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EXCEL - IDEA: XBRL DOCUMENT - HollyFrontier Corp | Financial_Report.xls |
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EX-31.1 - EX-31.1 - HollyFrontier Corp | d80514exv31w1.htm |
EX-31.2 - EX-31.2 - HollyFrontier Corp | d80514exv31w2.htm |
EX-32.1 - EX-32.1 - HollyFrontier Corp | d80514exv32w1.htm |
EX-32.2 - EX-32.2 - HollyFrontier Corp | d80514exv32w2.htm |
EX-10.10 - EX-10.10 - HollyFrontier Corp | d80514exv10w10.htm |
Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31, 2011
OR
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File Number 1-3876
HOLLY CORPORATION
(Exact name of registrant as specified in its charter)
Delaware | 75-1056913 | |
(State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification No.) |
100 Crescent Court, Suite 1600 Dallas, Texas |
75201-6915 | |
(Address of principal executive offices) | (Zip Code) |
Registrants telephone number, including area code (214) 871-3555 |
Former name, former address and former fiscal year, if changed since last report
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
Yes 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 Regulation 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.
Large accelerated filer þ | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o | |||
(Do not check if a smaller reporting company) |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes o No þ
53,312,273 shares of Common Stock, par value $.01 per share, were outstanding on April 29, 2011.
HOLLY CORPORATION
INDEX
INDEX
Table of Contents
PART I. FINANCIAL INFORMATION
FORWARD-LOOKING STATEMENTS
References herein to Holly Corporation include Holly Corporation and its consolidated subsidiaries.
In accordance with the Securities and Exchange Commissions (SEC) Plain English guidelines,
this Quarterly Report on Form 10-Q has been written in the first person. In this document, the
words we, our, ours and us refer only to Holly Corporation and its consolidated
subsidiaries or to Holly Corporation or an individual subsidiary and not to any other person. The
words we, our, ours and us generally include Holly Energy Partners, L.P. (HEP) and its
subsidiaries as consolidated subsidiaries of Holly Corporation with certain exceptions where there
are transactions or obligations between HEP and Holly Corporation or its other subsidiaries. This
document contains certain disclosures of agreements that are specific to HEP and its consolidated
subsidiaries and do not necessarily represent obligations of Holly Corporation. When used in
descriptions of agreements and transactions, HEP refers to HEP and its consolidated subsidiaries.
This Quarterly Report on Form 10-Q contains certain forward-looking statements within the meaning
of the federal securities laws. All statements, other than statements of historical fact included
in this Form 10-Q, including, but not limited to, those under Results of Operations, Liquidity
and Capital Resources and Risk Management in Item 2 Managements Discussion and Analysis of
Financial Condition and Results of Operations in Part I and those in Item 1 Legal Proceedings in
Part II, are forward-looking statements. These statements are based on managements beliefs and
assumptions using currently available information and expectations as of the date hereof, are not
guarantees of future performance and involve certain risks and uncertainties. Although we believe
that the expectations reflected in these forward-looking statements are reasonable, we cannot
assure you that our expectations will prove to be correct. Therefore, actual outcomes and results
could materially differ from what is expressed, implied or forecast in these statements. Any
differences could be caused by a number of factors including, but not limited to:
| risks and uncertainties with respect to the actions of actual or potential competitive suppliers of refined petroleum products in our markets; | ||
| the demand for and supply of crude oil and refined products; | ||
| the spread between market prices for refined products and market prices for crude oil; | ||
| the possibility of constraints on the transportation of refined products; | ||
| the possibility of inefficiencies, curtailments or shutdowns in refinery operations or pipelines; | ||
| effects of governmental and environmental regulations and policies; | ||
| the availability and cost of our financing; | ||
| the effectiveness of our capital investments and marketing strategies; | ||
| our efficiency in carrying out construction projects; | ||
| our ability to acquire refined product operations or pipeline and terminal operations on acceptable terms and to integrate any existing or future acquired operations; | ||
| the possibility of terrorist attacks and the consequences of any such attacks; | ||
| general economic conditions; | ||
| risks and uncertainties with respect to our proposed merger of equals with Frontier Oil Corporation, including our ability to complete the merger in the anticipated timeframe or at all, the diversion of management in connection with the merger and our ability to realize fully or at all the anticipated benefits of the merger; and | ||
| other financial, operational and legal risks and uncertainties detailed from time to time in our Securities and Exchange Commission filings. |
Cautionary statements identifying important factors that could cause actual results to differ
materially from our expectations are set forth in this Form 10-Q, including without limitation, the
forward-looking statements that are referred to above. This summary discussion should be read in
conjunction with the discussion of risk factors and other cautionary statements under the heading
Risk Factors included in Item 1A of our Annual Report on Form 10-K for the year ended December
31, 2010 and in conjunction with the discussion in this Form 10-Q in Managements Discussion and
Analysis of Financial Condition and Results of Operations under the heading Liquidity and Capital
Resources. All forward-looking statements included in this Form 10-Q and all subsequent written
or oral forward-looking statements attributable to us or persons acting on our behalf are
expressly qualified in their entirety by these cautionary statements. The forward-looking
statements speak only as of the date made and, other than as required by law, we undertake no
obligation to publicly update or revise any forward-looking statements, whether as a result of new
information, future events or otherwise.
- 3 -
Table of Contents
DEFINITIONS
Within this report, the following terms have these specific meanings:
Alkylation means the reaction of propylene or butylene (olefins) with isobutane to form an
iso-paraffinic gasoline (inverse of cracking).
Aromatic oil is long chain oil that is highly aromatic in nature that is used to manufacture
tires and in the production of asphalt.
BPD means the number of barrels per calendar day of crude oil or petroleum products.
BPSD means the number of barrels per stream day (barrels of capacity in a 24 hour period) of
crude oil or petroleum products.
Black wax crude oil is a low sulfur, low gravity crude oil produced in the Uintah Basin in
Eastern Utah that has certain characteristics that require specific facilities to transport, store
and refine into transportation fuels.
Catalytic reforming means a refinery process which uses a precious metal (such as platinum)
based catalyst to convert low octane naphtha to high octane gasoline blendstock and hydrogen. The
hydrogen produced from the reforming process is used to desulfurize other refinery oils and is a
primary source of hydrogen for the refinery.
Cracking means the process of breaking down larger, heavier and more complex hydrocarbon
molecules into simpler and lighter molecules.
Crude distillation means the process of distilling vapor from liquid crudes, usually by
heating, and condensing the vapor slightly above atmospheric pressure turning it back to liquid in
order to purify, fractionate or form the desired products.
Delayed coker unit is a refinery unit that removes carbon from the bottom cuts of crude oil
to produce unfinished light transportation fuels and petroleum coke.
Ethanol means a high octane gasoline blend stock that is used to make various grades of
gasoline.
FCC, or fluid catalytic cracking, means a refinery process that breaks down large complex
hydrocarbon molecules into smaller more useful ones using a circulating bed of catalyst at
relatively high temperatures.
Hydrocracker means a refinery unit that breaks down large complex hydrocarbon molecules into
smaller more useful ones using a fixed bed of catalyst at high pressure and temperature with
hydrogen.
Hydrodesulfurization means to remove sulfur and nitrogen compounds from oil or gas in the
presence of hydrogen and a catalyst at relatively high temperatures.
Hydrogen plant means a refinery unit that converts natural gas and steam to high purity
hydrogen, which is then used in the hydrodesulfurization, hydrocracking and isomerization
processes.
HF alkylation, or hydrofluoric alkylation, means a refinery process which combines isobutane
and C3/C4 olefins using HF acid as a catalyst to make high octane gasoline blend stock.
Isomerization means a refinery process for rearranging the structure of C5/C6 molecules
without changing their size or chemical composition and is used to improve the octane of C5/C6
gasoline blendstocks.
LPG means liquid petroleum gases.
LSG, or low sulfur gasoline, means gasoline that contains less than 30 PPM of total sulfur.
- 4 -
Table of Contents
Lube extraction unit is a unit used in the lube process that separates aromatic oils from
paraffinic oils using furfural as a solvent.
Lubricant or lube means a solvent neutral paraffinic product used in passenger and
commercial vehicle engine oils, specialty products for metal working or heat transfer and other
industrial applications.
MEK means a lube process that separates waxy oil from non-waxy oils using methyl ethyl
ketone as a solvent.
MMBTU means one million British thermal units.
MMSCFD means one million standard cubic feet per day.
MTBE means methyl tertiary butyl ether, a high octane gasoline blend stock that is used to
make various grades of gasoline.
Natural gasoline means a low octane gasoline blend stock that is purchased and used to blend
with other high octane stocks produced to make various grades of gasoline.
PPM means parts-per-million.
Parafinnic oil is a high paraffinic, high gravity oil produced by extracting aromatic oils
and waxes from gas oil and is used in producing high-grade lubricating oils.
Refinery gross margin means the difference between average net sales price and average
product costs per produced barrel of refined products sold. This does not include the associated
depreciation and amortization costs.
Reforming means the process of converting gasoline type molecules into aromatic, higher
octane gasoline blend stocks while producing hydrogen in the process.
