||||||||||
Loss on derivative instruments |
(5,525 | ) | ||||||||||||||||||
Other |
103 | |||||||||||||||||||
Income tax expense |
(438 | ) | ||||||||||||||||||
Net loss |
$ | (3,450 | ) | |||||||||||||||||
Capital expenditures |
$ | 20,635 | $ | | $ | 20,635 | $ | | $ | 20,635 |
30
Table of Contents
Specialty | Fuel | Combined | Consolidated | |||||||||||||||||
Six Months Ended June 30, 2010 | Products | Products | Segments | Eliminations | Total | |||||||||||||||
Sales: |
||||||||||||||||||||
External customers |
$ | 634,899 | $ | 364,370 | $ | 999,269 | $ | | $ | 999,269 | ||||||||||
Intersegment sales |
363,261 | 27,217 | 390,478 | (390,478 | ) | | ||||||||||||||
Total sales |
$ | 998,160 | $ | 391,587 | $ | 1,389,747 | $ | (390,478 | ) | $ | 999,269 | |||||||||
Depreciation and amortization |
35,508 | | 35,508 | | 35,508 | |||||||||||||||
Operating income |
16,835 | 5,836 | 22,671 | | 22,671 | |||||||||||||||
Reconciling items to net loss: |
||||||||||||||||||||
Interest expense |
(14,711 | ) | ||||||||||||||||||
Loss on derivative instruments |
(21,624 | ) | ||||||||||||||||||
Other |
(50 | ) | ||||||||||||||||||
Income tax expense |
(260 | ) | ||||||||||||||||||
Net loss |
$ | (13,974 | ) | |||||||||||||||||
Capital expenditures |
$ | 17,017 | $ | | $ | 17,017 | $ | | $ | 17,017 |
June 30, 2011 | December 31, 2010 | |||||||
Segment assets: |
||||||||
Specialty products |
$ | 1,058,981 | $ | 962,850 | ||||
Fuel products |
137,243 | 53,822 | ||||||
Total assets |
$ | 1,196,224 | $ | 1,016,672 | ||||
b. Geographic Information
International sales accounted for less than 10% of consolidated sales in each of the three
months and six months ended June 30, 2011 and 2010. All of the Companys long-lived assets are
domestically located.
c. Product Information
The Company offers products primarily in five general categories consisting of lubricating
oils, solvents, waxes, fuels and asphalt and by-products. Fuel products primarily consist of
gasoline, diesel, jet fuel and by-products. The following table sets forth the major product
category sales:
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Specialty products: |
||||||||||||||||
Lubricating oils |
$ | 246,448 | $ | 176,354 | $ | 455,499 | $ | 340,402 | ||||||||
Solvents |
135,642 | 95,777 | 253,978 | 183,631 | ||||||||||||
Waxes |
33,874 | 28,362 | 68,181 | 54,608 | ||||||||||||
Fuels |
592 | 2,232 | 1,423 | 3,971 | ||||||||||||
Asphalt and other by-products |
49,858 | 26,698 | 84,435 | 52,287 | ||||||||||||
Total |
$ | 466,414 | $ | 329,423 | $ | 863,516 | $ | 634,899 | ||||||||
Fuel products: |
||||||||||||||||
Gasoline |
127,452 | 76,287 | 223,233 | 152,170 | ||||||||||||
Diesel |
91,611 | 77,396 | 173,764 | 141,626 | ||||||||||||
Jet fuel |
40,686 | 27,816 | 67,460 | 65,380 | ||||||||||||
By-products |
7,607 | 3,730 | 11,037 | 5,194 | ||||||||||||
Total |
$ | 267,356 | $ | 185,229 | $ | 475,494 | $ | 364,370 | ||||||||
Consolidated sales |
$ | 733,770 | $ | 514,652 | $ | 1,339,010 | $ | 999,269 | ||||||||
d. Major Customers
During the three and six months ended June 30, 2011 and 2010, the Company had no customer that
represented 10% or greater of consolidated sales.
31
Table of Contents
15. Subsequent Events
On July 22, 2011, the Company declared a quarterly cash distribution of $0.495 per unit on all
outstanding units, or approximately $20,124 in aggregate, for the quarter ended June 30, 2011. The distribution will be paid
on August 12, 2011 to unitholders of record as of the close of business on August 2, 2011. This
quarterly distribution of $0.495 per unit equates to $1.98 per unit, or approximately $80,496 in aggregate on an annualized
basis.
The fair value of the Companys derivatives decreased by approximately $46,000 subsequent to
June 30, 2011 to a liability of approximately $184,000. As of
August 8, 2011, the Company had $31,300 in cash
margin posted with one counterparty to support crack spread hedging. The fair value of the Companys long-term debt, excluding capital leases, has not changed materially subsequent to June 30, 2011.
On July 25, 2011, the Company entered into a definitive asset purchase agreement with Murphy
Oil Corporation (Murphy Oil), pursuant to which the Company will acquire (the Superior
Acquisition):
| Murphy Oils refinery located in Superior, Wisconsin (the Superior Refinery) and associated inventories; | ||
| the Superior Refinerys wholesale marketing business and related assets, including certain owned or leased Murphy Oil product terminals located in Superior and Rhinelander, Wisconsin, Duluth and Crookston and Proctor, Minnesota, Grand Island, Nebraska and Toole, Utah and associated inventories and logistics assets located at each of the foregoing facilities; and | ||
| Murphy Oils SPUR branded gasoline wholesale business and related assets. |
The Superior Acquisition is expected to close by the end of the third quarter of 2011, subject
to customary closing conditions and regulatory approvals.
The Superior Refinery produces gasoline, distillate, asphalt and specialty petroleum products
that are marketed in the Midwest region of the United States, Canada and the surrounding border
states. The Superior wholesale business transports products produced at the Superior Refinery
through several Magellan pipeline terminals in Minnesota, Wisconsin, Iowa, North Dakota and South
Dakota and through its own leased and owned product terminals located in Superior and Rhinelander,
Wisconsin, Duluth, Crookston and Proctor, Minnesota, Grand Island, Nebraska and Toole, Utah. The
Superior Wholesale Business also sells gasoline wholesale to SPUR branded gas stations, which are
owned and operated by independent franchisees.
The aggregate purchase price for the acquired business is $214,000, plus the market value of
the acquired business hydrocarbon inventories at closing and the reimbursement of certain capital
expenditures to be incurred at the Superior Refinery during the period from the execution of the
Purchase Agreement to the closing of the Superior Acquisition (the Interim Period). The purchase
price is also subject to customary purchase price adjustments. The Company intends to finance the
Superior Acquisition primarily through a combination of equity and long-term debt financing and
through borrowings under its revolving credit facility. The Companys obligation to consummate the
Superior Acquisition is not conditioned upon the receipt of financing.
32
Table of Contents
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
The historical consolidated financial statements included in this Quarterly Report reflect all
of the assets, liabilities and results of operations of Calumet Specialty Products Partners, L.P.
(Calumet, the Company, we, our, us). The following discussion analyzes the financial
condition and results of operations of Calumet for the three and six months ended June 30, 2011 and
2010. Unitholders should read the following discussion and analysis of the financial condition and
results of operations for Calumet in conjunction with our 2010 Annual Report and the historical
unaudited condensed consolidated financial statements and notes of the Company included elsewhere
in this Quarterly Report.
Overview
We are a leading independent producer of high-quality, specialty hydrocarbon products in North
America. We own plants located in Princeton, Louisiana, Cotton Valley, Louisiana, Shreveport,
Louisiana, Karns City, Pennsylvania and a terminal located in Burnham, Illinois. Our business is
organized into two segments: specialty products and fuel products. In our specialty products
segment, we process crude oil and other feedstocks into a wide variety of customized lubricating
oils, white mineral oils, solvents, petrolatums and waxes. Our specialty products are sold to
domestic and international customers who purchase them primarily as raw material components for
basic industrial, consumer and automotive goods. In our fuel products segment, we process crude oil
into a variety of fuel and fuel-related products, including gasoline, diesel and jet fuel. In
connection with our production of specialty products and fuel products, we also produce asphalt and
a limited number of other by-products.
Second Quarter 2011 Update
For the three months ended June 30, 2011 and 2010, 51.5% and 51.8%, respectively, of our sales
volume and 115.3% and 93.5%, respectively, of our gross profit was generated from our specialty
products segment while, for the same periods, 48.5% and 48.2%, respectively, of our sales volume
and (15.3)% and 6.5%, respectively, of our gross profit was generated from our fuel products
segment.
We noted continued improvement in our specialty products segment during the second quarter of
2011. The trend of increased demand for our specialty products has continued, with specialty
products segment sales volume increasing 12.8% for the quarter ended June 30, 2011 compared to the
same period in 2010. Specialty products segment generated a gross profit margin of 12.5% in the
second quarter of 2011, as compared to a gross profit margin of 14.1% for the same period in the
prior year.
While fuel products refining margins significantly strengthened during the second quarter, our
fuel products segment did not fully realize the impact of higher market crack spreads due primarily
to lower than expected run rates caused by the approximately three week shutdown during May and
June 2011 of the ExxonMobil crude oil pipeline serving our Shreveport refinery resulting from the
Mississippi River flooding during this period, resulting in minimal unhedged fuel products barrels.
In addition, we recorded realized derivative losses of $27.4 million during the second quarter in
our fuel products segment. We expect to benefit more significantly going forward from the higher
market crack spread environment as our overall production rates have increased subsequent to the
restart of the pipeline in late June 2011. In addition, during this period of higher crack spreads
we have entered into additional crack spread hedges, hedging crack spreads on 7,847 barrels per day
in calendar year 2013 at an average of $23.90 per barrel, an $11.42 per barrel increase over our
average hedged crack spreads in calendar year 2011.
Our second quarter 2011 total production increased by 13.2% quarter over quarter, due
primarily to our decision to increase production run rates at our Shreveport refinery to take
advantage of better fuel refining crack spreads in the second quarter of 2011, the impact of
the failure of an environmental operating unit at our Shreveport refinery in the first quarter of
2010 that was not replaced until after the second quarter of 2010 and a planned
turnaround at our Shreveport refinery in the second quarter of 2010, with no such events in 2011,
partially offset by the impact of the approximately three week shutdown during May and June 2011 of
the ExxonMobil crude oil pipeline serving our Shreveport refinery resulting from the Mississippi
River flooding occurring during this period. Production levels at our other facilities, which focus
primarily on the production of specialty products, also increased quarter over quarter to take
advantage of higher specialty products demand.
We used $70.6 million in cash flows from operating activities during the second quarter of
2011 primarily due to increased crude inventory levels as a result of terminating certain
just-in-time inventory supply arrangements with a related party, Legacy, effective May 31, 2011,
increased working capital requirements resulting from increased run rates at our Shreveport
refinery and higher commodity prices in general. We plan to continue focusing our efforts on
generating positive cash flows from operations which we expect will be used to (i) improve our
liquidity position, (ii) pay quarterly distributions to our unitholders, (iii) service our debt
obligations and (iv) provide funding for general partnership purposes.
33
Table of Contents
During the second quarter of 2011, we restructured the majority of our outstanding long-term
debt. We issued $400.0 million in aggregate principal amount of our 9 3/8% senior notes due 2019
(the 2019 Notes) in a private placement and used the majority of the proceeds to repay borrowings
under, and subsequently extinguish, our $435.0 million term loan facility, consisting of a $385.0
million term loan and a prefunded $50 million letter of credit to support crack spread hedging. We
also amended our master derivative contracts with various hedging counterparties and entered into a
collateral sharing agreement with these counterparties to continue to support our fuel products
hedging program. Further, we amended and restated our revolving credit agreement to increase the
credit facility from $375.0 million to $550.0 million, as well as amend its covenants and terms.
Superior Refinery Purchase Agreement
On July 25, 2011, we entered into a definitive asset purchase agreement with Murphy Oil
Corporation (Murphy Oil), pursuant to which we will acquire (the Superior Acquisition):
| Murphy Oils refinery located in Superior, Wisconsin (the Superior Refinery) and associated inventories; | ||
| the Superior Refinerys wholesale marketing business and related assets, including certain owned or leased Murphy Oil product terminals located in Superior and Rhinelander, Wisconsin, Duluth and Crookston and Proctor, Minnesota, Grand Island, Nebraska and Toole, Utah and associated inventories and logistics assets located at each of the foregoing facilities; and | ||
| Murphy Oils SPUR branded gasoline wholesale business and related assets. |
In this Quarterly Report on Form 10-Q, the Superior Refinery, the wholesale business and the
SPUR business are collectively referred to as the Acquired Business. The Superior Acquisition is
expected to close by the end of the third quarter of 2011, subject to customary closing conditions
and regulatory approvals.