Roofing flux is produced from the bottom cut of crude oil and is the base oil used to make
roofing shingles for the housing industry.
RFS2 or advanced renewable fuel standard is a regulatory mandate required by the Energy
Independence and Security Act of 2007 that requires 36 billion gallons of renewable fuel to be
blended into transportation fuels by 2022. New mandated blending requirements for this standard
became effective July 1, 2010.
ROSE, or Solvent deasphalter / residuum oil supercritical extraction, means a refinery
unit that uses a light hydrocarbon like propane or butane to extract non-asphaltene heavy oils from
asphalt or atmospheric reduced crude. These deasphalted oils are then further converted to
gasoline and diesel in the FCC process. The remaining asphaltenes are either sold, blended to fuel
oil or blended with other asphalt as a hardener.
Scanfiner is a refinery unit that removes sulfur from gasoline to produce low sulfur
gasoline blendstock.
Sour crude oil means crude oil containing quantities of sulfur greater than 0.4 percent by
weight, while sweet crude oil means crude oil containing quantities of sulfur equal to or less
than 0.4 percent by weight.
ULSD, or ultra low sulfur diesel, means diesel fuel that contains less than 15 PPM of total
sulfur.
Vacuum distillation means the process of distilling vapor from liquid crudes, usually by
heating, and condensing the vapor below atmospheric pressure turning it back to a liquid in order
to purify, fractionate or form the desired products.
- 5 -
Table of Contents
Item 1. Financial Statements
HOLLY CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
(In thousands, except share data)
March 31, | December 31, | |||||||
2011 | 2010 | |||||||
(Unaudited) | ||||||||
ASSETS |
||||||||
Current assets: |
||||||||
Cash and cash equivalents (HEP: $1,502 and $403, respectively) |
$ | 224,114 | $ | 229,101 | ||||
Marketable securities |
48,947 | 1,343 | ||||||
Accounts receivable: Product and transportation (HEP: $23,475 and $22,508, respectively) |
349,509 | 299,081 | ||||||
Crude oil resales |
802,745 | 694,035 | ||||||
1,152,254 | 993,116 | |||||||
Inventories: Crude oil and refined products |
424,785 | 353,636 | ||||||
Materials and supplies (HEP: $185 and $202, respectively) |
48,671 | 46,731 | ||||||
473,456 | 400,367 | |||||||
Income taxes receivable |
2,042 | 51,034 | ||||||
Prepayments and other (HEP: $360 and $573, respectively) |
14,941 | 28,474 | ||||||
Total current assets |
1,915,754 | 1,703,435 | ||||||
Properties, plants and equipment, at cost (HEP: $563,834 and $552,398, respectively) |
2,282,634 | 2,215,828 | ||||||
Less accumulated depreciation (HEP: $(66,995) and $(60,300), respectively) |
(481,082 | ) | (459,137 | ) | ||||
1,801,552 | 1,756,691 | |||||||
Marketable securities (long-term) |
19,550 | | ||||||
Other assets: Turnaround costs |
69,409 | 69,533 | ||||||
Goodwill (HEP: $81,602 and $81,602) |
81,602 | 81,602 | ||||||
Intangibles and other (HEP: $75,138 and $72,434, respectively) |
101,893 | 90,214 | ||||||
252,904 | 241,349 | |||||||
Total assets |
$ | 3,989,760 | $ | 3,701,475 | ||||
LIABILITIES AND EQUITY |
||||||||
Current liabilities: |
||||||||
Accounts payable (HEP: $10,325 and $10,238, respectively) |
$ | 1,498,508 | $ | 1,317,446 | ||||
Accrued liabilities (HEP: $13,691 and $21,206, respectively) |
76,734 | 72,409 | ||||||
Total current liabilities |
1,575,242 | 1,389,855 | ||||||
Long-term debt (HEP: $505,918 and $482,271, respectively) |
834,213 | 810,561 | ||||||
Deferred income taxes |
131,698 | 131,935 | ||||||
Other long-term liabilities (HEP: $9,511 and $10,809, respectively) |
80,657 | 80,985 | ||||||
Equity: |
||||||||
Holly Corporation stockholders equity: |
||||||||
Preferred stock, $1.00 par value 1,000,000 shares authorized; none issued |
| | ||||||
Common stock $.01 par value 160,000,000 shares authorized; 76,346,432 shares
issued as of March 31, 2011 and December 31, 2010 |
763 | 763 | ||||||
Additional capital |
193,121 | 194,378 | ||||||
Retained earnings |
1,283,021 | 1,206,328 | ||||||
Accumulated other comprehensive loss |
(25,866 | ) | (26,246 | ) | ||||
Common stock held in treasury, at cost 23,034,159 and 23,081,744 shares as of March
31, 2011
and December 31, 2010, respectively |
(677,253 | ) | (677,804 | ) | ||||
Total Holly Corporation stockholders equity |
773,786 | 697,419 | ||||||
Noncontrolling interest |
594,164 | 590,720 | ||||||
Total equity |
1,367,950 | 1,288,139 | ||||||
Total liabilities and equity |
$ | 3,989,760 | $ | 3,701,475 | ||||
Parenthetical amounts represent asset and liability balances attributable to Holly Energy
Partners, L.P. (HEP) as of March 31, 2011 and December 31, 2010. HEP is a consolidated variable
interest entity.
See accompanying notes.
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Table of Contents
HOLLY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(Unaudited)
(In thousands, except per share data)
Three Months Ended | ||||||||
March 31, | ||||||||
2011 | 2010 | |||||||
Sales and other revenues |
$ | 2,326,585 | $ | 1,874,290 | ||||
Operating costs and expenses: |
||||||||
Cost of products sold (exclusive of depreciation and amortization) |
1,984,617 | 1,723,864 | ||||||
Operating expenses (exclusive of depreciation and amortization) |
134,743 | 127,544 | ||||||
General and administrative expenses (exclusive of depreciation and amortization) |
16,818 | 17,869 | ||||||
Depreciation and amortization |
31,308 | 27,757 | ||||||
Total operating costs and expenses |
2,167,486 | 1,897,034 | ||||||
Income (loss) from operations |
159,099 | (22,744 | ) | |||||
Other income (expense): |
||||||||
Equity in earnings of SLC Pipeline |
740 | 481 | ||||||
Interest income |
85 | 59 | ||||||
Interest expense |
(16,204 | ) | (17,722 | ) | ||||
Merger transaction costs |
(3,698 | ) | | |||||
(19,077 | ) | (17,182 | ) | |||||
Income (loss) before income taxes |
140,022 | (39,926 | ) | |||||
Income tax provision (benefit): |
||||||||
Current |
49,489 | 5,361 | ||||||
Deferred |
(478 | ) | (22,033 | ) | ||||
49,011 | (16,672 | ) | ||||||
Net income (loss) |
91,011 | (23,254 | ) | |||||
Less net income attributable to noncontrolling interest |
6,317 | 4,840 | ||||||
Net income (loss) attributable to Holly Corporation stockholders |
$ | 84,694 | $ | (28,094 | ) | |||
Earnings per share attributable to Holly Corporation stockholders: |
||||||||
Basic |
$ | 1.59 | $ | (0.53 | ) | |||
Diluted |
$ | 1.58 | $ | (0.53 | ) | |||
Cash dividends declared per common share |
$ | 0.15 | $ | 0.15 | ||||
Average number of common shares outstanding: |
||||||||
Basic |
53,307 | 53,094 | ||||||
Diluted |
53,633 | 53,094 |
See accompanying notes.
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Table of Contents
HOLLY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)
(Unaudited)
(In thousands)
Three Months Ended | ||||||||
March 31, | ||||||||
2011 | 2010 | |||||||
Cash flows from operating activities: |
||||||||
Net income (loss) |
$ | 91,011 | $ | (23,254 | ) | |||
Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||
Depreciation and amortization |
31,308 | 27,757 | ||||||
SLC Pipeline earnings, net of distributions |
(365 | ) | (481 | ) | ||||
Deferred income taxes |
(478 | ) | (22,033 | ) | ||||
Equity based compensation expense |
1,754 | 2,907 | ||||||
Change in fair value derivative instruments |
1,092 | 1,464 | ||||||
(Increase) decrease in current assets: |
||||||||
Accounts receivable |
(159,138 | ) | (121,085 | ) | ||||
Inventories |
(73,089 | ) | (117,509 | ) | ||||
Income taxes receivable |
48,992 | 7,824 | ||||||
Prepayments and other |
6,978 | (30,420 | ) | |||||
Current assets of discontinued operations |
| 2,195 | ||||||
Increase (decrease) in current liabilities: |
||||||||
Accounts payable |
181,045 | 180,298 | ||||||
Accrued liabilities |
14,155 | 7,590 | ||||||
Turnaround expenditures |
(16,924 | ) | (7,257 | ) | ||||
Other, net |
4,201 | 1,980 | ||||||
Net cash provided by (used for) operating activities |
130,542 | (90,024 | ) | |||||
Cash flows from investing activities: |
||||||||
Additions to properties, plants and equipment Holly Corporation |
(62,563 | ) | (29,187 | ) | ||||
Additions to properties, plants and equipment Holly Energy Partners |
(11,475 | ) | (1,911 | ) | ||||
Purchases of marketable securities |
(98,937 | ) | | |||||
Sales and maturities of marketable securities |
31,925 | | ||||||
Net cash used for investing activities |
(141,050 | ) | (31,098 | ) | ||||
Cash flows from financing activities: |
||||||||
Borrowings under credit agreement Holly Corporation |
| 310,000 | ||||||
Repayments under credit agreement Holly Corporation |
| (310,000 | ) | |||||
Borrowings under credit agreement Holly Energy Partners |
30,000 | 33,000 | ||||||
Repayments under credit agreement Holly Energy Partners |
(7,000 | ) | (68,000 | ) | ||||
Proceeds from issuance of senior notes Holly Energy Partners |
| 147,540 | ||||||
Repayments under financing obligation Holly Corporation |
(277 | ) | (246 | ) | ||||
Purchase of treasury stock |
(2,051 | ) | (1,055 | ) | ||||
Contribution from joint venture partner |
8,500 | 1,250 | ||||||
Dividends |
(7,984 | ) | (7,926 | ) | ||||
Distributions to noncontrolling interest |
(12,485 | ) | (11,963 | ) | ||||
Excess tax benefit (expense) from equity based compensation |
261 | (1,045 | ) | |||||
Purchase of units for restricted grants Holly Energy Partners |
(399 | ) | (1,745 | ) | ||||
Deferred financing costs |
(3,044 | ) | (56 | ) | ||||
Issuance of common stock upon exercise of options |
| 61 | ||||||
Net cash provided by financing activities |
5,521 | 89,815 | ||||||
Cash and cash equivalents: |
||||||||
Decrease for the period |
(4,987 | ) | (31,307 | ) | ||||
Beginning of period |
229,101 | 124,596 | ||||||
End of period |
$ | 224,114 | $ | 93,289 | ||||
Supplemental disclosure of cash flow information: |
||||||||
Cash paid during the period for: |
||||||||
Interest |
$ | 12,602 | $ | 11,879 | ||||
Income taxes |
$ | 8 | $ | |
See accompanying notes.
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Table of Contents
HOLLY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited)
(In thousands)
(Unaudited)
(In thousands)
Three Months Ended | ||||||||
March 31, | ||||||||
2011 | 2010 | |||||||
Net income (loss) |
$ | 91,011 | $ | (23,254 | ) | |||
Other comprehensive income (loss): |
||||||||
Unrealized gain on available-for-sale securities |
142 | 244 | ||||||
Hedging instruments: |
||||||||
Change in fair value of cash flow hedging instruments |
1,321 | (1,362 | ) | |||||
Other comprehensive income (loss) before income taxes |
1,463 | (1,118 | ) | |||||
Income tax expense (benefit) |
242 | 318 | ||||||
Other comprehensive income (loss) |
1,221 | (1,436 | ) | |||||
Total comprehensive income (loss) |
92,232 | (24,690 | ) | |||||
Less noncontrolling interest in comprehensive income |
7,159 | 2,904 | ||||||
Comprehensive income (loss) attributable to Holly Corporation stockholders |
$ | 85,073 | $ | (27,594 | ) | |||
See accompanying notes.
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Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(Unaudited)
NOTE 1: Description of Business and Presentation of Financial Statements
References herein to Holly Corporation include Holly Corporation and its consolidated subsidiaries.
In accordance with the Securities and Exchange Commissions (SEC) Plain English guidelines,
this Quarterly Report on Form 10-Q has been written in the first person. In this document, the
words we, our, ours and us refer only to Holly Corporation and its consolidated
subsidiaries or to Holly Corporation or an individual subsidiary and not to any other person. The
words we, our, ours and us generally include HEP and its subsidiaries as consolidated
subsidiaries of Holly Corporation with certain exceptions where there are transactions or
obligations between HEP and Holly Corporation or its other subsidiaries. These financial
statements contain certain disclosures of agreements that are specific to HEP and its consolidated
subsidiaries and do not necessarily represent obligations of Holly Corporation. When used in
descriptions of agreements and transactions, HEP refers to HEP and its consolidated subsidiaries.
As of March 31, 2011, we:
| owned and operated three refineries consisting of a petroleum refinery in Artesia, New Mexico that is operated in conjunction with crude oil distillation and vacuum distillation and other facilities situated 65 miles away in Lovington, New Mexico (collectively, the Navajo Refinery), a refinery in Woods Cross, Utah (the Woods Cross Refinery) and our two refinery facilities located in Tulsa, Oklahoma (collectively, operated as the Tulsa Refinery); | ||
| owned and operated Holly Asphalt Company (Holly Asphalt) which manufactures and markets asphalt products from various terminals in Arizona, New Mexico and Texas; | ||
| owned a 75% interest in a 12-inch refined products pipeline project from Salt Lake City, Utah to Las Vegas, Nevada, together with terminal facilities in the Cedar City, Utah and North Las Vegas areas (the UNEV Pipeline); and | ||
| owned a 34% interest in HEP, a consolidated variable interest entity (VIE), which includes our 2% general partner interest. HEP has logistic assets including petroleum product and crude oil pipelines located in Texas, New Mexico, Oklahoma and Utah; ten refined product terminals; a jet fuel terminal; loading rack facilities at each of our three refineries, a refined products tank farm facility and on-site crude oil tankage at our Navajo, Woods Cross and Tulsa Refineries. Additionally, HEP owns a 25% interest in SLC Pipeline LLC (SLC Pipeline), a new 95-mile intrastate pipeline system that serves refineries in the Salt Lake City area. |
We have prepared these consolidated financial statements without audit. In managements opinion,
these consolidated financial statements include all normal recurring adjustments necessary for a
fair presentation of our consolidated financial position as of March 31, 2011, the consolidated
results of operations and comprehensive income (loss) for the three months ended March 31, 2011 and
2010 and consolidated cash flows for the three months ended March 31, 2011 and 2010 in accordance
with the rules and regulations of the SEC. Although certain notes and other information required
by generally accepted accounting principles in the United States (GAAP) have been condensed or
omitted, we believe that the disclosures in these consolidated financial statements are adequate to
make the information presented not misleading. These consolidated financial statements should be
read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2010 filed
with the SEC.
Our results of operations for the first three months of 2011 are not necessarily indicative of the
results to be expected for the full year.
Accounts Receivable
Our accounts receivable consist of amounts due from customers that are primarily companies in the
petroleum industry. Credit is extended based on our evaluation of the customers financial
condition and in certain circumstances, collateral, such as a letter of credit or guarantee, is
required. Credit losses are charged to income
- 10 -
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when accounts are deemed uncollectible and
historically have been minimal. At March 31, 2011, our allowance for doubtful accounts reserve was
$2.4 million.
Inventories
We use the last-in, first-out (LIFO) method of valuing inventory. Under the LIFO method, an
actual valuation of inventory can only be made at the end of each year based on the inventory
levels at that time. Accordingly, interim
LIFO calculations are based on managements estimates of expected year-end inventory levels and are
subject to the final year-end LIFO inventory valuation.
NOTE 2: Pending Holly Frontier Merger
On February 21, 2011, we entered into a merger agreement providing for a merger of equals
business combination of us and Frontier Oil Corporation (Frontier). Subject to the terms and
conditions of the merger agreement which has been approved unanimously by both our and Frontiers
board of directors, Frontier shareholders will receive 0.4811 shares of our common stock for each
share of Frontier common stock if the merger is completed. Completion of the merger is subject to
certain conditions, including, among others, (i) approval by our stockholders of the issuance of
our common stock to Frontiers stockholders in connection with the merger, (ii) adoption of the
merger agreement by Frontiers stockholders, (iii) the expiration or termination of the applicable
waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, (iv) the
registration statement on Form S-4 used to register the common stock to be issued as consideration
for the merger having been declared effective by the SEC and (v) the entry into a new credit
facility for the combined company.
In March 2011, the Federal Trade Commission (FTC) granted early termination of its
Hart-Scott-Rodino antitrust review of the proposed merger.
NOTE 3: Holly Energy Partners
HEP, a consolidated VIE, is a publicly held master limited partnership that was formed to acquire,
own and operate the petroleum product and crude oil pipeline and terminal, tankage and loading rack
facilities that support our refining and marketing operations in west Texas, New Mexico, Utah,
Oklahoma, Idaho and Arizona. HEP also owns and operates refined product pipelines and terminals,
located primarily in Texas, that service Alon USA, Inc.s (Alon) refinery in Big Spring, Texas.
As of March 31, 2011, we owned a 34% interest in HEP, including the 2% general partner interest.
We are HEPs primary beneficiary and therefore we consolidate HEP. See Note 17 for supplemental
guarantor/non-guarantor financial information, including HEP balances included in these
consolidated financial statements. All intercompany transactions with HEP are eliminated in our
consolidated balances.
HEP has two primary customers (including us) and generates revenues by charging tariffs for
transporting petroleum products and crude oil though its pipelines, by charging fees for
terminalling refined products and other hydrocarbons, and storing and providing other services at
its storage tanks and terminals. Under our long-term transportation agreements with HEP (discussed
further below), we accounted for 76% of HEPs total revenues for the three months ended March 31,
2011. We do not provide financial or equity support through any liquidity arrangements and /or
guarantees to HEP.