The Superior Refinery produces gasoline, distillate, asphalt and specialty petroleum products
that are marketed in the Midwest region of the United States, Canada and the surrounding border
states. The Superior Refinery has crude oil throughput capacity of approximately 45,000 barrels
per day. The Superior wholesale business transports products produced at the Superior Refinery
through several Magellan pipeline terminals in Minnesota, Wisconsin, Iowa, North Dakota and South
Dakota and through its own leased and owned product terminals located in Superior and Rhinelander,
Wisconsin, Duluth, Crookston and Proctor, Minnesota, Grand Island, Nebraska and Toole, Utah. The
Superior Wholesale Business also sells gasoline wholesale to SPUR branded gas stations, which are
owned and operated by independent franchisees.
The
aggregate purchase price for the Acquired Business is $214.0 million, plus the market value
of the Acquired Business hydrocarbon inventories at closing and the reimbursement of certain
capital expenditures to be incurred at the Superior Refinery during the period from the execution
of the Purchase Agreement to the closing of the Superior Acquisition (the Interim Period). The
estimated market value of the hydrocarbon inventories of the Acquired
Business as of June 30, 2011
was approximately $260.0 million and the projected capital expenditures at the Superior Refinery to
be reimbursed by us for the Interim Period are approximately $4.0 million. The purchase price is
also subject to customary purchase price adjustments. We intend to finance the Superior
Acquisition primarily through a combination of equity and long-term debt financing and through
borrowings under our revolving credit facility. Our obligation to consummate the Superior
Acquisition is not conditioned upon the receipt of financing.
Key Performance Measures
Our sales and net income are principally affected by the price of crude oil, demand for
specialty and fuel products, prevailing crack spreads for fuel products, the price of natural gas
used as fuel in our operations and our results from derivative instrument activities.
Our primary raw materials are crude oil and other specialty feedstocks and our primary outputs
are specialty petroleum and fuel products. The prices of crude oil, specialty products and fuel
products are subject to fluctuations in response to changes in supply, demand, market uncertainties
and a variety of additional factors beyond our control. We monitor these risks and enter into
financial derivatives designed to mitigate the impact of commodity price fluctuations on our
business. The primary purpose of our commodity risk management activities is to economically hedge
our cash flow exposure to commodity price risk so that we can meet our cash
34
Table of Contents
distribution, debt service and capital expenditure requirements despite fluctuations in crude
oil and fuel products prices. We enter into derivative contracts for future periods in quantities
that do not exceed our projected purchases of crude oil and natural gas and sales of fuel products.
Please read Part I Item 3 Quantitative and Qualitative Disclosures About Market Risk Commodity
Price Risk. As of June 30, 2011, we have hedged approximately 11.4 million barrels of fuel
products through December 2013 at an average refining margin of $15.73 per barrel with average
refining margins ranging from a low of $12.16 per barrel in 2011 to a high of $23.90 per barrel in
2013. Please refer to Note 6 under Part I Item 1 Financial Statements Notes to Unaudited
Condensed Consolidated Financial Statements and Part I Item 3 Quantitative and Qualitative
Disclosures About Market Risk Existing Commodity Derivative Instruments for detailed
information regarding our derivative instruments.
Our management uses several financial and operational measurements to analyze our performance.
These measurements include the following:
| sales volumes; | ||
| production yields; and | ||
| specialty products and fuel products gross profit. |
Sales volumes. We view the volumes of specialty products and fuel products sold as an
important measure of our ability to effectively utilize our refining assets. Our ability to meet
the demands of our customers is driven by the volumes of crude oil and feedstocks that we run at
our facilities. Higher volumes improve profitability both through the spreading of fixed costs over
greater volumes and the additional gross profit achieved on the incremental volumes.
Production yields. In order to maximize our gross profit and minimize lower margin
by-products, we seek the optimal product mix for each barrel of crude oil we refine, which we refer
to as production yield.
Specialty products and fuel products gross profit. Specialty products and fuel products gross
profit are important measures of our ability to maximize the profitability of our specialty
products and fuel products segments. We define specialty products and fuel products gross profit as
sales less the cost of crude oil and other feedstocks and other production-related expenses, the
most significant portion of which includes labor, plant fuel, utilities, contract services,
maintenance, depreciation and processing materials. We use specialty products and fuel products
gross profit as indicators of our ability to manage our business during periods of crude oil and
natural gas price fluctuations, as the prices of our specialty products and fuel products generally
do not change immediately with changes in the price of crude oil and natural gas. The increase in
selling prices typically lags behind the rising costs of crude oil feedstocks for specialty
products. Other than plant fuel, production-related expenses generally remain stable across broad
ranges of throughput volumes, but can fluctuate depending on maintenance activities performed
during a specific period.
Our fuel products segment gross profit may differ from a standard U.S. Gulf Coast 2/1/1 or
3/2/1 market crack spread due to many factors, including our fuel products mix as shown in our
production table being different than the ratios used to calculate such market crack spreads, the
allocation of by-product (primarily asphalt) losses at the Shreveport refinery to the fuel products
segment, operating costs including fixed costs, derivative activity to hedge our fuel products
segment revenues and cost of crude oil reflected in gross profit and our local market pricing
differential in Shreveport, Louisiana as compared to U.S. Gulf Coast postings.
In addition to the foregoing measures, we also monitor our selling, general and administrative
expenditures, substantially all of which are incurred through our general partner.
35
Table of Contents
Results of Operations for the Three and Six Months Ended June 30, 2011 and 2010
Production Volume. The following table sets forth information about our combined operations.
Facility production volume differs from sales volume due to changes in inventory.
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||
2011 | 2010 | % Change | 2011 | 2010 | % Change | |||||||||||||||||||
(In bpd) | (In bpd) | |||||||||||||||||||||||
Total sales volume (1) |
59,648 | 52,626 | 13.3 | % | 56,619 | 52,166 | 8.5 | % | ||||||||||||||||
Total feedstock runs (2) |
61,853 | 57,169 | 8.2 | % | 58,986 | 52,774 | 11.8 | % | ||||||||||||||||
Facility production: (3) |
||||||||||||||||||||||||
Specialty products: |
||||||||||||||||||||||||
Lubricating oils |
14,141 | 13,783 | 2.6 | % | 13,961 | 12,538 | 11.3 | % | ||||||||||||||||
Solvents |
11,051 | 8,904 | 24.1 | % | 10,592 | 8,490 | 24.8 | % | ||||||||||||||||
Waxes |
1,204 | 1,152 | 4.5 | % | 1,133 | 1,081 | 4.8 | % | ||||||||||||||||
Fuels |
435 | 978 | (55.5 | )% | 533 | 1,063 | (49.9 | )% | ||||||||||||||||
Asphalt and other by-products |
8,961 | 6,075 | 47.5 | % | 8,495 | 5,921 | 43.5 | % | ||||||||||||||||
Total |
35,792 | 30,892 | 15.9 | % | 34,714 | 29,093 | 19.3 | % | ||||||||||||||||
Fuel products: |
||||||||||||||||||||||||
Gasoline |
10,266 | 8,710 | 17.9 | % | 9,619 | 8,743 | 10.0 | % | ||||||||||||||||
Diesel |
11,424 | 10,875 | 5.0 | % | 11,095 | 9,936 | 11.7 | % | ||||||||||||||||
Jet fuel |
5,429 | 5,326 | 1.9 | % | 4,303 | 5,290 | (18.7 | )% | ||||||||||||||||
By-products |
1,065 | 722 | 47.5 | % | 812 | 511 | 58.9 | % | ||||||||||||||||
Total |
28,184 | 25,633 | 10.0 | % | 25,829 | 24,480 | 5.5 | % | ||||||||||||||||
Total facility production (3) |
63,976 | 56,525 | 13.2 | % | 60,543 | 53,573 | 13.0 | % | ||||||||||||||||
(1) | Total sales volume includes sales from the production at our facilities and certain third-party facilities pursuant to supply and/or processing agreements and sales of inventories. | |
(2) | Total feedstock runs represent the barrels per day of crude oil and other feedstocks processed at our facilities and at certain third-party facilities pursuant to supply and/or processing agreements. The increase in the total feedstock runs for the three months ended June 30, 2011 compared to the same quarter in 2010 is due primarily to the decision to increase crude oil run rates at our facilities because of favorable economics of running additional barrels, the failure of an environmental operating unit at our Shreveport refinery in 2010 and a planned turnaround at our Shreveport refinery in April 2010 partially offset by the impact of the approximately three week shutdown during May and June 2011 of the ExxonMobil crude oil pipeline serving our Shreveport refinery resulting from the Mississippi River flooding occurring during this period. Additionally, the increase in feedstock runs for the for the six months ended June 30, 2011 compared to the same period in 2010 is due primarily to the operational reasons discussed above further offset by a planned turnaround at the Shreveport refinery in the first quarter of 2011. | |
(3) | Total facility production represents the barrels per day of specialty products and fuel products yielded from processing crude oil and other feedstocks at our facilities and at certain third-party facilities, pursuant to supply and/or processing agreements, including such agreements with LyondellBasell. The difference between total facility production and total feedstock runs is primarily a result of the time lag between the input of feedstock and production of finished products and volume loss. The increase in production in the three and six months ended June 30, 2011 compared to the same periods in 2010 is due primarily to higher throughput rates at our Shreveport and Cotton Valley refineries period over period as discussed above in footnote 2 of this table. |
36
Table of Contents
The following table reflects our consolidated results of operations and includes the
non-GAAP financial measures EBITDA, Adjusted EBITDA and Distributable Cash Flow. For a
reconciliation of EBITDA, Adjusted EBITDA and Distributable Cash Flow to net income (loss) and net
cash provided by (used in) operating activities, our most directly comparable financial performance
and liquidity measures calculated in accordance with GAAP, please read Non-GAAP Financial
Measures.
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(In thousands) | (In thousands) | |||||||||||||||
Sales |
$ | 733,770 | $ | 514,652 | $ | 1,339,010 | $ | 999,269 | ||||||||
Cost of sales |
683,205 | 465,033 | 1,241,581 | 917,974 | ||||||||||||
Gross profit |
50,565 | 49,619 | 97,429 | 81,295 | ||||||||||||
Operating costs and expenses: |
||||||||||||||||
Selling, general and administrative |
10,467 | 8,321 | 20,995 | 15,491 | ||||||||||||
Transportation |
22,691 | 19,956 | 45,766 | 40,202 | ||||||||||||
Taxes other than income taxes |
1,203 | 1,098 | 2,563 | 2,123 | ||||||||||||
Insurance recoveries |
(7,910 | ) | | (8,698 | ) | | ||||||||||
Other |
703 | 480 | 1,238 | 808 | ||||||||||||
Operating income |
23,411 | 19,764 | 35,565 | 22,671 | ||||||||||||
Other income (expense): |
||||||||||||||||
Interest expense |
(10,544 | ) | (7,277 | ) | (18,025 | ) | (14,711 | ) | ||||||||
Debt extinguishment costs |
(15,130 | ) | | (15,130 | ) | | ||||||||||
Realized loss on derivative instruments |
(2,370 | ) | (5,297 | ) | (1,984 | ) | (5,858 | ) | ||||||||
Unrealized loss on derivative instruments |
(3,124 | ) | (8,008 | ) | (3,541 | ) | (15,766 | ) | ||||||||
Other |
274 | 9 | 103 | (50 | ) | |||||||||||
Total other expense |
(30,894 | ) | (20,573 | ) | (38,577 | ) | (36,385 | ) | ||||||||
Net loss before income taxes |
(7,483 | ) | (809 | ) | (3,012 | ) | (13,714 | ) | ||||||||
Income tax expense |
168 | 98 | 438 | 260 | ||||||||||||
Net loss |
$ | (7,651 | ) | $ | (907 | ) | $ | (3,450 | ) | $ | (13,974 | ) | ||||
Adjusted EBITDA |
$ | 40,841 | $ | 32,136 | $ | 75,494 | $ | 52,259 | ||||||||
Distributable Cash Flow |
$ | 25,367 | $ | 7,219 | $ | 43,589 | $ | 14,304 | ||||||||
Non-GAAP Financial Measures
We include in this Quarterly Report the non-GAAP financial measures EBITDA, Adjusted EBITDA
and Distributable Cash Flow, and provide reconciliations of EBITDA, Adjusted EBITDA and
Distributable Cash Flow to net income (loss) and net cash provided by (used in) operating
activities, our most directly comparable financial performance and liquidity measures calculated
and presented in accordance with GAAP.
EBITDA, Adjusted EBITDA and Distributable Cash Flow are used as supplemental financial
measures by our management and by external users of our financial statements such as investors,
commercial banks, research analysts and others, to assess:
| the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; | ||
| the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; | ||
| our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure; and | ||
| the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities. |
We believe that these non-GAAP measures are useful to analysts and investors as they exclude
transactions not related to our core cash operating activities and provide metrics to analyze our
ability to pay distributions. We believe that excluding these transactions allows investors to
meaningfully trend and analyze the performance of our core cash operations.
We define EBITDA for any period as net income plus interest expense (including debt issuance
and extinguishment costs), taxes and depreciation and amortization. We define Adjusted EBITDA for
any period as: (1) net income plus (2)(a) interest expense; (b) income taxes; (c) depreciation and
amortization; (d) unrealized losses from mark to market accounting for hedging activities; (e)
realized gains under derivative instruments excluded from the determination of net income; (f)
non-cash equity based compensation expense and other non-cash items (excluding items such as
accruals of cash expenses in a future period or amortization of a prepaid cash expense) that were
deducted in computing net income; (g) debt refinancing fees, premiums and penalties and (h) all
37
Table of Contents
extraordinary, unusual or non-recurring items of gain or loss, or revenue or expense; minus (3)(a)
unrealized gains from mark to
market accounting for hedging activities; (b) realized losses under derivative instruments
excluded from the determination of net income and (c) other non-recurring expenses and unrealized
items that reduced net income for a prior period, but represent a cash item in the current period.
We define Distributable Cash Flow for any period as Adjusted EBITDA less replacement capital
expenditures, turnaround costs, cash interest expense (consolidated interest expense less non-cash
interest expense) and income tax expense. Distributable Cash Flow is used by us and our investors
to analyze our ability to pay distributions.
The definitions of Adjusted EBITDA and Distributable Cash that are presented in this Quarterly
Report have been updated to reflect the calculation of Consolidated Cash Flow contained in the
indenture governing our 2019 Notes. We are required to report Consolidated Cash Flow to the holders
of our 2019 Notes and Adjusted EBITDA to the lenders under our revolving credit facility, and these
measures are used by them to determine our compliance with certain covenants governing those debt
instruments. Adjusted EBITDA and Distributable Cash Flow that are presented in this Quarterly
Report for prior periods have been updated to reflect the use of the new calculations. Please refer
to Liquidity and Capital Resources Debt and Credit Facilities within this item for additional
details regarding the covenants governing our debt instruments.
EBITDA, Adjusted EBITDA and Distributable Cash Flow should not be considered alternatives to
net income, operating income, net cash provided by operating activities or any other measure of
financial performance presented in accordance with GAAP. In evaluating our performance as measured
by EBITDA, Adjusted EBITDA and Distributable Cash Flow, management recognizes and considers the
limitations of these measurements. EBITDA, Adjusted EBITDA and Distributable Cash Flow do not
reflect our obligations for the payment of income taxes, interest expense or other obligations such
as capital expenditures. Accordingly, EBITDA, Adjusted EBITDA and Distributable Cash Flow are only
three of the measurements that management utilizes. Moreover, our EBITDA, Adjusted EBITDA and
Distributable Cash Flow may not be comparable to similarly titled measures of another company
because all companies may not calculate EBITDA, Adjusted EBITDA and Distributable Cash Flow in the
same manner. The following table presents a reconciliation of both net income (loss) to EBITDA,
Adjusted EBITDA and Distributable Cash Flow, and Distributable Cash Flow, Adjusted EBITDA and
EBITDA to net cash provided by (used in) operating activities, our most directly comparable GAAP
financial performance and liquidity measures, for each of the periods indicated.
38
Table of Contents
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(In thousands) | (In thousands) | |||||||||||||||
Reconciliation of Net Loss to EBITDA and Adjusted EBITDA
and Distributable Cash Flow: |
||||||||||||||||
Net loss |
$ | (7,651 | ) | $ | (907 | ) | $ | (3,450 | ) | $ | (13,974 | ) | ||||
Add: |
||||||||||||||||
Interest expense |
10,544 | 7,277 | 18,025 | 14,711 | ||||||||||||
Debt extinguishment costs |
15,130 | | 15,130 | | ||||||||||||
Depreciation and amortization |
14,532 | 15,098 | 28,964 | 29,502 | ||||||||||||
Income tax expense |
168 | 98 | 438 | 260 | ||||||||||||
EBITDA |
$ | 32,723 | $ | 21,566 | $ | 59,107 | $ | 30,499 | ||||||||
Add: |
||||||||||||||||
Unrealized loss on derivatives |
$ | 3,124 | $ | 8,008 | $ | 3,541 | $ | 15,766 | ||||||||
Realized gain on derivatives, not included in net loss |
1,394 | 372 | 5,137 | 1,442 | ||||||||||||
Amortization of turnaround costs |
2,533 | 1,960 | 5,746 | 4,100 | ||||||||||||
Non-cash equity based compensation |
1,067 | 230 | 1,963 | 452 | ||||||||||||
Adjusted EBITDA |
$ | 40,841 | $ | 32,136 | $ | 75,494 | $ | 52,259 | ||||||||
Less: |
||||||||||||||||
Replacement capital expenditures (1) |
3,505 | 10,893 | 7,596 | 16,342 | ||||||||||||
Cash interest expense (2) |
9,887 | 6,318 | 16,370 | 12,805 | ||||||||||||
Turnaround costs |
1,914 | 7,608 | 7,501 | 8,548 | ||||||||||||
Income tax expense |
168 | 98 | 438 | 260 | ||||||||||||
Distributable Cash Flow |
$ | 25,367 | $ | 7,219 | $ | 43,589 | $ | 14,304 | ||||||||
(1) | Replacement capital expenditures are defined as those capital expenditures which do not increase operating capacity or reduce operating costs and exclude turnaround costs. | |
(2) | Represents consolidated interest expense less non-cash interest expense. |
39
Table of Contents
Six Months Ended | ||||||||
June 30, | ||||||||
2011 | 2010 | |||||||
(In thousands) | ||||||||
Reconciliation of Distributable Cash Flow, Adjusted EBITDA
and EBITDA to net cash provided by (used in) operating activities: |
||||||||
Distributable Cash Flow |
$ | 43,589 | $ | 14,304 | ||||
Add: |
||||||||
Replacement capital expenditures (1) |
7,596 | 16,342 | ||||||
Turnaround costs |
7,501 | 8,548 | ||||||
Cash interest expense (2) |
16,370 | 12,805 | ||||||
Income tax expense |
438 | 260 | ||||||
Adjusted EBITDA |
$ | 75,494 | $ | 52,259 | ||||
Less: |
||||||||
Unrealized loss on derivative instruments |
3,541 | 15,766 | ||||||
Realized gains on derivatives, not included in net loss |
5,137 | 1,442 | ||||||
Non-cash equity based compensation |
1,963 | 452 | ||||||
Amortization of turnaround costs |
5,746 | 4,100 | ||||||
EBITDA |
$ | 59,107 | $ | 30,499 | ||||
Add: |
||||||||
Unrealized loss on derivative instruments |
3,541 | 15,766 | ||||||
Cash interest expense (2) |
(16,370 | ) | (12,805 | ) | ||||
Non-cash equity based compensation |
1,963 | 452 | ||||||
Amortization of turnaround costs |
5,746 | 4,100 | ||||||
Income tax expense |
(438 | ) | (260 | ) | ||||
Provision for doubtful accounts |
255 | (91 | ) | |||||
Debt extinguishment costs |
(729 | ) | | |||||
Changes in assets and liabilities: |
||||||||
Accounts receivable |
(48,479 | ) | (27,323 | ) | ||||
Inventory |
(111,555 | ) | (9,583 | ) | ||||
Other current assets |
(14,482 | ) | 2,265 | |||||
Turnaround costs |
(7,501 | ) | (8,548 | ) | ||||
Derivative activity |
5,699 | 1,443 | ||||||
Accounts payable |
62,834 | 48,584 | ||||||
Other liabilities |
(7,904 | ) | (2,580 | ) | ||||
Other, including changes in noncurrent assets and liabilities |
(2,245 | ) | 648 | |||||
Net cash provided by (used in) operating activities |
$ | (70,558 | ) | $ | 42,567 | |||
(1) | Replacement capital expenditures are defined as those capital expenditures which do not increase operating capacity or reduce operating costs and exclude turnaround costs. | |
(2) | Represents consolidated interest expense less non-cash interest expense. |
40
Table of Contents
Changes in Results of Operations for the Three Months Ended June 30, 2011 and 2010
Sales. Sales increased $219.1 million, or 42.6%, to $733.8 million in the three months ended
June 30, 2011 from $514.7 million in the same period in 2010. Sales for each of our principal
product categories in these periods were as follows:
Three Months Ended June 30, | ||||||||||||
2011 | 2010 | % Change | ||||||||||
(Dollars in thousands, except per barrel data) | ||||||||||||
Sales by segment: |
||||||||||||
Specialty products: |
||||||||||||
Lubricating oils |
$ | 246,448 | $ | 176,354 | 39.7 | % | ||||||
Solvents |
135,642 | 95,777 | 41.6 | % | ||||||||
Waxes |
33,874 | 28,362 | 19.4 | % | ||||||||
Fuels (1) |
592 | 2,232 | (73.5 | )% | ||||||||
Asphalt and by-products (2) |
49,858 | 26,698 | 86.7 | % | ||||||||
Total specialty products |
$ | 466,414 | $ | 329,423 | 41.6 | % | ||||||
Total specialty products sales volume (in barrels) |
2,798,000 | 2,481,000 | 12.8 | % | ||||||||
Average specialty products sales price per barrel |
$ | 166.70 | $ | 132.78 | 25.5 | % | ||||||
Fuel products: |
||||||||||||
Gasoline |
$ | 127,452 | $ | 76,287 | 67.1 | % | ||||||
Diesel |
91,611 | 77,396 | 18.4 | % | ||||||||
Jet fuel |
40,686 | 27,816 | 46.3 | % | ||||||||
By-products (3) |
7,607 | 3,730 | 103.9 | % | ||||||||
Total fuel products |
$ | 267,356 | $ | 185,229 | 44.3 | % | ||||||
Total fuel products sales volume (in barrels) |
2,630,000 | 2,308,000 | 14.0 | % | ||||||||
Average fuel products sales price per barrel (4) |
$ | 101.66 | $ | 80.26 | 26.7 | % | ||||||
Total sales |
$ | 733,770 | $ | 514,652 | 42.6 | % | ||||||
Total sales volume (in barrels) |
5,428,000 | 4,789,000 | 13.3 | % | ||||||||
(1) | Represents fuels produced in connection with the production of specialty products at the Princeton, Cotton Valley and Karns City refineries. | |
(2) | Represents asphalt and other by-products produced in connection with the production of specialty products at the Princeton, Cotton Valley and Shreveport refineries. | |
(3) | Represents by-products produced in connection with the production of fuels at the Shreveport refinery. | |
(4) | Average fuel products sales price per barrel includes impact of hedging contracts. |
Specialty products segment sales for the three months ended June 30, 2011 increased $137.0
million, or 41.6%, as a result of an increase in the average selling price per barrel of $33.92, or
25.5%, and a 12.8% increase in sales volume as compared to the same period in 2010. Lubricating
oils, solvents and waxes experienced price increases, driven by improving overall demand and a
37.6% increase in the average cost of crude oil per barrel for the 2011 period as compared to the
same period in 2010. The increased volume is due primarily to improving overall specialty products
demand as a result of improved economic conditions and higher refinery run rates over the prior
period.
Fuel products segment sales for the three months ended June 30, 2011 increased $82.1 million,
or 44.3%, due primarily to an increase in the average selling price per barrel (excluding the
impact of hedging activities) of $39.91, or 45.8% and a 14.0% increase in sales volume, driven by
market conditions and higher refinery run rates over the prior period. The increase in the average
selling price per barrel of 45.8% compares to a 39.0% increase in the average price of crude oil
per barrel. The average selling price per barrel increased for all fuel products, with jet fuel and
diesel selling prices experiencing significant increases driven by improved market pricing. The
increase in sales volume is due primarily to higher refinery run rates over the prior period.