HEP has outstanding debt under a senior secured revolving credit agreement and its senior notes.
With the exception of the assets of HEP Logistics Holdings, L.P., one of our wholly-owned
subsidiaries and HEPs general partner, HEPs creditors have no recourse to our assets. Any
recourse to HEPs general partner would be limited to the extent of HEP Logistics Holdings, L.P.s
assets, which other than its investment in HEP, are not significant. Furthermore, our creditors
have no recourse to the assets of HEP and its consolidated subsidiaries. See Note 10 for a
description of HEPs debt obligations.
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We have pledged 6,000,000 of our HEP common units to collateralize certain crude oil purchases in
2011.
HEP has risk associated with its operations. If a major shipper of HEP were to terminate its
contracts or fail to meet desired shipping levels for an extended period time, revenue would be
reduced and HEP could suffer substantial losses to the extent that a new customer is not found. In
the event that HEP incurs a loss, our operating results will reflect HEPs loss, net of
intercompany eliminations, to the extent of our ownership interest in HEP at that point in time.
2010 Tulsa East / Lovington Storage Asset Transaction
On March 31, 2010, HEP acquired from us certain storage assets for $93 million, consisting of
hydrocarbon storage tanks having approximately 2 million barrels of storage capacity, a rail
loading rack and a truck unloading rack located at our Tulsa Refinery east facility and an asphalt
loading rack facility located at our Navajo Refinery facility located in Lovington, New Mexico.
Transportation Agreements
HEP serves our refineries in New Mexico, Utah and Oklahoma under the following long-term pipeline
and terminal, tankage and throughput agreements:
| HEP PTA (pipelines and terminals throughput agreement expiring in 2019 that relates to the pipelines and terminal assets that we contributed to HEP upon its initial public offering in 2004); | ||
| HEP IPA (intermediate pipelines throughput agreement expiring in 2024 that relates to the intermediate pipelines sold to HEP in 2005 and 2009); | ||
| HEP CPTA (crude pipelines and tankage throughput agreement expiring in 2023 that relates to the crude pipelines and tankage assets sold to HEP in 2008); | ||
| HEP PTTA (pipeline, tankage and loading rack throughput agreement expiring in 2024 that relates to the Tulsa east storage tank and loading rack facilities acquired in 2009 and 2010); | ||
| HEP RPA (pipeline throughput agreement expiring in 2024 that relates to the Roadrunner Pipeline sold to HEP in 2009); | ||
| HEP ETA (equipment and throughput agreement expiring in 2024 that relates to the Tulsa west loading rack facilities sold to HEP in 2009); | ||
| HEP NPA (natural gas pipeline throughput agreement expiring in 2024); and | ||
| HEP ATA (loading rack throughput agreement expiring in 2025 that relates to the Lovington asphalt loading rack facility sold to HEP in March 2010). |
Under these agreements, we pay HEP fees to transport, store and throughput volumes of refined
product and crude oil on HEPs pipeline and terminal, tankage and loading rack facilities that
result in minimum annual payments to HEP. These minimum annual payments are subject to annual
tariff rate adjustments on July 1, based on the Producer Price Index (PPI) or Federal Energy
Regulatory Commission (FERC) index, but with the exception of the HEP IPA, generally will not
decrease as a result of a decrease in the PPI or FERC index. As of March 31, 2011, these
agreements result in minimum annualized payments to HEP of $133 million.
NOTE 4: Financial Instruments
Our financial instruments consist of cash and cash equivalents, investments in marketable
securities, accounts receivable, accounts payable, debt and derivative instruments. The carrying
amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair
value due to the short-term maturity of these instruments.
Debt consists of borrowings outstanding under HEPs $275 million revolving credit agreement (the
HEP Credit Agreement), our 9.875% senior notes due 2017 (the Holly 9.875% Senior Notes), HEPs
6.25% senior notes due 2015 (the HEP 6.25% Senior Notes) and HEPs 8.25% senior notes due 2018 (the HEP 8.25% Senior
- 12 -
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Notes). The $182 million carrying amount of borrowings outstanding under
the HEP Credit Agreement approximates fair value as interest rates are reset frequently using
current interest rates. At March 31, 2011, the estimated fair values of the Holly 9.875% Senior
Notes, HEP 6.25% Senior Notes and HEP 8.25% Senior Notes were $338.3 million, $185 million and
$160.5 million, respectively. These fair value estimates are based on market quotes provided from
a third-party bank. See Note 10 for additional information on these debt instruments.
Fair value measurements are derived using inputs (assumptions that market participants would use in
pricing an asset or liability, including assumptions about risk). GAAP categorizes inputs used in
fair value measurements into three broad levels as follows:
| (Level 1) Quoted prices in active markets for identical assets or liabilities. | ||
| (Level 2) Observable inputs other than quoted prices included in Level 1, such as quoted prices for similar assets and liabilities in active markets, similar assets and liabilities in markets that are not active or can be corroborated by observable market data. | ||
| (Level 3) Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. This includes valuation techniques that involve significant unobservable inputs. |
Our investments in marketable securities are measured at fair value using quoted market prices, a
Level 1 input. See Note 7 for additional information on our investments in marketable securities,
including fair value measurements.
We have commodity price swaps and HEP has an interest rate swap that is measured at fair value on a
recurring
basis using Level 2 inputs. With respect to these instruments, fair value is based on the net
present value of expected future cash flows related to both variable and fixed rate legs of the
respective swap agreements. The measurements are computed using market-based observable inputs,
quoted forward commodity prices with respect to our commodity price swaps and the forward London
Interbank Offered Rate (LIBOR) yield curve with respect to HEPs interest rate swap. See Note 11
for additional information on these swap contracts, including fair value measurements.
NOTE 5: Earnings Per Share
Basic earnings per share is calculated as net income attributable to Holly Corporation stockholders
divided by the average number of shares of common stock outstanding. Diluted earnings per share
assumes, when dilutive, the issuance of the net incremental shares from stock options, variable
restricted shares and variable performance shares. The following is a reconciliation of the
denominators of the basic and diluted per share computations for net income attributable to Holly
Corporation stockholders:
Three Months Ended | ||||||||
March 31, | ||||||||
2011 | 2010 | |||||||
(In thousands, except per share data) | ||||||||
Net income attributable to Holly Corporation stockholders |
$ | 84,694 | $ | (28,094 | ) | |||
Average number of shares of common stock outstanding |
53,307 | 53,094 | ||||||
Effect of dilutive stock options, variable restricted shares and
performance share units |
326 | | ||||||
Average number of shares of common stock outstanding assuming dilution |
53,633 | 53,094 | ||||||
Basic earnings per share |
$ | 1.59 | $ | (0.53 | ) | |||
Diluted earnings per share |
$ | 1.58 | $ | (0.53 | ) | |||
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NOTE 6: Stock-Based Compensation
On March 31, 2011, we had two principal share-based compensation plans that are described below
(collectively, the Long-Term Incentive Compensation Plan). The compensation cost that has been
charged against income for these plans was $1.1 million and $1.9 million for the three months ended
March 31, 2011 and 2010, respectively. The total income tax benefit recognized in the income
statement for share-based compensation arrangements was $0.4 million and $0.8 million for the three
months ended March 31, 2011 and 2010, respectively. Our current accounting policy for the
recognition of compensation expense for awards with pro-rata vesting (substantially all of our
awards) is to expense the costs pro-rata over the vesting periods. We have proposed to a vote of
shareholders, an amendment to the Long-Term Incentive Compensation Plan that will extend the term
of the plan and our ability to grant equity compensation awards until December 31, 2020.
Additionally, HEP maintains share-based compensation plans for HEP directors and select Holly
Logistic Services, L.L.C. executives and employees. Compensation cost attributable to HEPs
share-based compensation plans was $0.7 million and $1 million for the three months ended March 31,
2011 and 2010, respectively.
Restricted Stock
Under our Long-Term Incentive Compensation Plan, we grant certain officers, other key employees and
outside directors restricted stock awards with substantially all awards vesting generally over a
period of one to five years. Although ownership of the shares does not transfer to the recipients
until after the shares vest, recipients generally have dividend rights on these shares from the
date of grant. The vesting for certain key executives is contingent upon certain performance
targets being realized. The fair value of each share of restricted stock awarded, including the
shares issued to the key executives, was measured based on the market price as of the date of grant
and is being amortized over the respective vesting period.
A summary of restricted stock activity and changes during the three months ended March 31, 2011 is
presented below:
Weighted-Average | ||||||||||||
Grant Date Fair | Aggregate Intrinsic | |||||||||||
Restricted Stock | Grants | Value | Value ($000) | |||||||||
Outstanding at January 1, 2011 (non-vested) |
346,996 | $ | 29.31 | |||||||||
Vesting and transfer of ownership to recipients |
(87,232 | ) | 29.80 | |||||||||
Forfeited |
(12,965 | ) | 52.02 | |||||||||
Outstanding at March 31, 2011 (non-vested) |
246,799 | $ | 27.94 | $ | 14,996 | |||||||
The total fair value of restricted stock vested and transferred to recipients during the three
months ended March 31, 2011 and 2010 was $2.6 million and $1.6 million, respectively. As of March
31, 2011, there was $1.7 million of total unrecognized compensation cost related to non-vested
restricted stock grants. That cost is expected to be recognized over a weighted-average period of
0.7 years.