Refinery run rates were below expectations due to an approximate three week shutdown during May and
June 2011 of an ExxonMobil crude oil pipeline serving our Shreveport refinery due to the impacts of
the Mississippi River flooding occurring during this period. Also adversely impacting fuel product
sales was a $50.9 million increase in derivative losses on our fuel products cash flow hedges
recorded in sales. Please see Gross Profit below for discussion of the net impact of our crude
oil and fuel products derivative instruments designated as hedges.
41
Table of Contents
Gross Profit. Gross profit increased $0.9 million, or 1.9%, to $50.6 million in the three
months ended June 30, 2011 from $49.6 million in the same period in 2010. Gross profit for our
specialty products and fuel products segments was as follows:
Three Months Ended June 30, | ||||||||||||
2011 | 2010 | % Change | ||||||||||
(Dollars in thousands, except per barrel data) | ||||||||||||
Gross profit by segment: |
||||||||||||
Specialty products |
$ | 58,308 | $ | 46,400 | 25.7 | % | ||||||
Percentage of sales |
12.5 | % | 14.1 | % | ||||||||
Specialty products gross profit per barrel |
$ | 20.84 | $ | 18.70 | 11.4 | % | ||||||
Fuel products |
$ | (7,743 | ) | $ | 3,219 | (340.5 | )% | |||||
Percentage of sales |
(2.9 | )% | 1.7 | % | ||||||||
Fuel products gross profit per barrel |
$ | (2.94 | ) | $ | 1.39 | (311.5 | )% | |||||
Total gross profit |
$ | 50,565 | $ | 49,619 | 1.9 | % | ||||||
Percentage of sales |
6.9 | % | 9.6 | % |
The increase in specialty products segment gross profit of $11.9 million quarter over quarter
was due primarily to a 12.8% increase in sales volume and a 25.5% increase in the average selling
price per barrel as discussed above, partially offset by a 37.6% increase in the average cost of
crude oil per barrel and higher operating costs, primarily repairs and maintenance.
The decrease in fuel products segment gross profit of $11.0 million quarter over quarter was
due primarily to increased realized losses on derivatives of $27.1 million in our fuel products
hedging program, a 39.0% increase in the cost of crude oil per barrel, and increased production of
by-products partially offset by a 14.0% increase in sales volume and a 45.8% increase in selling
prices per barrel, excluding the impact of realized hedging losses. Our fuels hedging program and
refinery run rates being below expectations resulted in our diesel and jet fuel sales volumes being
approximately 100% hedged at approximately $12.00 per barrel during the second quarter of 2011. This
prevented us from fully realizing the benefit of increased market prices for fuels. Additionally,
by-product production increased in the 2011 period as compared to the 2010 period due
primarily to an increase in the mix of sour crude oil run rates at the Shreveport refinery.
Selling, general and administrative. Selling, general and administrative expenses increased
$2.1 million or 25.8% to $10.5 million in the three months ended June 30, 2011 from $8.3 million in
the same period in 2010. This increase is due primarily to increased accrued incentive compensation
costs of $1.6 million in 2011 compared to 2010.
Transportation. Transportation expenses increased $2.7 million, or 13.7%, to $22.7 million in
the three months ended June 30, 2011 from $20.0 million in the same period in 2010. This increase
is due primarily to increased sales volumes of lubricating oils, solvents and waxes, as well as
higher freight costs.
Insurance recoveries. Insurance recoveries were $7.9 million for the three months ended June
30, 2011. The gain was related to a claim settled in the second quarter of 2011 with insurers
related to the failure of an environmental operating unit at the Shreveport refinery in the first
quarter of 2010.
Interest expense. Interest expense increased $3.3 million, or 44.9%, to $10.5 million in the
three months ended June 30, 2011 from $7.3 million in the three months ended June 30, 2010, due
primarily to higher interest rates associated with the new 2019 Notes as compared to our term loan
that was repaid in full and extinguished in connection with the issuance of the 2019 Notes.
Debt extinguishment costs. Debt extinguishment costs were $15.1 million during the three
months ended June 30, 2011. The debt extinguishment costs were related to the extinguishment of
the term loan with proceeds from the issuance of the 2019 Notes.
Realized loss on derivative instruments. Realized loss on derivative instruments decreased
$2.9 million to $2.4 million in the three months ended June 30, 2011 from $5.3 million for the
three months ended June 30, 2010. The change was due primarily to realized losses of approximately
$3.9 million in our specialty products segment related to crude oil derivatives not designated as
hedges, partially offset by realized crack spread derivative gains of $1.3 million that were both
incurred during the three months ended June 30, 2010, with minimal comparable activity during the
three months ended June 30, 2011.
Unrealized loss on derivative instruments. Unrealized loss on derivative instruments
decreased $4.9 million, to $3.1 million in the three months ended June 30, 2011 from $8.0 million
in the three months ended June 30,
2010. The change was due primarily to decreases in unrealized losses on crack spread
derivatives that were executed to economically lock in gains on a portion of our fuel
42
Table of Contents
products segment derivative hedging activity related to 2010, and decreases in unrealized
losses on derivatives used to economically hedge our specialty products segment crude oil purchases and increased
gain ineffectiveness. Partially offsetting these improvements were the losses on the $1.4 million in interest
rate swap contracts that were discontinued as cash flow hedges of the future payment of interest on our term loan
that was extinguished with the issuance of the 2019 Notes.
Changes in Results of Operations for the Six Months Ended June 30, 2011 and 2010
Sales. Sales increased $339.7 million, or 34.0%, to $1,339.0 million in the six months ended
June 30, 2011 from $999.3 million in the same period in 2010. Sales for each of our principal
product categories in these periods were as follows:
Six Months Ended June 30, | ||||||||||||
2011 | 2010 | % Change | ||||||||||
(Dollars in thousands, except per barrel data) | ||||||||||||
Sales by segment: |
||||||||||||
Specialty products: |
||||||||||||
Lubricating oils |
$ | 455,499 | $ | 340,402 | 33.8 | % | ||||||
Solvents |
253,978 | 183,631 | 38.3 | % | ||||||||
Waxes |
68,181 | 54,608 | 24.9 | % | ||||||||
Fuels (1) |
1,423 | 3,971 | (64.2 | )% | ||||||||
Asphalt and by-products (2) |
84,435 | 52,287 | 61.5 | % | ||||||||
Total specialty products |
$ | 863,516 | $ | 634,899 | 36.0 | % | ||||||
Total specialty products sales volume (in barrels) |
5,446,000 | 4,936,000 | 10.3 | % | ||||||||
Average specialty products sales price per barrel |
$ | 158.56 | $ | 128.63 | 23.3 | % | ||||||
Fuel products: |
||||||||||||
Gasoline |
$ | 223,233 | $ | 152,170 | 46.7 | % | ||||||
Diesel |
173,764 | 141,626 | 22.7 | % | ||||||||
Jet fuel |
67,460 | 65,380 | 3.2 | % | ||||||||
By-products (3) |
11,037 | 5,194 | 112.5 | % | ||||||||
Total fuel products |
$ | 475,494 | $ | 364,370 | 30.5 | % | ||||||
Total fuel products sales volume (in barrels) |
4,802,000 | 4,506,000 | 6.6 | % | ||||||||
Average fuel products sales price per barrel (4) |
$ | 99.02 | $ | 80.86 | 22.5 | % | ||||||
Total sales |
$ | 1,339,010 | $ | 999,269 | 34.0 | % | ||||||
Total sales volume (in barrels) |
10,248,000 | 9,442,000 | 8.5 | % | ||||||||
(1) | Represents fuels produced in connection with the production of specialty products at the Princeton, Cotton Valley and Karns City refineries. | |
(2) | Represents asphalt and other by-products produced in connection with the production of specialty products at the Princeton, Cotton Valley and Shreveport refineries. | |
(3) | Represents by-products produced in connection with the production of fuels at the Shreveport refinery. | |
(4) | Average fuel products sales price per barrel includes impact of hedging contracts. |
Specialty products segment sales for the six months ended June 30, 2011 increased $228.6
million, or 36.0%, as a result of an increase in the average selling price per barrel of $29.93, or
23.3%, and a 10.3% increase in sales volume as compared to the same period in 2010. Lubricating
oils, solvents and waxes experienced price increases, driven by improving overall demand and a
30.6% increase in the average cost of crude oil per barrel for the 2011 period as compared to the
same period in 2010. The increased volume is due primarily to improving overall specialty products
demand as a result of improved economic conditions and higher refinery run rates over the prior
period.
Fuel products segment sales for the six months ended June 30, 2011 increased $111.1 million,
or 30.5%, due primarily to an increase in the average selling price per barrel (excluding the
impact of hedging activities) of $34.00, or 39.2%, driven by market conditions compared to a 31.6%
increase in the average price of crude oil per barrel and a 6.6% increase in sales volume. The
average selling price per barrel increased for all fuel products, with gasoline and diesel selling
prices experiencing significant increases driven by improved market pricing. Adversely impacting
fuel products sales was a $77.8 million increase in derivative losses on our fuel products cash
flow hedges recorded in sales. Please see Gross Profit below for discussion of the net impact of
our crude oil and fuel products derivative instruments designated as hedges.
43
Table of Contents
Gross Profit. Gross profit increased $16.1 million, or 19.8%, to $97.4 million in the six
months ended June 30, 2011 from $81.3 million in the same period in 2010. Gross profit for our
specialty products and fuel products segments was as follows:
Six Months Ended June 30, | ||||||||||||
2011 | 2010 | % Change | ||||||||||
(Dollars in thousands, except per barrel data) | ||||||||||||
Gross profit by segment: |
||||||||||||
Specialty products |
$ | 106,199 | $ | 69,826 | 52.1 | % | ||||||
Percentage of sales |
12.3 | % | 11.0 | % | ||||||||
Specialty products gross profit per barrel |
$ | 19.50 | $ | 14.15 | 37.8 | % | ||||||
Fuel products |
$ | (8,770 | ) | $ | 11,469 | (176.5 | )% | |||||
Percentage of sales |
(1.8 | )% | 3.1 | % | ||||||||
Fuel products gross profit per barrel |
$ | (1.83 | ) | $ | 2.55 | (171.8 | )% | |||||
Total gross profit |
$ | 97,429 | $ | 81,295 | 19.8 | % | ||||||
Percentage of sales |
7.3 | % | 8.1 | % |
The increase in specialty products segment gross profit of $36.4 million for the six months
ended June 30, 2011 compared to the same period in 2010 was due primarily to a 10.3% increase in
sales volumes and a 23.3% increase in the average selling price per barrel as discussed above,
partially offset by a 30.6% increase in the average cost of crude oil per barrel and higher
operating costs, primarily repair and maintenance.
The decrease in fuel products segment gross profit of $20.2 million for the six months ended
June 30, 2011 compared to the same period in 2010 was due primarily to increased realized losses on
derivatives of $52.4 million in our fuel products hedging program, a 31.6% increase in the cost of
crude oil per barrel, and increased production of by-products, partially offset by a 6.6% increase
in sales volume and a 39.2% increase in selling prices per barrel, excluding the impact of realized
hedging losses. Our fuel products hedging program and refinery run rates being below expectations
resulted in our diesel and jet fuel sales volumes being approximately 100% hedged during the second
quarter of 2011 at approximately $12.00 per barrel. This prevented us from realizing the benefit of
increased market pricing for these products. Additionally, by-product production increased
in the 2011 period as compared to the 2010 period due primarily to an increase in the mix of sour
crude oil run rates at the Shreveport refinery.
Selling, general and administrative. Selling, general and administrative expenses increased
$5.5 million, or 35.5%, to $21.0 million in the six months ended June 30, 2011 from $15.5 million
in 2010. This increase is due primarily to increased accrued incentive compensation costs of $3.0
million in 2011 compared to 2010, as well as increased overall salaries and wages, bad debt expense
and advertising.
Transportation. Transportation expenses increased $5.6 million, or 13.8%, to $45.8 million in
the six months ended June 30, 2011 from $40.2 million in the same period in 2010. This increase is
due primarily to increased sales volumes of lubricating oils, solvents and waxes, as well as higher
freight costs.
Insurance recoveries. Insurance recoveries were $8.7 million for the six months ended June
30, 2011. The gain was related to a claim settled in the second quarter of 2011 with insurers
related to the failure of an environmental operating unit at the Shreveport refinery in the first
quarter of 2010.
Interest expense. Interest expense increased $3.3 million or 22.5%, to $18.0 million in the
six months ended June 30, 2011 from $14.7 million in the six months ended June 30, 2010, due
primarily to higher interest rates associated with the new 2019 Notes as compared to our term loan
that was repaid in full and extinguished in connection with the issuance of the 2019 Notes.