Performance Share Units
Under our Long-Term Incentive Compensation Plan, we grant certain officers and other key employees
performance share units, which are payable in stock upon meeting certain criteria over the service
period, and generally vest over a period of one to three years. Under the terms of our performance
share unit grants, awards are subject to financial performance criteria.
The fair value of each performance share unit award is computed using the grant date closing stock
price of each respective award grant and will apply to the number of units ultimately awarded. The
number of shares ultimately issued for each award will be based on our financial performance as
compared to peer group companies over the performance period and can range from zero to 200%. As
of March 31, 2011, estimated share payouts for outstanding non-vested performance share unit awards
ranged from 130% to 150%.
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A summary of performance share unit activity and changes during the three months ended March 31,
2011 is presented below:
Performance Share Units | Grants | |||
Outstanding at January 1, 2011 (non-vested) |
278,093 | |||
Vesting and transfer of ownership to recipients |
(53,962 | ) | ||
Outstanding at March 31, 2011 (non-vested) |
224,131 | |||
For the three months ended March 31, 2011, we issued 75,007 shares of our common stock having
a fair value of $3.6 million related to vested performance share units, representing a 139% payout.
Based on the weighted average grant date fair value of $25.82, there was $6.6 million of total
unrecognized compensation cost related to non-vested performance share units. That cost is
expected to be recognized over a weighted-average period of 1.2 years.
NOTE 7: Cash and Cash Equivalents and Investments in Marketable Securities
Our investment portfolio at March 31, 2011, consisted of cash, cash equivalents and investments in
debt securities primarily issued by government entities. We also hold 1,000,000 shares of
Connacher Oil and Gas Limited common stock that were received as partial consideration upon our
sale of our Montana refinery in 2006.
We invest in highly-rated marketable debt securities, primarily issued by government entities that
have maturities at the date of purchase of greater than three months. We also invest in other
marketable debt securities with the maximum maturity of any individual issue not greater than two
years from the date of purchase. All of these instruments including investments in equity
securities are classified as available-for-sale, and as a result, are reported at fair value using
quoted market prices. Interest income is recorded as earned. Unrealized gains and losses, net of
related income taxes, are considered temporary and are reported as a component of accumulated other
comprehensive income. For investments in an unrealized loss position that are determined to be
other than temporary, unrealized losses are reclassified out of accumulated other comprehensive
income and into earnings as an impairment loss. Upon sale, realized gains and losses on the sale
of marketable securities are computed based on the specific identification of the underlying cost
of the securities sold and the unrealized gains and losses previously reported in other
comprehensive income are reclassified to current earnings.
The following is a summary of our available-for-sale securities:
Available-for-Sale Securities | ||||||||||||
Estimated Fair Value | ||||||||||||
Gross Unrealized | (Net Carrying | |||||||||||
Amortized Cost | Gain | Amount) | ||||||||||
(In thousands) | ||||||||||||
March 31, 2011 |
||||||||||||
State and political subdivision debt securities |
$ | 67,012 | $ | 8 | $ | 67,020 | ||||||
Equity securities |
610 | 867 | 1,477 | |||||||||
Total marketable securities |
$ | 67,622 | $ | 875 | $ | 68,497 | ||||||
December 31, 2010 |
||||||||||||
Equity securities |
$ | 610 | $ | 733 | $ | 1,343 | ||||||
For the three months ended March 31, 2011, we invested $98.9 million in marketable debt
securities and received a total of $31.9 million related to sales and maturities of our investments
in marketable debt securities.
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NOTE 8: Inventories
Inventory consists of the following components:
March 31, | December 31, | |||||||
2011 | 2010 | |||||||
(In thousands) | ||||||||
Crude oil |
$ | 83,513 | $ | 96,570 | ||||
Other raw materials and unfinished products (1) |
69,485 | 68,792 | ||||||
Finished products (2) |
271,787 | 188,274 | ||||||
Process chemicals (3) |
22,532 | 22,512 | ||||||
Repairs and maintenance supplies and other |
26,139 | 24,219 | ||||||
Total inventory |
$ | 473,456 | $ | 400,367 | ||||
(1) | Other raw materials and unfinished products include feedstocks and blendstocks, other than crude. | |
(2) | Finished products include gasolines, jet fuels, diesels, lubricants, asphalts, LPGs and residual fuels. | |
(3) | Process chemicals include catalysts, additives and other chemicals. |
NOTE 9: Environmental
Consistent with our accounting policy for environmental remediation costs, we expensed $1.1 million
and $1.4 million for the three months ended March 31, 2011 and 2010, respectively, for
environmental remediation obligations. The accrued environmental liability reflected in the
consolidated balance sheets was $25 million and $26.2 million at March 31, 2011 and December 31,
2010, respectively, of which $19.4 million and $20.4 million, respectively, were classified as
other long-term liabilities. Costs of future expenditures for environmental remediation that are
expected to be incurred over the next several years are not discounted to their present value.
NOTE 10: Debt
Credit Facilities
We have a $400 million senior secured credit agreement expiring in March 2013 (the Holly Credit
Agreement) with Bank of America, N.A. as administrative agent and one of a syndicate of lenders.
The Holly Credit Agreement may be used to fund working capital requirements, capital expenditures,
permitted acquisitions or other general corporate purposes. We were in compliance with all
covenants at March 31, 2011. At March 31, 2011, we had no outstanding borrowings and outstanding
letters of credit totaling $70 million under the Holly Credit Agreement. At that level of usage,
the unused commitment was $330 million at March 31, 2011.
The $275 million HEP Credit Agreement is available to fund capital expenditures, investments,
acquisitions, distribution payments and working capital and for general partnership purposes. In
February 2011, HEP amended its previous credit agreement (expiring in August 2011), slightly,
reducing the size of the credit facility from $300 million to $275 million. The size was reduced
based on managements review of past and forecasted utilization of the facility. The HEP Credit
Agreement expires in February 2016; however, in the event that the HEP 6.25% Senior Notes
(discussed below) are not repurchased, refinanced, extended or repaid prior to September 1, 2014,
the HEP Credit Agreement shall expire on that date.
HEPs obligations under the HEP Credit Agreement are collateralized by substantially all of HEPs
assets (presented
parenthetically in our Consolidated Balance Sheets). Indebtedness under the HEP Credit Agreement
is recourse to HEP Logistics Holdings, L.P., its general partner, and guaranteed by HEPs material,
wholly-owned subsidiaries. Any recourse to the general partner would be limited to the extent of
HEP Logistics Holdings, L.P.s assets, which other than its investment in HEP, are not significant.
HEPs creditors have no other recourse to our assets. Furthermore, our creditors have no recourse
to the assets of HEP and its consolidated subsidiaries.
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Holly Senior Notes Due 2017
Our $300 million 9.875% Senior Notes mature in June 2017 and are unsecured and impose certain
restrictive covenants, including limitations on our ability to incur additional debt, incur liens,
enter into sale-and-leaseback transactions, pay dividends, enter into mergers, sell assets and
enter into certain transactions with affiliates. At any time when the Holly 9.875% Senior Notes
are rated investment grade by both Moodys and Standard & Poors and no default or event of default
exists, we will not be subject to many of the foregoing covenants. Additionally, we have certain
redemption rights under the Holly 9.875% Senior Notes.
HEP Senior Notes Due 2018 and 2015
In March 2010, HEP issued $150 million in aggregate principal amount of 8.25% Senior Notes which
mature in March 2018. A portion of the $147.5 million in net proceeds received was used to fund
HEPs $93 million purchase of certain storage assets at our Tulsa Refinery east facility and Navajo
Refinery Lovington facility on March 31, 2010. Additionally, HEP used a portion to repay $42
million in outstanding HEP Credit Agreement borrowings, with the remaining proceeds available for
general partnership purposes, including working capital and capital expenditures.
The HEP 6.25% Senior Notes having an aggregate principal amount of $185 million outstanding mature
in March 2015 and are registered with the SEC. The HEP 6.25% Senior Notes and HEP 8.25% Senior
Notes (collectively, the HEP Senior Notes) are unsecured and impose certain restrictive
covenants, including limitations on HEPs ability to incur additional indebtedness, make
investments, sell assets, incur certain liens, pay distributions, enter into transactions with
affiliates, and enter into mergers. At any time when the HEP Senior Notes are rated investment
grade by both Moodys and Standard & Poors and no default or event of default exists, HEP will not
be subject to many of the foregoing covenants. Additionally, HEP has certain redemption rights
under the HEP Senior Notes.
Indebtedness under the HEP Senior Notes is recourse to HEP Logistics Holdings, L.P., its general
partner, and guaranteed by HEPs wholly-owned subsidiaries. However, any recourse to the general
partner would be limited to the extent of HEP Logistics Holdings, L.P.s assets, which other than
its investment in HEP, are not significant. HEPs creditors have no other recourse to our assets.