Debt extinguishment costs. Debt extinguishment costs were $15.1 million during the six months
ended June 30, 2011. The debt extinguishment costs were related to the extinguishment of the term
loan with proceeds from the issuance of the 2019 Notes.
Realized loss on derivative instruments. Realized loss on derivative instruments decreased
$3.9 million to $2.0 million in the six months ended June 30, 2011 from $5.9 million for the six
months ended June 30, 2010. This change was due primarily to increased realized gains of
approximately $0.9 million in our specialty products segment related to crude oil derivatives not
designated as hedges for the six months ended June 30, 2011, while experiencing losses on similar
specialty products segment derivatives of $4.6
44
Table of Contents
million for the same period in 2010. Partially
offsetting these decreased losses were realized crack spread derivative gains of $2.3 million
realized in the prior period, with minimal comparable activity during the six months ended June 30,
2011.
Unrealized loss on derivative instruments. Unrealized loss on derivative instruments decreased
$12.2 million, to $3.5 million in the
six months ended June 30, 2011 from $15.8 million in the six months ended June 30, 2010. The
decreased loss is due primarily to an increase in gain ineffectiveness during the quarter ended
June 30, 2011 with significant loss ineffectiveness in the prior period. Partially offsetting this
improvement were the losses on the $1.4 million in interest rate swap contracts that were
discontinued as cash flow hedges of the future payment of interest on our term loan that was
extinguished with the issuance of the 2019 Notes.
Liquidity and Capital Resources
The following should be read in conjunction with Managements Discussion and Analysis of
Financial Condition and Results of Operations Liquidity and Capital Resources included under
Part I Item 7 in our 2010 Annual Report. There have been no material changes in that information
other than as discussed below. Also, see Note 5 under Part I Item 1 Financial Statements Notes
to Unaudited Condensed Consolidated Financial Statements for additional discussion related to
long-term debt.
Our principal sources of cash have historically included cash flow from operations, proceeds
from public equity offerings, proceeds from notes offerings and bank borrowings. Principal uses of
cash have included capital expenditures, acquisitions, distributions to our unitholders and general
partner and debt service. We expect that our principal uses of cash in the future will be for
distributions to our limited partners and general partner, debt service, replacement and
environmental capital expenditures and capital expenditures related to internal growth projects and
acquisitions from third parties or affiliates. We expect to fund future capital expenditures with
current cash flow from operations and borrowings under our revolving credit facility. Future
internal growth projects or acquisitions may require expenditures in excess of our then-current
cash flow from operations and borrowings under our existing revolving credit facility and may
require us to issue debt or equity securities in public or private offerings or incur additional
borrowings under bank credit facilities to meet those costs.
As discussed above, we intend to finance the Superior Acquisition primarily through a
combination of equity and long-term debt financing and through borrowings under our revolving
credit facility. Please read Managements Discussion and Analysis of Financial Condition and
Results of Operations Superior Refinery Purchase Agreement above for additional information.
Cash Flows
We believe that we have sufficient liquid assets, cash flow from operations and borrowing
capacity to meet our financial commitments, debt service obligations and anticipated capital
expenditures. However, we are subject to business and operational risks that could materially
adversely affect our cash flows. A material decrease in our cash flow from operations including a
significant, sudden decrease in crude oil prices would likely produce a corollary material adverse
effect on our borrowing capacity under our revolving credit facility and potentially our ability to
comply with the covenants under our credit facilities. A significant, sudden increase in crude oil
prices, if sustained, would likely result in increased working capital requirements which would be
funded by borrowings under our revolving credit facility.
The following table summarizes our primary sources and uses of cash in each of the periods
presented:
Six Months Ended | ||||||||
June 30, | ||||||||
2011 | 2010 | |||||||
(In thousands) | ||||||||
Net cash provided by (used in) operating activities |
$ | (70,558 | ) | $ | 42,567 | |||
Net cash used in investing activities |
$ | (18,563 | ) | $ | (16,896 | ) | ||
Net cash provided by (used in) financing activities |
$ | 89,139 | $ | (25,653 | ) |
Operating Activities. Operating activities used cash of $70.6 million during the six months
ended June 30, 2011 compared to cash provided of $42.6 million during the same period in 2010. The
change was due primarily to increases in working capital requirements of $122.0 million, due
primarily to the increased crude oil inventory levels as a result of terminating certain
just-in-time inventory supply arrangements with a related party, Legacy, effective May 31, 2011,
increased working capital requirements resulting from increased run rates at our Shreveport
facility and higher commodity prices in general, partially offset by insurance recoveries related to
a settled claim with insurers resulting from the failure of an environmental operating unit at the
Shreveport refinery in the first quarter of 2010.
Investing Activities. Cash used in investing activities increased to $18.6 million during the
six months ended June 30, 2011 compared to $16.9 million during the six months ended June 30, 2010.
The increase is due primarily to increased capital expenditures for capital improvements, which
were partially offset by insurance recoveries of $1.9 million.
45
Table of Contents
Financing Activities. Financing activities provided cash of $89.1 million for the six months
ended June 30, 2011 compared to cash used of $25.7 million during the six months ended June 30,
2010. The increase is due primarily to the net proceeds from the public
equity offering of $92.3 million during the first quarter of 2011 and net proceeds from the
2019 Notes offering of $389.0 million in the second quarter of 2011, partially offset by debt
issuance costs, the repayment of the senior secured first lien term loan facility and quarterly
distributions to our unitholders.
On April 8, 2011, we declared a quarterly cash distribution of $0.475 per unit on all
outstanding units, or approximately $19.3 million in the aggregate, for the quarter ended March 31,
2011. The distribution was paid on May 13, 2011 to unitholders of record as of the close of
business on May 3, 2011. This quarterly distribution of $0.475 per unit equates to $1.90 per unit,
or approximately $77.2 million in the aggregate on an annualized basis.
On July 22, 2011, we declared a quarterly cash distribution of $0.495 per unit on all
outstanding units, or approximately $20.1 million in aggregate, for the quarter ended June 30,
2011. The distribution will be paid on August 12, 2011 to unitholders of record as of the close of
business on August 2, 2011. This quarterly distribution of $0.495 per unit equates to $1.98 per
unit, or approximately $80.5 million in the aggregate on an annualized basis.
Capital Expenditures
Our capital expenditure requirements consist of capital improvement expenditures, replacement
capital expenditures and environmental capital expenditures. Capital improvement expenditures
include expenditures to acquire assets to grow our business, to expand existing facilities, such as
projects that increase operating capacity, or to reduce operating costs. Replacement capital
expenditures replace worn out or obsolete equipment or parts. Environmental capital expenditures
include asset additions to meet or exceed environmental and operating regulations.
The following table sets forth our capital improvement expenditures, replacement capital
expenditures and environmental capital expenditures in each of the periods shown.
Six Months Ended June 30, | ||||||||
2011 | 2010 | |||||||
(In thousands) | ||||||||
Capital improvement expenditures |
$ | 13,039 | $ | 675 | ||||
Replacement capital expenditures |
5,873 | 8,801 | ||||||
Environmental capital expenditures |
1,723 | 7,541 | ||||||
Total |
$ | 20,635 | $ | 17,017 | ||||
We anticipate that future capital expenditure requirements will be provided primarily through
cash from operations and available borrowings under our revolving credit facility. We estimate our
replacement and environmental capital expenditures will be approximately $6.0 million per quarter
for the remainder of 2011, with total replacement and environmental capital expenditures below 2010
levels. These estimated amounts for 2011 include a portion of the $11.0 million to $15.0 million in
environmental projects to be spent over the next five years as required by our settlement with the
LDEQ under the Small Refinery and Single Site Refining Initiative. Please read Note 4 of Part I
Item 1 Financial Statements Commitments and Contingencies Environmental for additional
information. Our capital improvement expenditures have increased due to various minor capital improvement
projects to reduce energy costs, improve finished product quality and improve finished product
yields. We do not expect significant capital improvement expenditures for the remainder of 2011.
Debt and Credit Facilities
As of June 30, 2011, our debt and credit facilities consisted of:
| a $550.0 million senior secured revolving credit facility, subject to borrowing base restrictions, with a letter of credit sublimit equal to the greater of (i) $400.0 million and (ii) 80% of revolver commitments then in effect; and | ||
| $400.0 million of 9 3/8% senior notes due 2019. |
46
Table of Contents
Amended and Restated Senior Secured Revolving Credit Facility
On June 24, 2011, we entered into an amended and restated senior secured revolving
credit facility, which increased the maximum availability from $375.0 million to $550.0 million,
subject to borrowing base limitations, and includes a $300.0 million
incremental uncommitted expansion feature. The revolving credit facility, which matures in June 2016, has a first priority lien on our cash, accounts receivable, inventory and certain other personal property .
The revolving credit facility contains various covenants that limit, among other things, the
Companys ability to: incur indebtedness; grant liens; dispose of certain assets; make certain
acquisitions and investments; redeem or prepay other debt or make other restricted payments such as
distributions to unitholders; enter into transactions with affiliates; and enter into a merger,
consolidation or sale of assets. The revolving credit facility generally permits us to make cash distributions to our
unitholders as long as immediately after giving effect to such a cash distribution we have
availability under the revolving credit facility at least equal to the greater of (i) 15% of the
lesser of (a) the Borrowing Base (as defined in the revolving credit facility) without giving
effect to the LC Reserve (as defined in the revolving credit facility) and (b) the revolving credit
facility commitments then in effect and (ii) $45.0 million. Further, the revolving credit facility contains one springing
financial covenant which provides that only if the Companys availability under the revolving
credit facility falls below the greater of (i) 12.5% of the lesser of (a) the Borrowing Base (as
defined in the credit agreement) (without giving effect to the LC Reserve (as defined in the credit
agreement)) and (b) the credit agreement commitments then in effect and (ii) $30.0 million, then
the Company will be required to maintain as of the end of each fiscal quarter a Fixed Charge
Coverage Ratio (as defined in the Credit Agreement) of at least 1.0 to 1.0.
Borrowings under the revolving credit facility are limited to a borrowing base that is
determined based on advance rates of percentages of eligible accounts receivable and inventory (as
defined by the revolving credit facility agreement). As such, the borrowing base can fluctuate
based on changes in selling prices of our products and our current material costs, primarily the
cost of crude oil. On
June 30, 2011, we had availability on our revolving credit facility of $194.7 million, based upon a
$402.2 million borrowing base, $179.5 million in outstanding standby letters of credit and
outstanding borrowings of $28.1 million. Our borrowing base at June 30, 2011 was $402.2 million. The borrowing base
cannot exceed the revolving credit facility commitments then in effect. The lender group under our
revolving credit facility is comprised of a syndicate of eleven lenders with total commitments of
$550.0 million.
The revolving credit facility, which is our primary source of liquidity for cash needs in
excess of cash generated from operations, matures in June 2016 and currently bears interest at
prime plus a basis points margin or LIBOR plus a basis points margin, at our option. As of June 30,
2011, this margin was 125 basis points for prime and 250 basis points for LIBOR; however, the
margin fluctuates quarterly based on our average availability for additional borrowings under the
revolving credit facility in the preceding calendar quarter. Letters of credit issued under the
revolving credit facility accrue fees at the margin applicable to LIBOR loans. Basis points margin
is as follows:
Quarterly Average | Margin on Base Rate | Margin on LIBOR | ||
Availability Percentage | Revolving Loans | Revolving Loans | ||
≥ 66%
|
1.00% | 2.25% | ||
≥ 33% and < 66% | 1.25% | 2.50% | ||
< 33% | 1.50% | 2.75% |
If an event of default exists under the revolving credit facility, the lenders will be able to
accelerate the maturity of the credit facilities and exercise other rights and remedies. An event
of default includes, among other things, the nonpayment of principal interest, fees or other
amounts; failure of any representation or warranty to be true and correct when made or confirmed;
failure to perform or observe covenants in the revolving credit facility or other loan documents,
subject, in limited circumstances, to certain grace periods; cross-defaults in other indebtedness
if the effect of such default is to cause, or permit the holders of such indebtedness to cause, the
acceleration of such indebtedness under any material agreement; bankruptcy or insolvency events;
monetary judgment defaults; asserted invalidity of the loan documentation; and a change of control
over us.
Amounts outstanding on our revolving credit facility fluctuate materially during each
quarter due to normal changes in working capital, payments of quarterly distributions to
unitholders and debt service costs. Specifically, the amount borrowed under our revolving credit
facility is typically at its highest level after we pay for the majority of our crude oil supplies
on the 20th day of every month per standard industry terms. The maximum revolving credit facility
borrowings during the second quarter of 2011 were $97.6
47
Table of Contents
million. Nonetheless, our availability on
our revolving credit facility during the peak borrowing days of a quarter has been ample to support
our operations and service upcoming requirements. During the quarter ended June 30, 2011,
availability for additional borrowings under our revolving credit facility was approximately $104.3
million at its lowest point. We believe that we will continue to have sufficient cash flow from
operations and borrowing availability under our revolving credit facility to meet our financial
commitments, minimum quarterly distributions to our unitholders, debt service obligations,
credit agreement covenants, contingencies and anticipated capital expenditures.
9 3/8% Senior Notes
On April 21, 2011, we and Calumet Finance Corp. issued and sold $400.0 million in aggregate
principal amount of our 9 3/8% 2019 Notes in a private placement pursuant to Rule 144A under the
Securities Act to eligible purchasers. The 2019 Notes were resold to qualified institutional buyers
pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to
Regulation S under the Securities Act. We received proceeds of $389.0 million net of underwriters
fees and expenses, which we used to repay in full borrowings outstanding under our existing senior
secured first lien term loan facility, as well as all accrued interest and fees, and for general
partnership purposes. Interest on the 2019 Notes will be paid semiannually in arrears on May 1 and
November 1 of each year, beginning on November 1, 2011. The 2019 Notes will mature on May 1, 2019,
unless redeemed prior to maturity. The 2019 Notes are guaranteed on a senior unsecured basis by all
of our operating subsidiaries and certain of our future operating subsidiaries.
At any time prior to May 1, 2014, we may on any one or more occasions redeem up to 35% of the
aggregate principal amount of the 2019 Notes with the net proceeds of a public or private equity
offering at a redemption price of 109.375% of the principal amount, plus any accrued and unpaid
interest to the date of redemption, provided that: (1) at least 65% of the aggregate principal
amount of 2019 Notes issued remains outstanding immediately after the occurrence of such redemption
and (2) the redemption occurs within 120 days of the date of the closing of such public or private
equity offering.
On and after May 1, 2015, we may on any one or more occasions redeem all or a part of the 2019
Notes at the redemption prices (expressed as percentages of principal amount) set forth below, plus
any accrued and unpaid interest to the applicable redemption date on such 2019 Notes, if redeemed
during the twelve-month period beginning on May 1 of the years indicated below:
Year | Percentage | |||
2015 |
104.688 | % | ||
2016 |
102.344 | % | ||
2017 and at any time thereafter |
100.000 | % |
Prior to May 1, 2015, we may on any one or more occasions redeem all or part of the 2019 Notes
at a redemption price equal to the sum of: (1) the principal amount thereof, plus (2) a make-whole
premium (as set forth in the indenture governing the 2019 Notes) at the redemption date, plus any
accrued and unpaid interest to the applicable redemption date.
The indenture governing the 2019 Notes contains covenants that, among other things, restrict
our ability and the ability of certain of our subsidiaries to: (i) sell assets; (ii) pay
distributions on, redeem or repurchase our units or redeem or repurchase our subordinated debt;
(iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units;
(v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other
payments from our restricted subsidiaries to us; (vii) consolidate, merge or transfer all or
substantially all of our assets; (viii) engage in transactions with affiliates and (ix) create
unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications.
At any time when the 2019 Notes are rated investment grade by either of Moodys Investors Service,
Inc. or Standard & Poors Ratings Services and no Default or Event of Default, each as defined in
the indenture governing the 2019 Notes, has occurred and is continuing, many of these covenants
will be suspended.
Upon the occurrence of certain change of control events, each holder of the 2019 Notes will
have the right to require that we repurchase all or a portion of such holders 2019 Notes in cash
at a purchase price equal to 101% of the principal amount thereof, plus any accrued and unpaid
interest to the date of repurchase.
In connection with the notes offering on April 21, 2011, our then current revolving credit
facility was amended to, among other things, (i) permit the issuance of the 2019 Notes; (ii) upon
consummation of the issuance of the 2019 Notes and the termination of the senior secured first lien
credit facility, release the revolving credit facility lenders second priority lien on the
collateral securing the senior secured first lien credit facility and (iii) change the interest
rate pricing on the revolving credit facility.
48
Table of Contents
Registration Rights Agreement
On April 21, 2011, in connection with the issuance and sale of the 2019 Notes, we entered into
a registration rights agreement with the initial purchasers of the 2019 Notes obligating us to use
reasonable best efforts to file an exchange registration statement with the
SEC so that holders of the 2019 Notes can offer to exchange the 2019 Notes issued in this
offering for registered notes having substantially the same terms as the 2019 Notes and evidencing
the same indebtedness as the 2019 Notes. We must use reasonable best efforts to cause the exchange
offer registration statement to become effective by April 20, 2012 and remain effective until 180
days after the closing of the exchange. Additionally, we have agreed to commence the exchange offer
promptly after the exchange offer registration statement is declared effective by the SEC and use
reasonable best efforts to complete the exchange offer not later than 60 days after such effective
date. Under certain circumstances, in lieu of a registered exchange offer, we must use reasonable
best efforts to file a shelf registration statement for the resale of the 2019 Notes. If we fail to
satisfy these obligations on a timely basis, the annual interest borne by the 2019 Notes will be
increased by up to 1.0% per annum until the exchange offer is completed or the shelf registration
statement is declared effective.
Senior Secured First Lien Credit Facility
On April 21, 2011, we used approximately $369.5 million of the net proceeds from the issuance
and sale of the 2019 Notes to repay in full our term loan facility,
as well as accrued interest and fees, and extinguished the senior
secured first lien credit facility. We did not incur any material early extinguishment penalties in
connection with our termination of the senior secured first lien credit facility. Further, we
recorded in the second quarter of 2011 approximately $15.1 million in extinguishment charges
related to the write off of the unamortized debt issuance costs and the unamortized discount
associated with the term loan.
Borrowings under the senior secured first lien credit facility were used (i) to finance a
portion of the acquisition of Penreco in 2008, (ii) to fund the anticipated growth in working
capital and remaining capital expenditures associated with our Shreveport refinery expansion
project completed in 2008, (iii) to refinance our then-existing term loan facility, (iv) to issue a
$50.0 million letter credit to secure our obligations under one of our master derivatives contracts
and (v) for general partnership purposes. Each lender under the senior secured first lien credit
facility generally had a first priority lien on our fixed assets and a second priority lien on our
cash, accounts receivable, inventory and certain other personal property. The senior secured first
lien credit facility would have matured in January 2015.
Derivatives
In connection with the termination of the term loan facility and the amendment
of our senior secured revolving credit facility, on April 21, 2011, we entered into Amendments to
certain of our master derivatives contracts to provide new credit support arrangements to secure
our payment obligations under these contracts following the termination of the term loan facility
and the amendment and restatement of our senior secured revolving credit facility. Under the new
credit support arrangements, our payment obligations are generally secured by a first priority lien
on our and our subsidiaries real property, plant and equipment, fixtures, intellectual property,
certain financial assets, certain investment property, commercial tort claims, chattel paper,
documents, instruments and proceeds of the foregoing (including proceeds of hedge arrangements). We
also issued to one counterparty a $25.0 million standby letter of credit under the revolving credit
facility to replace a prefunded $50.0 million letter of credit previously issued under the senior
secured first lien facility. In the event that such counterpartys exposure to us exceeds $150.0
million, we will be required to post additional collateral support in the form of either cash or
letters of credit with the counterparty to enter into additional crack spread hedges. Our master
derivatives contracts will continue to impose a number of covenant limitations on our operating and
financing activities, including limitations on liens on collateral, limitations on dispositions of
collateral and collateral maintenance and insurance requirements. In addition to the $25.0 million
standby letter of credit posted to one counterparty, as of June 30, 2011 we had cash collateral
posted to another counterparty of $11.9 million. For financial reporting purposes, we do not
offset the collateral provided to a counterparty against the fair value of its obligation to that
counterparty. Any outstanding collateral is released to us upon settlement of the related
derivative instrument liability. Our master derivative contracts continue to impose a number of
covenant limitations on our operating and financing activities, including limitations on liens on
collateral, limitations on dispositions of collateral and collateral maintenance and insurance
requirements.
The fair value of the Companys derivatives decreased by approximately $46.0 million
subsequent to June 30, 2011 to a liability of approximately
$184.0 million. As of August 8, 2011, we had
approximately $31.3 million in cash margin posted with one counterparty to support crack spread
hedging. All other credit support thresholds with our counterparties are at levels where it would
take a substantial increase in fuel products crack spreads to require additional collateral to be
posted. As a result, we do not expect further increases in fuel products crack spreads to
significantly impact our liquidity.
49
Table of Contents
Contractual Obligations and Commercial Commitments
The following table summarizes our contractual cash obligations as of June 30, 2011 at current
maturities and reflects only those line items that are materially changed since December 31, 2010:
Payments Due by Period | ||||||||||||||||||||
Less Than | 1-3 | 3-5 | More Than | |||||||||||||||||
Total | 1 Year | Years | Years | 5 Years | ||||||||||||||||
(In thousands) | ||||||||||||||||||||
Operating activities: |
||||||||||||||||||||
Interest on long-term debt at contractual rates (1) |
$ | 309,932 | $ | 43,288 | $ | 80,219 | $ | 80,175 | $ | 106,250 | ||||||||||
Operating lease obligations (2) |
33,107 | 11,789 | 15,458 | 5,182 | 678 | |||||||||||||||
Letters of credit (3) |
179,473 | 179,473 | | | | |||||||||||||||
Purchase commitments (4) |
1,271,176 | 765,864 | 436,920 | 68,392 | | |||||||||||||||
Financing activities: |
||||||||||||||||||||
Capital lease obligations |
1,292 | 942 | 350 | | | |||||||||||||||
Long-term debt obligations, excluding capital lease obligations |
428,090 | | | | 428,090 | |||||||||||||||
Total obligations |
$ | 2,223,070 | $ | 1,001,356 | $ | 532,947 | $ | 153,749 | $ | 535,018 | ||||||||||
(1) | Interest on long-term debt at contractual rates and maturities relates primarily to our 2019 Notes and revolving credit agreement. | |
(2) | We have various operating leases primarily for the use of land, storage tanks, pressure stations, railcars, equipment, precious metals and office facilities that extend through August 2017. | |
(3) | Letters of credit primarily supporting crude oil purchases, precious metals leasing and hedging activities. | |
(4) | Purchase commitments consist primarily of obligations to purchase fixed volumes of crude oil and other feedstocks and finished products for resale from various suppliers based on current market prices at the time of delivery. |
In connection with the closing of the acquisition of Penreco on January 3, 2008, we entered
into a feedstock purchase agreement with ConocoPhillips related to the LVT unit at its Lake
Charles, Louisiana refinery (the LVT Feedstock Agreement). Pursuant to the LVT Feedstock
Agreement, ConocoPhillips is obligated to supply a minimum quantity (the Base Volume) of
feedstock for the LVT unit for a term of ten years. Based upon this minimum supply quantity, we
expect to purchase $74.6 million of feedstock for the LVT unit in each fiscal year of the term
based on pricing estimates as of June 30, 2011. This amount is not included in the table above. If
the Base Volume is not supplied at any point during the first five years of the ten year term, a
penalty for each gallon of shortfall must be paid to us as liquidated damages.
Off-Balance Sheet Arrangements
We have no material off-balance sheet arrangements.
Critical Accounting Policies and Estimates
For additional discussion regarding our critical accounting policies and estimates, see
Critical Accounting Policies and Estimates under Part I Item 7 of our 2010 Annual Report.
Recent Accounting Pronouncements
For additional discussion regarding recent accounting pronouncements, see Note 2 under Part I
Item 1 Financial Statements Notes to Unaudited Condensed Consolidated Financial Statements.
Equity Transactions
In February 2011, we satisfied the last of the earnings and distributions tests contained
in our partnership agreement for the automatic conversion of all 13,066,000 outstanding
subordinated units into common units on a one-for-one basis. The last of these requirements was met
upon payment of the quarterly distribution on February 14, 2011. Two days following this quarterly
distribution to our unitholders, or February 16, 2011, all
of the outstanding subordinated units automatically converted to common units.
50
Table of Contents
On February 24, 2011, we completed a public equity offering of our common units in which we
sold 4,500,000 common units to the underwriters of the offering at a price to the public of $21.45
per common unit. The proceeds received by us from this offering (net of underwriting discounts,
commissions and expenses but before our general partners capital contribution) were $92.3 million.