Furthermore, our creditors have no recourse to the assets of HEP and its consolidated subsidiaries.
Holly Financing Obligation
In October 2009, we sold approximately 400,000 barrels of crude oil tankage at our Tulsa Refinery
west facility as well as certain crude oil pipeline receiving facilities to Plains for $40 million
in cash. In connection with this transaction, we entered into a 15-year lease agreement with
Plains, whereby we agreed to pay a fixed monthly fee for the exclusive use of this tankage as well
as a fee for volumes received at the receiving facilities purchased by Plains. Additionally, we
have a margin sharing agreement with Plains under which we will equally share contango profits for
crude oil purchased by them and delivered to our Tulsa Refinery west facility for storage. Due to
our continuing involvement in these assets, this transaction has been accounted for as a financing
obligation. As a result, we retained these assets on our books and recorded a liability
representing the $40 million in proceeds received.
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The carrying amounts of long-term debt are as follows:
March 31, | December 31, | |||||||
2011 | 2010 | |||||||
(In thousands) | ||||||||
Holly 9.875% Senior Notes |
||||||||
Principal |
$ | 300,000 | $ | 300,000 | ||||
Unamortized discount |
(10,209 | ) | (10,491 | ) | ||||
289,791 | 289,509 | |||||||
Holly financing obligation |
||||||||
Principal |
38,504 | 38,781 | ||||||
Total Holly long-term debt |
328,295 | 328,290 | ||||||
HEP Credit Agreement |
182,000 | 159,000 | ||||||
HEP 6.25% Senior Notes |
||||||||
Principal |
185,000 | 185,000 | ||||||
Unamortized discount |
(10,304 | ) | (10,961 | ) | ||||
Unamortized premium dedesignated fair value hedge |
1,357 | 1,444 | ||||||
176,053 | 175,483 | |||||||
HEP 8.25% Senior Notes |
||||||||
Principal |
150,000 | 150,000 | ||||||
Unamortized discount |
(2,135 | ) | (2,212 | ) | ||||
147,865 | 147,788 | |||||||
Total HEP long-term debt |
505,918 | 482,271 | ||||||
Total long-term debt |
$ | 834,213 | $ | 810,561 | ||||
NOTE 11: Derivative Instruments and Hedging Activities
Commodity Price Risk Management
Our primary market risk is commodity price risk. We are exposed to market risks related to the
volatility in crude oil and refined products, as well as volatility in the price of natural gas
used in our refining operations.
We periodically enter into derivative contracts in the form of commodity price swaps to mitigate
price exposure with respect to:
| our inventory positions; | ||
| natural gas purchases; | ||
| costs of crude oil; | ||
| prices of refined products; and | ||
| our refining margins. |
As of March 31, 2011, we have outstanding commodity price swap contracts serving as economic hedges
to protect the value of a temporary crude oil inventory build of 105,000 barrels against price
volatility and to protect refining margins on forecasted sales of 6.2 million barrels of produced
gasoline. These contracts are measured quarterly at fair value with offsetting adjustments (gains /
losses) recorded directly to cost of products sold.
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Interest Rate Risk Management
HEP uses interest rate swaps to manage its exposure to interest rate risk.
As of March 31, 2011, HEP has an interest rate swap that hedges its exposure to the cash flow risk
caused by the effects of LIBOR changes on a $155 million HEP Credit Agreement advance. This
interest rate swap effectively converts $155 million of LIBOR based debt to fixed rate debt having
an interest rate of 3.74% plus an applicable margin, currently 2.5%, which equaled an effective
interest rate of 6.24% as of March 31, 2011. This interest rate swap contract has been designated
as a cash flow hedge and matures in February 2013.
This contract initially hedged variable LIBOR interest on $171 million in outstanding HEP Credit
Agreement debt. In May 2010, HEP repaid $16 million of the HEP Credit Agreement debt and also
settled a corresponding portion of
its interest rate swap agreement having a notional amount of $16 million for $1.1 million. Upon
payment, HEP reduced its swap liability and reclassified a $1.1 million charge from accumulated
other comprehensive loss to interest expense, representing the application of hedge accounting
prior to settlement.
The following table presents balance sheet locations and related fair values of outstanding
derivative instruments.
Balance Sheet | ||||||||||||
Derivative Instruments | Location | Fair Value | Location of Offsetting Balance | Offsetting Amount | ||||||||
(Dollars in thousands) | ||||||||||||
March 31, 2011 |
||||||||||||
Derivative designated as cash flow
hedging instrument: |
||||||||||||
Variable-to-fixed interest rate swap contract
($155 million LIBOR based debt interest
payments) |
Other long-term liabilities | $ | 8,743 | Accumulated other comprehensive loss | $ | 8,743 | ||||||
Derivatives not designated as hedging instruments: |
||||||||||||
Variable-to-fixed commodity price swap contracts
(various inventory positions) |
Prepayments and other current assets | $ | 6,555 | Cost of products sold (decrease) | $ | 6,555 | ||||||
Fixed/variable-to-variable/fixed commodity price
contracts (various inventory positions) |
Accrued liabilities | $ | 5,960 | Cost of products sold (increase) | $ | 5,960 | ||||||
December 31, 2010 |
||||||||||||
Derivative designated as cash flow
hedging instruments: |
||||||||||||
Variable-to-fixed commodity price swap contracts
(forecasted volumes of natural gas purchases) |
Accrued liabilities | $ | 38 | Accumulated other comprehensive loss | $ | 38 | ||||||
Variable-to-fixed interest rate swap contract
($155 million LIBOR based debt interest
payments) |
Other long-term liabilities | $ | 10,026 | Accumulated other comprehensive loss | $ | 10,026 | ||||||
Derivatives not designated as hedging instruments: |
||||||||||||
Fixed-to-variable rate swap contracts
(various inventory positions) |
Accrued liabilities | $ | 497 | Cost of products sold (increase) | $ | 497 | ||||||
For the three months ended March 31, 2011, maturities and fair value adjustments attributable
to our economic hedges resulted in a $3.7 million increase to costs of products sold.
For the three months ended March 31, 2010, HEP recognized $1.5 million in charges to interest
expense as a result of fair value changes to interest rate swap contracts that were settled in the
first quarter of 2010.
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NOTE 12: Equity
Changes to equity during the three months ended March 31, 2011 are presented below:
Holly | ||||||||||||
Corporation | ||||||||||||
Stockholders | Noncontrolling | Total | ||||||||||
Equity | Interest | Equity | ||||||||||
(In thousands) | ||||||||||||
Balance at December 31, 2010 |
$ | 697,419 | $ | 590,720 | $ | 1,288,139 | ||||||
Net income |
84,694 | 6,317 | 91,011 | |||||||||
Dividends |
(8,001 | ) | | (8,001 | ) | |||||||
Distributions to noncontrolling interest holders |
| (12,485 | ) | (12,485 | ) | |||||||
Other comprehensive income |
380 | 841 | 1,221 | |||||||||
Contribution from joint venture partner |
| 8,500 | 8,500 | |||||||||
Equity based compensation |
1,084 | 670 | 1,754 | |||||||||
Tax benefit from equity based compensation arrangements |
261 | | 261 | |||||||||
Purchase of HEP units for restricted grants |
| (399 | ) | (399 | ) | |||||||
Purchase of treasury stock (1) |
(2,051 | ) | | (2,051 | ) | |||||||
Balance at March 31, 2011 |
$ | 773,786 | $ | 594,164 | $ | 1,367,950 | ||||||
(1) | Includes 40,673 shares purchased under the terms of restricted stock agreements to provide funds for the payment of payroll and income taxes due at vesting of restricted stock. |
During the three months ended March 31, 2011, we repurchased shares of our common stock at
market price from certain executives and employees costing $2.1 million. These purchases were made
under the terms of restricted stock and performance share unit agreements to provide funds for the
payment of payroll and income taxes due at the vesting of restricted shares in the case of officers
and employees who did not elect to satisfy such taxes by other
means.
NOTE 13: Other Comprehensive Income (Loss)
The components and allocated tax effects of other comprehensive income (loss) are as follows:
Tax Expense | ||||||||||||
Before-Tax | (Benefit) | After-Tax | ||||||||||
(In thousands) | ||||||||||||
Three Months Ended March 31, 2011 |
||||||||||||
Unrealized gain on available-for-sale securities |
$ | 142 | $ | 55 | $ | 87 | ||||||
Unrealized gain on hedging activities |
1,321 | 187 | 1,134 | |||||||||
Other comprehensive loss |
1,463 | 242 | 1,221 | |||||||||
Less other comprehensive income attributable to noncontrolling interest |
841 | | 841 | |||||||||
Other comprehensive income attributable to Holly stockholders |
$ | 622 | $ | 242 | $ | 380 | ||||||
Three Months Ended March 31, 2010 |
||||||||||||
Unrealized gain on available-for-sale securities |
$ | 244 | $ | 94 | $ | 150 | ||||||
Unrealized loss on hedging activities |
(1,362 | ) | 224 | (1,586 | ) | |||||||
Other comprehensive loss |
(1,118 | ) | 318 | (1,436 | ) | |||||||
Less other comprehensive loss attributable to noncontrolling interest |
(1,936 | ) | | (1,936 | ) | |||||||
Other comprehensive income attributable to Holly stockholders |
$ | 818 | $ | 318 | $ | 500 | ||||||
The temporary unrealized gain on available-for-sale securities is due to changes in market
prices of securities.
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Accumulated other comprehensive loss in the equity section of our consolidated balance sheets
includes:
March 31, | December 31, | |||||||
2011 | 2010 | |||||||
(In thousands) | ||||||||
Pension obligation adjustment |
$ | (22,672 | ) | $ | (22,672 | ) | ||
Retiree medical obligation adjustment |
(1,894 | ) | (1,894 | ) | ||||
Unrealized gain on available-for-sale securities |
538 | 451 | ||||||
Unrealized loss on hedging activities, net of noncontrolling interest |
(1,838 | ) | (2,131 | ) | ||||
Accumulated other comprehensive loss |
$ | (25,866 | ) | $ | (26,246 | ) | ||
NOTE 14: Retirement Plan
We have a non-contributory defined benefit retirement plan that covers most of our employees who
were hired prior to January 1, 2007. Our policy is to make contributions annually of not less than
the minimum funding requirements of the Employee Retirement Income Security Act of 1974. Benefits
are based on the employees years of service and compensation.
The retirement plan is closed to employees hired subsequent to 2006 and not covered by collective
bargaining agreements with labor unions. To the extent a non-union employee was hired prior to
January 1, 2007, and elected to participate in automatic contributions features under our defined
contribution plan, their participation in future benefits of the retirement plan was frozen.
Effective July 1, 2010, the retirement plan was closed to all new employees covered by collective
bargaining agreements with labor unions. To the extent a union employee was hired prior to July 1,
2010, the employee may elect to continue their participation in the retirement plan or to
participate in our defined contribution plan whereby their participation in future benefits of the
retirement plan will be frozen.
The net periodic pension expense consisted of the following components:
Three Months Ended | ||||||||
March 31, | ||||||||
2011 | 2010 | |||||||
(In thousands) | ||||||||
Service cost benefit earned during the period |
$ | 1,267 | $ | 1,141 | ||||
Interest cost on projected benefit obligations |
1,281 | 1,286 | ||||||
Expected return on plan assets |
(1,339 | ) | (1,124 | ) | ||||
Amortization of prior service cost |
98 | 98 | ||||||
Amortization of net loss |
533 | 624 | ||||||
Net periodic pension expense |
$ | 1,840 | $ | 2,025 | ||||
The expected long-term annual rate of return on plan assets is 8.5%. This rate was used in
measuring 2011 and 2011 net periodic benefit cost. We expect to contribute between zero and $10
million to the retirement plan in 2011.
NOTE 15: Contingencies
In May 2007, the United States Court of Appeals for the District of Columbia Circuit (Court of
Appeals) issued its decision on petitions for review, brought by us and other parties, concerning
rulings by the FERC in proceedings brought by us and other parties against SFPP, L.P. (SFPP).
These proceedings relate to tariffs of common carrier pipelines, which are owned and operated by
SFPP, for shipments of refined products from El Paso, Texas to Tucson and Phoenix, Arizona and from
points in California to points in Arizona. We are one of several refiners that regularly utilize
the SFPP pipeline to ship refined products from El Paso, Texas to Tucson and Phoenix, Arizona on
SFPPs East Line. The Court of Appeals in its May 2007 decision approved a FERC position, which is
adverse to us, on the treatment of income taxes in the calculation of allowable rates for
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pipelines
operated by partnerships and ruled in our favor on an issue relating to our rights to reparations
when it is determined that certain tariffs we paid to SFPP in the past were too high. The case was
remanded to FERC and consolidated with other cases that together addressed SFPPs rates for the
period from January 1992 through May 2006. In 2003 we received an initial payment of $15.3 million
from SFPP as reparations for the period from 1992 through July 2000. On April 16, 2010, a
settlement among us, SFPP, and other shippers was filed with FERC for its approval. FERC approved
the settlement on May 28, 2010. Pursuant to the settlement, we received an additional settlement
payment of $8.6 million. This settlement finally resolves the amount of additional payments SFPP
owes us for the period January 1992 through May 2006.
We and other shippers also engaged in settlement discussions with SFPP relating to East Line
service in the FERC proceedings that address periods after May 2006. A partial settlement covering
the period June 2006 through November 2007, which became final in February 2008, resulted in a
payment from SFPP to us of $1.3 million in April 2008. On October 22, 2008, we and other shippers
jointly filed at the FERC with SFPP a settlement covering the period from December 2008 through
November 2010. The FERC approved the settlement on January 29, 2009. The settlement reduced SFPPs
current rates and required SFPP to make additional payments to us of $2.9 million, which were
received on May 18, 2009.
On June 2, 2009, SFPP notified us that it would terminate the October 22, 2008 settlement, as
provided under the settlement, effective August 31, 2009. On July 31, 2009, SFPP filed substantial
rate increases for East Line service to become effective September 1, 2009. We and several other
shippers filed protests at the FERC challenging the rate increase and asking the FERC to suspend
the effectiveness of the increased rates. On August 31, 2009, the FERC issued an order suspending
the effective date of the rate increase until January 1, 2010, on which date the rate increase was
placed into effect subject to refund, and setting the rate increase for a full evidentiary hearing
to be held in 2010. SFPP subsequently reduced its rates for the East Line service, effective
September 1, 2010. The rates placed in effect on January 1, 2010, and the lower rates put into
effect on September 1, 2010, remain subject to refund subject to the outcome of the evidentiary
hearing. We are not in a position to predict the ultimate outcome of the rate proceeding.
We are a party to various other litigation and proceedings which we believe, based on advice of
counsel, will not either individually or in the aggregate have a materially adverse impact on our
financial condition, results of operations or cash flows.
NOTE 16: Segment Information
Our operations are currently organized into two reportable segments, Refining and HEP. Our
operations that are not included in the Refining and HEP segments are included in Corporate and
Other. Intersegment transactions are eliminated in our consolidated financial statements and are
included in Consolidations and Eliminations.
The Refining segment includes the operations of our Navajo, Woods Cross, and Tulsa Refineries and
Holly Asphalt and involves the purchase and refining of crude oil and wholesale and branded
marketing of refined products, such as gasoline, diesel fuel and jet fuel. These petroleum
products are primarily marketed in the Southwest, Rocky Mountain and Mid-Continent regions of the
United States and northern Mexico. Additionally, the Refining segment includes specialty lubricant
products produced at our Tulsa Refinery that are marketed throughout North America and are
distributed in Central and South America. Holly Asphalt manufactures and markets asphalt and
asphalt
products in Arizona, New Mexico, Oklahoma, Kansas, Missouri, Texas and northern Mexico.
The HEP segment includes all of the operations of HEP, a consolidated VIE, which owns and operates
a system of petroleum product and crude gathering pipelines in Texas, New Mexico, Oklahoma and
Utah, distribution terminals in Texas, New Mexico, Arizona, Utah, Idaho, and Washington and
refinery tankage in New Mexico, Utah and Oklahoma. Revenues are generated by charging tariffs for
transporting petroleum products and crude oil through its pipelines, by leasing certain pipeline
capacity to Alon USA, Inc., by charging fees for terminalling refined products and other
hydrocarbons and storing and providing other services at its storage tanks and terminals. The HEP
segment also includes a 25% interest in SLC Pipeline that services refineries in the Salt Lake
- 22 -
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City, Utah area. Revenues from the HEP segment are earned through transactions with unaffiliated
parties for pipeline transportation, rental and terminalling operations as well as revenues
relating to pipeline transportation services provided for our refining operations. Our revaluation
of HEPs assets and liabilities at March 1, 2008 (date of reconsolidation) resulted in basis
adjustments to our consolidated HEP balances. Therefore, our reported amounts for the HEP segment
may not agree to amounts reported in HEPs periodic public filings.
The accounting policies for our segments are the same as those described in the summary of
significant accounting policies in our Annual Report on Form 10-K for the year ended December 31,
2010.