The net proceeds were used to repay borrowings under our revolving credit facility and for general
partnership purposes. Underwriting discounts totaled $3.9 million. Our general partner contributed
$2.0 million to retain its 2% general partner interest.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
The following should be read in conjunction with Quantitative and Qualitative Disclosures
About Market Risk included under Part I Item 7A in our 2010 Annual Report. There have been no
material changes in that information other than as discussed below. Also, see Note 6 under Part I
Item 1 Financial Statements Notes to Unaudited Condensed Consolidated Financial Statements for
additional discussion related to derivative instruments and hedging activities.
Commodity Price Risk
Holding all other variables constant, we expect a $1 increase in the applicable commodity
prices would change our recorded mark-to-market valuation by the following amounts based upon the
volumes hedged as of June 30, 2011:
In millions | ||||
Crude oil swaps |
$ | 11.4 | ||
Diesel swaps |
$ | 3.6 | ||
Jet fuel swaps |
$ | 7.3 | ||
Gasoline swaps |
$ | 0.6 |
Interest Rate Risk
Our profitability and cash flows are affected by changes in interest rates, specifically LIBOR
and prime rates, which is consistent with prior years. The primary purpose of our interest rate
risk management activities is to hedge our exposure to changes in interest rates. Historically, our
policy has been to enter into interest rate swap agreements to hedge up to 75% of our interest rate
risk related to variable rate debt.
We are exposed to market risk from fluctuations in interest rates. As of June 30, 2011, we had
approximately $28.1 million of variable rate debt outstanding under our revolving credit facility.
Holding other variables constant (such as debt levels), a one hundred basis point change in
interest rates on our variable rate debt as of June 30, 2011 would be expected to have an impact on
net income and cash flows for 2011 of approximately $0.3 million.
Existing Commodity Derivative Instruments
Fuel Products Segment
The following table provides a summary of the implied crack spreads for the crude oil, diesel,
jet fuel and gasoline swaps as of June 30, 2011 disclosed in Note 6 under Part I Item 1 Financial
Statements Notes to Unaudited Condensed Consolidated Financial Statements, all of which are
designated as hedges.
Implied Crack | ||||||||||||
Crude Oil and Fuel Products Swap Contracts by Expiration Dates | Barrels | BPD | Spread ($/Bbl) | |||||||||
Third Quarter 2011 |
1,610,000 | 17,500 | $ | 12.75 | ||||||||
Fourth Quarter 2011 |
1,334,000 | 14,500 | 12.16 | |||||||||
Calendar Year 2012 |
5,626,000 | 15,372 | 13.27 | |||||||||
Calendar Year 2013 |
2,864,000 | 7,847 | 23.90 | |||||||||
Totals |
11,434,000 | |||||||||||
Average price |
$ | 15.73 |
51
Table of Contents
At June 30, 2011, we had the following jet fuel put options related to jet fuel crack spreads
in our fuel products segment, none of which are designated as hedges.
Average | Average | |||||||||||||||
Sold Put | Bought Put | |||||||||||||||
Jet Fuel Put Option Crack Spread Contracts by Expiration Dates | Barrels | BPD | ($/Bbl) | ($/Bbl) | ||||||||||||
Fourth Quarter 2011 |
184,000 | 2,000 | $ | 4.75 | $ | 7.00 | ||||||||||
Totals |
184,000 | |||||||||||||||
Average price |
$ | 4.75 | $ | 7.00 |
Specialty Products Segment
At June 30, 2011, we had no derivative positions outstanding related to crude oil purchases in
our specialty products segment. Please refer to Note 6 under Part I Item 1 Financial Statements
Notes to Unaudited Condensed Consolidated Financial Statements for detailed information on these
derivatives.
Item 4. Controls and Procedures
(a) Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) of the Securities Exchange Act of 1934 (the Exchange Act), as
amended, we have evaluated, under the supervision and with the participation of our management,
including our principal executive officer and principal financial officer, the effectiveness of the
design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and
15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Our
disclosure controls and procedures are designed to provide reasonable assurance that the
information required to be disclosed by us in reports that we file under the Exchange Act is
accumulated and communicated to our management, including our principal executive officer and
principal financial officer, as appropriate, to allow timely decisions regarding required
disclosure and is recorded, processed, summarized and reported within the time periods specified in
the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and
principal financial officer have concluded that our disclosure controls and procedures were
effective as of June 30, 2011 at the reasonable assurance level.
(b) Changes in Internal Control over Financial Reporting
There was no change in our internal control over financial reporting during the second fiscal
quarter of 2011 that has materially affected, or is reasonably likely to materially affect, our
internal control over financial reporting.
52
Table of Contents
PART II
Item 1. Legal Proceedings
We are not a party to, and our property is not the subject of, any pending legal proceedings
other than ordinary routine litigation incidental to our business. Our operations are subject to a
variety of risks and disputes normally incident to our business. As a result, we may, at any given
time, be a defendant in various legal proceedings and litigation arising in the ordinary course of
business. The information provided under Note 4 Commitments and Contingencies in Part I Item 1
Financial Statements Notes to Unaudited Condensed Consolidated Financial Statements is
incorporated herein by reference.
Item 1A. Risk Factors
The risk factors included in our 2010 Annual Report have not materially changed other than as
set forth below.
Our revolving credit facility, indenture governing the 2019 Notes and master derivative contracts
contain operating and financial restrictions that may restrict our business and financing
activities.
The operating and financial restrictions and covenants in our revolving credit facility,
indenture governing the 2019 Notes, master derivative contracts and any future financing agreements
could restrict our ability to finance future operations or capital needs or to engage, expand or
pursue our business activities, including restrictions on our ability to, among other things:
| pay distributions or redeem or repurchase our units or repurchase our subordinated debt; |
| incur or guarantee additional indebtedness or issue preferred units; |
| create or incur certain liens; |
| make certain acquisitions and investments; |
| make capital expenditures above specified amounts; |
| redeem or repay other debt or make other restricted payments; |
| enter into transactions with affiliates; |
| enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us; |
| create unrestricted subsidiaries; |
| enter into sale and leaseback transactions; |
| enter into a merger, consolidation or transfer or sale of assets, including equity interests in our subsidiaries; |
| cease our commodity hedging program; and |
| engage in certain business activities. |
Our revolving credit facility contains operating and financial restrictions similar to the
above listed items, including a springing financial covenant which provides that if availability
under the revolving credit facility falls below the greater of (i) 12.5% of the lesser of (a) the
Borrowing Base (as defined in the credit agreement) (without giving effect to the LC Reserve (as
defined in the credit agreement)) and (b) the credit agreement commitments then in effect and (ii)
$30.0 million, we will be required to maintain as of the end of each fiscal quarter a Fixed Charge
Coverage Ratio (as defined in the Credit Agreement) of at least 1.0 to 1.0. The failure to comply
with any of these or other covenants would cause a default under our revolving credit facility.
53
Table of Contents
Our existing indebtedness imposes, and any future indebtedness may impose, a number of
covenants on us regarding collateral maintenance and insurance maintenance. As a result of these
covenants and restrictions, we will be limited in the manner in which we conduct our business, and
we may be unable to engage in favorable business activities or finance future operations or capital
needs.
Our ability to comply with the covenants and restrictions contained in the indenture governing
the 2019 Notes, our revolving credit facility and our master derivative contracts may be affected
by events beyond our control. If market or other economic conditions deteriorate, our ability to
comply with these covenants and restrictions may be impaired. A failure to comply with the
covenants, ratios or tests in the indenture governing the 2019 Notes, our revolving credit
facility, our master derivative contracts or any future indebtedness could result in an event of
default under the indenture, our revolving credit facility, our master derivative contracts, the
indenture governing our 2019 Notes or our future indebtedness, which, if not cured or waived, could
have a material adverse affect on our business, financial condition and results of operations. In
the event of any default on our indebtedness, our debt holders and lenders:
| will not be required to lend any additional amounts to us; |
| could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable; |
| could elect to require that all obligations accrue interest at the default rate, if such rate has not already been imposed; |
| may have the ability to require us to apply all of our available cash to repay these borrowings; or |
| may prevent us from making debt service payments under our other agreements, any of which could result in an event of default under the notes. |
If an acceleration of our debt occurs, we may not be able to repay our debt or borrow
sufficient funds to refinance it. Even if new financing were available, it may be on terms that are
less attractive to us than our then existing credit facilities or it may not be on terms that are
acceptable to us.
If our existing indebtedness were to be accelerated, there can be no assurance that we would
have, or be able to obtain, sufficient funds to repay such indebtedness in full. In addition, our
obligations under our revolving credit facility are secured by substantially all of our accounts
receivable, inventory and certain related assets and our obligations under our master derivative
contracts are secured by a first priority lien on our real property, plant and equipment, fixtures,
intellectual property, certain financial assets, certain investment property, commercial tort
claims, chattel paper, documents, instruments and proceeds of the forgoing (including proceeds of
hedge agreements), and if we are unable to repay our indebtedness under the revolving credit
facility or master derivative contracts, the lenders could seek to foreclose on these assets.
Please read Part I Item 2 Managements Discussion and Analysis of Financial Condition and Results
of Operations Liquidity and Capital Resources Debt and Credit Facilities for additional
information regarding our long-term debt.
We have a holding company structure in which our subsidiaries conduct our operations and own our
operating assets and our ability to distribute cash to our unitholders and make payments on our debt
obligations depends on the performance of our subsidiaries and their ability to distribute funds
to us.
We are a holding company, and our subsidiaries conduct all of our operations and own all of
our operating assets. We have no significant assets other than the equity interests in our
subsidiaries. As a result, our ability to distribute cash to our unitholders and payments of debt
obligations depends on the performance of our subsidiaries and their ability to distribute funds to
us. The ability of our subsidiaries to make distributions to us may be restricted by, among other
things, our revolving credit facility and applicable state laws and other laws and regulations. If
we are unable to obtain the funds necessary to distribute cash to our unitholders or payments of
debt obligations, we may be required to adopt one or more alternatives, such as a refinancing of
our indebtedness, including our 2019 Notes, or incurring borrowings under our revolving credit
facility. We cannot assure you that we would be able to refinance our indebtedness or that the
terms on which we could refinance our indebtedness would be favorable.
A change of control could result in us facing substantial repayment obligations under our
revolving credit facility and our 2019 Notes.
Our revolving credit agreement and the indenture governing our 2019 Notes contain provisions
relating to change of control of our managing general partner, our partnership and our operating
subsidiaries. Upon a change of control event, we may be required
54
Table of Contents
immediately to repay the
outstanding principal, any accrued interest on and any other amounts owed by us under our revolving
credit facility, the 2019 Notes and other outstanding indebtedness. The source of funds for these
repayments would be our available cash or cash generated from other sources. In such an event,
there is no assurance that we would be able to pay the indebtedness, in which case the lenders
under our revolving credit facility would have the right to foreclose on our assets, which would
have a material adverse effect on us. Furthermore, certain change of control events would
constitute an event of default under the agreement governing our revolving credit facility, and we
might not be able to obtain a waiver of such default. There is no restriction in our partnership
agreement on the ability of our general partner to enter into a transaction which would trigger the
change of control provisions of our revolving credit facility agreement or the indenture governing
our 2019 Notes.
We depend on certain key crude oil and other feedstock suppliers for a significant portion of our
supply of crude oil and other feedstocks, and the loss of any of these key suppliers or a material
decrease in the supply of crude oil and other feedstocks generally available to our refineries
could materially reduce our ability to make distributions to unitholders.
We purchase crude oil and other feedstocks from major oil companies as well as from various
crude oil gatherers and marketers in east Texas and north Louisiana. In 2010, subsidiaries of
Plains All American Pipeline, L.P. and Genesis Crude Oil, L.P. supplied us with approximately 49.6%
and 4.6%, respectively, of our total crude oil supplies under term contracts and evergreen crude
oil supply contracts. In addition, 41.5% of our total crude oil purchases in 2010 were from Legacy
Resources, an affiliate of our general partner, to supply crude oil to our Princeton and Shreveport
refineries. Each of our refineries is dependent on one or more of these suppliers and the loss of
any of these suppliers would adversely affect our financial results to the extent we were unable to
find another supplier of this substantial amount of crude oil. We do not maintain long-term
contracts with most of our suppliers. For example, our contracts with Plains are currently
month-to-month terminable upon 90 days notice. Additionally, we expect to purchase the crude oil
supply for the Princeton refinery and Shreveport refinery directly from third-party suppliers under
evergreen supply contracts and on the spot market. These evergreen contracts are generally
terminable on 30 days notice, and purchases on the spot market may expose us to changes in
commodity prices. For additional discussion regarding our crude oil
and feedstock supply, please read Items 1 and 2 Business and
Properties Crude Oil and Feedstock Supply
in our 2010 Annual Report.
To the extent that our suppliers reduce the volumes of crude oil and other feedstocks that
they supply us as a result of declining production or competition or otherwise, our revenues, net
income and cash available for distribution to unitholders and payments of our debt obligations
would decline unless we were able to acquire comparable supplies of crude oil and other feedstocks
on comparable terms from other suppliers, which may not be possible in areas where the supplier
that reduces its volumes is the primary supplier in the area. A material decrease in crude oil
production from the fields that supply our refineries, as a result of depressed commodity prices,
lack of drilling activity, natural production declines, governmental moratoriums on drilling or
production activities or otherwise, could result in a decline in the volume of crude oil we refine.
Fluctuations in crude oil prices can greatly affect production rates and investments by third
parties in the development of new oil reserves. Drilling activity generally decreases as crude oil
prices decrease. We have no control over the level of drilling activity in the fields that supply
our refineries, the amount of reserves underlying the wells in these fields, the rate at which
production from a well will decline or the production decisions of producers, which are affected
by, among other things, prevailing and projected energy prices, demand for hydrocarbons, geological
considerations, governmental regulation and the availability and cost of capital.
We are dependent on certain third-party pipelines for transportation of crude oil and refined
products, and if these pipelines become unavailable to us, our revenues and cash available for
distributions to our unitholders and payment of our debt obligations could decline.
Our Shreveport refinery is interconnected to pipelines that supply most of its crude oil and
ship a portion of its refined fuel products to customers, such as pipelines operated by
subsidiaries of Enterprise Products Partners L.P. and ExxonMobil. Since we do not own or operate
any of these pipelines, their continuing operation is not within our control. In addition, any of
these third-party pipelines could become unavailable to transport crude oil or our refined fuel
products because of acts of God, accidents, government regulation, terrorism or other events. For
example, our refinery run rates were affected by an approximately three week shutdown during May
and June 2011 of the ExxonMobil crude oil pipeline serving our Shreveport refinery resulting from
the Mississippi River flooding occurring during this period. If any of these third-party pipelines
become unavailable to transport crude oil or our refined fuel products because of acts of God,
accidents, government regulation, terrorism or other events, our revenues, net income and cash
available for distributions to our unitholders and payment of our debt obligations could decline.
55
Table of Contents
Decreases in the price of crude oil may lead to a reduction in the borrowing base under our
revolving credit facility or the requirement that we post substantial amounts of cash collateral
for derivative instruments, either of which could adversely affect our liquidity, financial
condition and our ability to distribute cash to our unitholders.
The borrowing base under our revolving credit facility is determined weekly or monthly
depending upon availability levels or the existence of a default or event of default. Reductions in
the value of our inventories as a result of lower crude oil prices could result in a reduction in
our borrowing base, which would reduce the amount of financial resources available to meet our
capital requirements. Further, if at any time our available capacity under our revolving credit
facility falls below $35.0 million, or a default or event of
default exists and for an additional 60
days after those circumstances do not exist, our cash balances in a dominion account established
with the administrative agent will be applied on a daily basis to our
outstanding obligations and
the revolving credit facility. In addition, decreases in the price of crude oil may require us to
post substantial amounts of cash collateral to our hedging counterparties in order to maintain our
hedging positions. At June 30, 2011, we had $194.7 million in availability under our revolving
credit facility. Please read Managements Discussion and Analysis of Financial Condition and
Results of Operations Liquidity and Capital Resources Debt and Credit Facilities for
additional information. If the borrowing base under our revolving credit facility decreases or we
are required to post substantial amounts of cash collateral to our hedging counterparties, it could
have a material adverse effect on our liquidity, financial condition and our ability to distribute
cash to our unitholders.
An increase in interest rates will cause our debt service obligations to increase.
Borrowings under our revolving credit facility bear interest at a floating rate (4.50% as of
June 30, 2011). The interest rate is subject to adjustment based on fluctuations in the London
Interbank Offered Rate (LIBOR) or prime rate. An increase in the interest rates associated with
our floating-rate debt would increase our debt service costs and affect our results of operations
and cash flow available for distribution to our unitholders. In addition, an increase in interest
rates could adversely affect our future ability to obtain financing or materially increase the cost
of any additional financing.
In addition to the other information set forth in this Quarterly Report, you should carefully
consider the factors discussed in Part I Item 1A. Risk Factors in our 2010 Annual Report, which
could materially affect our business, financial condition or future results. The risks described in
this Quarterly Report and in our 2010 Annual Report are not the only risks facing the Company.
Additional risks and uncertainties not currently known to us or that we currently deem to be
immaterial also may materially adversely affect our business, financial condition or future
results.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Removed and Reserved
Item 5. Other Information
None.
56
Table of Contents
Item 6. Exhibits
The following documents are filed as exhibits to this Quarterly Report:
Exhibit | ||
Number | Description | |
3.1
|
Certificate of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrants Registration Statement on Form S-1 filed with the Commission on October 7, 2005 (File No. 333-128880)). | |
3.2
|
Amended and Restated Limited Partnership Agreement of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrants Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)). | |
3.3
|
Certificate of Formation of Calumet GP, LLC (incorporated by reference to Exhibit 3.3 to the Registrants Registration Statement on Form S-1 filed with the Commission on October 7, 2005 (File No. 333-128880)). | |
3.4
|
Amended and Restated Limited Liability Company Agreement of Calumet GP, LLC (incorporated by reference to Exhibit 3.2 to the Registrants Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)). | |
3.5
|
Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrants Current Report on Form 8-K filed with the Commission on July 11, 2006 (File No. 000-51734)). | |
3.6
|
Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrants Current Report on Form 8-K filed with the Commission on April 18, 2008 (File No. 000-51734)). | |
4.1
|
Specimen Unit Certificate representing common units (incorporated by reference to Exhibit 3.7 to the Registrants Quarterly Report on Form 10-Q filed with the SEC on November 4, 2010 (File No. 000-51734)). | |
4.2
|
Indenture, dated April 21, 2011, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors party thereto and Wilmington Trust FSB, as trustee (incorporated by reference to Exhibit 4.1 to the Registrants Current Report on Form 8-K filed with the SEC on April 26, 2011 (File No. 000-51734)). | |
4.3
|
Registration Rights Agreement, dated April 21, 2011, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors party thereto and the initial purchasers party thereto (incorporated by reference to Exhibit 4.2 to the Registrants Current Report on Form 8-K filed with the SEC on April 26, 2011 (File No. 000-51734)). | |
10.1*
|
Amended and Restated ISDA Master Agreement and related Schedule, Lien Annex, Credit Support Annex and amendments thereto, dated as of January 3, 2008, between Calumet Lubricants Co., Limited Partnership and J. Aron & Company. | |
10.2*
|
Collateral Trust Agreement, as amended, dated as of April 21, 2011, among Calumet Lubricants Co., Limited Partnership, the guarantors party thereto, the secured hedge counterparties thereto and Bank of America, N.A. | |
10.3
|
Amended and Restated Credit Agreement, dated as June 24, 2011, by and among Calumet Specialty Products Partners, L.P. and its subsidiaries as Borrowers, the Lenders, Bank of America, N.A., as Agent and Merrill Lynch, Pierce, Fenner & Smith Incorporated, J.P. Morgan Securities LLC and Wells Fargo Capital Finance, LLC as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 10.1 to the Registrants Current Report on Form 8-K filed with the Commission on June 30, 2011 (File No. 000-51734)). | |
31.1*
|
Sarbanes-Oxley Section 302 certification of F. William Grube. | |
31.2*
|
Sarbanes-Oxley Section 302 certification of R. Patrick Murray, II. | |
32.1*
|
Section 1350 certification of F. William Grube and R. Patrick Murray, II. | |
100.INS**
|
XBRL Instance Document | |
101.SCH**
|
XBRL Taxonomy Extension Schema Document | |
101.CAL**
|
XBRL Taxonomy Extension Calculation Linkbase Document | |
101.DEF**
|
XBRL Taxonomy Extension Definition Linkbase Document | |
101.LAB**
|
XBRL Taxonomy Extension Label Linkbase Document | |
101.PRE**
|
XBRL Taxonomy Extension Presentation Linkbase Document |
* | Filed herewith. | |
** | XBRL (Extensible Business Reporting Language) information is furnished and not filed or a part of the registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections. |
57
Table of Contents
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P. |
||||
By: | Calumet GP, LLC, | |||
its general partner | ||||
By: | /s/ R. Patrick Murray, II | |||
R. Patrick Murray, II Vice President, | ||||
Chief Financial Officer and Secretary of Calumet GP, LLC, general partner of Calumet Specialty Products Partners, L.P. (Authorized Person and Principal Accounting Officer) |
||||
Date: August 8, 2011
58
Table of Contents
Index to Exhibits
Exhibit | ||
Number | Description | |
3.1
|
Certificate of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrants Registration Statement on Form S-1 filed with the Commission on October 7, 2005 (File No. 333-128880)). | |
3.2
|
Amended and Restated Limited Partnership Agreement of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrants Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)). | |
3.3
|
Certificate of Formation of Calumet GP, LLC (incorporated by reference to Exhibit 3.3 of Registrants Registration Statement on Form S-1 filed with the Commission on October 7, 2005 (File No. 333-128880)). | |
3.4
|
Amended and Restated Limited Liability Company Agreement of Calumet GP, LLC (incorporated by reference to Exhibit 3.2 to the Registrants Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)). | |
3.5
|
Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed with the Commission on July 11, 2006 (File No. 000-51734)). | |
3.6
|
Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed with the Commission on April 18, 2008 (File No. 000-51734)). | |
4.1
|
Specimen Unit Certificate representing common units (incorporated by reference to Exhibit 3.7 to the Registrants Quarterly Report on Form 10-Q filed with the SEC on November 4, 2010 (File No. 000-51734)). | |
4.2
|
Indenture, dated April 21, 2011, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors party thereto and Wilmington Trust FSB, as trustee (incorporated by reference to Exhibit 4.1 to the Registrants Current Report on Form 8-K filed with the SEC on April 26, 2011 (File No. 000-51734)). | |
4.3
|
Registration Rights Agreement, dated April 21, 2011, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors party thereto and the initial purchasers party thereto (incorporated by reference to Exhibit 4.2 to the Registrants Current Report on Form 8-K filed with the SEC on April 26, 2011 (File No. 000-51734)). | |
10.1*
|
Amended and Restated ISDA Master Agreement and related Schedule, Lien Annex, Credit Support Annex and amendments thereto, dated as of January 3, 2008, between Calumet Lubricants Co., Limited Partnership and J. Aron & Company. | |
10.2*
|
Collateral Trust Agreement, as amended, dated as of April 21, 2011, among Calumet Lubricants Co., Limited Partnership, the guarantors party thereto, the secured hedge counterparties thereto and Bank of America, N.A. | |
10.3
|
Amended and Restated Credit Agreement, dated as June 24, 2011, by and among Calumet Specialty Products Partners, L.P. and its subsidiaries as Borrowers, the Lenders, Bank of America, N.A., as Agent and Merrill Lynch, Pierce, Fenner & Smith Incorporated, J.P. Morgan Securities LLC and Wells Fargo Capital Finance, LLC as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 10.1 to the Registrants Current Report on Form 8-K filed with the Commission on June 30, 2011 (File No. 000-51734)). | |
31.1*
|
Sarbanes-Oxley Section 302 certification of F. William Grube. | |
31.2*
|
Sarbanes-Oxley Section 302 certification of R. Patrick Murray, II. | |
32.1*
|
Section 1350 certification of F. William Grube and R. Patrick Murray, II. | |
100.INS**
|
XBRL Instance Document | |
101.SCH**
|
XBRL Taxonomy Extension Schema Document | |
101.CAL**
|
XBRL Taxonomy Extension Calculation Linkbase Document | |
101.DEF**
|
XBRL Taxonomy Extension Definition Linkbase Document | |
101.LAB**
|
XBRL Taxonomy Extension Label Linkbase Document | |
101.PRE**
|
XBRL Taxonomy Extension Presentation Linkbase Document |
* | Filed herewith. | |
** | XBRL (Extensible Business Reporting Language) information is furnished and not filed or a part of the registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections. |
59