Consolidations and | ||||||||||||||||||||
Refining | HEP(1) | Corporate and Other | Eliminations | Consolidated Total | ||||||||||||||||
(In thousands) | ||||||||||||||||||||
Three Months Ended March 31, 2011 |
||||||||||||||||||||
Sales and other revenues |
$ | 2,315,092 | $ | 45,005 | $ | 648 | $ | (34,160 | ) | $ | 2,326,585 | |||||||||
Depreciation and amortization |
$ | 22,983 | $ | 7,235 | $ | 1,297 | $ | (207 | ) | $ | 31,308 | |||||||||
Income (loss) from operations |
$ | 152,104 | $ | 23,611 | $ | (16,098 | ) | $ | (518 | ) | $ | 159,099 | ||||||||
Capital expenditures |
$ | 22,965 | $ | 11,475 | $ | 39,598 | $ | | $ | 74,038 | ||||||||||
Three Months Ended March 31, 2010 |
||||||||||||||||||||
Sales and other revenues |
$ | 1,867,174 | $ | 40,689 | $ | 66 | $ | (33,639 | ) | $ | 1,874,290 | |||||||||
Depreciation and amortization |
$ | 20,726 | $ | 6,805 | $ | 521 | $ | (295 | ) | $ | 27,757 | |||||||||
Income (loss) from operations |
$ | (24,579 | ) | $ | 18,261 | $ | (15,767 | ) | $ | (659 | ) | $ | (22,744 | ) | ||||||
Capital expenditures |
$ | 19,209 | $ | 1,911 | $ | 9,978 | $ | | $ | 31,098 | ||||||||||
March 31, 2011 |
||||||||||||||||||||
Cash, cash equivalents and investments
in marketable securities |
$ | | $ | 1,502 | $ | 291,109 | $ | | $ | 292,611 | ||||||||||
Total assets |
$ | 2,725,065 | $ | 679,101 | $ | 619,825 | $ | (34,231 | ) | $ | 3,989,760 | |||||||||
Long-term debt |
$ | | $ | 505,918 | $ | 345,108 | $ | (16,813 | ) | $ | 834,213 | |||||||||
December 31, 2010 |
||||||||||||||||||||
Cash, cash equivalents and investments
in marketable securities |
$ | | $ | 403 | $ | 230,041 | $ | | $ | 230,444 | ||||||||||
Total assets |
$ | 2,490,193 | $ | 669,820 | $ | 573,531 | $ | (32,069 | ) | $ | 3,701,475 | |||||||||
Long-term debt |
$ | | $ | 482,271 | $ | 345,215 | $ | (16,925 | ) | $ | 810,561 |
(1) | HEP segment revenues from external customers were $10.9 million and $7.1 million for the three months ended March 31, 2011 and 2010, respectively. |
NOTE 17: Supplemental Guarantor/Non-Guarantor Financial Information
Our obligations under the Holly 9.875% Senior Notes have been jointly and severally guaranteed by
the substantial majority of our existing and future restricted subsidiaries (Guarantor Restricted
Subsidiaries). These guarantees are full and unconditional. HEP, in which we have a 34%
ownership interest, and its subsidiaries (collectively, Non-Guarantor Non-Restricted
Subsidiaries), and certain of our other subsidiaries (Non-Guarantor Restricted Subsidiaries)
have not guaranteed these obligations.
The following financial information presents condensed consolidating balance sheets, statements of
income, and statements of cash flows of Holly Corporation (the Parent), the Guarantor Restricted
Subsidiaries, the Non-Guarantor Restricted Subsidiaries and the Non-Guarantor Non-Restricted
Subsidiaries. The information has been presented as if the Parent accounted for its ownership in
the Guarantor Restricted Subsidiaries, and the Guarantor Restricted Subsidiaries accounted for the
ownership of the Non-Guarantor Restricted Subsidiaries and Non-Guarantor Non-Restricted
Subsidiaries, using the equity method of accounting. The Guarantor Restricted Subsidiaries and the
Non-Guarantor Restricted Subsidiaries are collectively the Restricted Subsidiaries. Our
revaluation of HEPs assets and liabilities at March 1, 2008 (date of reconsolidation) resulted in
basis adjustments to
our consolidated HEP balances. Therefore, our reported amounts for the HEP segment may not agree
to amounts reported in HEPs periodic public filings.
- 23 -
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Condensed Consolidating Balance Sheet
Non- | Non-Guarantor | |||||||||||||||||||||||||||||||
Guarantor | Holly Corp. Before | Non-Restricted | ||||||||||||||||||||||||||||||
Guarantor Restricted | Restricted | Consolidation of | Subsidiaries | |||||||||||||||||||||||||||||
March 31, 2011 | Parent | Subsidiaries | Subsidiaries | Eliminations | HEP | (HEP Segment) | Eliminations | Consolidated | ||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||||||
ASSETS |
||||||||||||||||||||||||||||||||
Current assets: |
||||||||||||||||||||||||||||||||
Cash and cash equivalents |
$ | 203,343 | $ | (633 | ) | $ | 19,902 | $ | | $ | 222,612 | $ | 1,502 | $ | | $ | 224,114 | |||||||||||||||
Marketable securities |
47,469 | 1,478 | | | 48,947 | | | 48,947 | ||||||||||||||||||||||||
Accounts receivable |
2,427 | 1,147,038 | 4,001 | | 1,153,466 | 23,475 | (24,687 | ) | 1,152,254 | |||||||||||||||||||||||
Intercompany accounts receivable
(payable) |
(1,474,477 | ) | 1,058,765 | 415,712 | | | | | | |||||||||||||||||||||||
Inventories |
| 473,271 | | | 473,271 | 185 | | 473,456 | ||||||||||||||||||||||||
Income taxes receivable |
2,042 | | | | 2,042 | | | 2,042 | ||||||||||||||||||||||||
Prepayments and other assets |
8,283 | 10,084 | | | 18,367 | 360 | (3,786 | ) | 14,941 | |||||||||||||||||||||||
Total current assets |
(1,210,913 | ) | 2,690,003 | 439,615 | | 1,918,705 | 25,522 | (28,473 | ) | 1,915,754 | ||||||||||||||||||||||
Properties and equipment, net |
17,279 | 1,019,342 | 274,994 | | 1,311,615 | 496,839 | (6,902 | ) | 1,801,552 | |||||||||||||||||||||||
Marketable securities (long-term) |
19,550 | | | | 19,550 | | | 19,550 | ||||||||||||||||||||||||
Investment in subsidiaries |
2,437,180 | 630,718 | (394,511 | ) | (2,673,387 | ) | | | | | ||||||||||||||||||||||
Intangibles and other assets |
7,800 | 87,220 | | | 95,020 | 156,740 | 1,144 | 252,904 | ||||||||||||||||||||||||
Total assets |
$ | 1,270,896 | $ | 4,427,283 | $ | 320,098 | $ | (2,673,387 | ) | $ | 3,344,890 | $ | 679,101 | $ | (34,231 | ) | $ | 3,989,760 | ||||||||||||||
LIABILITIES AND EQUITY |
||||||||||||||||||||||||||||||||
Current liabilities: |
||||||||||||||||||||||||||||||||
Accounts payable |
$ | 5,707 | $ | 1,496,835 | $ | 10,328 | $ | | $ | 1,512,870 | $ | 10,325 | $ | (24,687 | ) | $ | 1,498,508 | |||||||||||||||
Accrued liabilities |
30,244 | 35,525 | 1,060 | | 66,829 | 13,691 | (3,786 | ) | 76,734 | |||||||||||||||||||||||
Total current liabilities |
35,951 | 1,532,360 | 11,388 | | 1,579,699 | 24,016 | (28,473 | ) | 1,575,242 | |||||||||||||||||||||||
Long-term debt |
289,792 | 55,316 | | | 345,108 | 505,918 | (16,813 | ) | 834,213 | |||||||||||||||||||||||
Non-current liabilities |
44,444 | 26,703 | | | 71,147 | 9,510 | | 80,657 | ||||||||||||||||||||||||
Deferred income taxes |
125,685 | 325 | 737 | | 126,747 | | 4,951 | 131,698 | ||||||||||||||||||||||||
Distributions in excess of inv in HEP |
| 375,399 | | | 375,399 | | (375,399 | ) | | |||||||||||||||||||||||
Equity Holly Corporation |
775,024 | 2,437,180 | 307,973 | (2,745,153 | ) | 775,024 | 139,657 | (140,895 | ) | 773,786 | ||||||||||||||||||||||
Equity noncontrolling interest |
| | | 71,766 | 71,766 | | 522,398 | 594,164 | ||||||||||||||||||||||||
Total liabilities and equity |
$ | 1,270,896 | $ | 4,427,283 | $ | 320,098 | $ | (2,673,387 | ) | $ | 3,344,890 | $ | 679,101 | $ | (34,231 | ) | $ | 3,989,760 | ||||||||||||||
Condensed Consolidating Balance Sheet
Non- | Non-Guarantor | |||||||||||||||||||||||||||||||
Guarantor | Holly Corp. Before | Non-Restricted | ||||||||||||||||||||||||||||||
Guarantor Restricted | Restricted | Consolidation of | Subsidiaries | |||||||||||||||||||||||||||||
December 31, 2010 | Parent | Subsidiaries | Subsidiaries | Eliminations | HEP | (HEP Segment) | Eliminations | Consolidated | ||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||||||
ASSETS |
||||||||||||||||||||||||||||||||
Current assets: |
||||||||||||||||||||||||||||||||
Cash and cash equivalents |
$ | 230,082 | $ | (9,035 | ) | $ | 7,651 | $ | | $ | 228,698 | $ | 403 | $ | | $ | 229,101 | |||||||||||||||
Marketable securities |
| 1,343 | | | 1,343 | | | 1,343 | ||||||||||||||||||||||||
Accounts receivable |
1,683 | 991,778 | | | 993,461 | 22,508 | (22,853 | ) | 993,116 | |||||||||||||||||||||||
Intercompany accounts receivable
(payable) |
(1,401,580 | ) | 981,691 | 419,889 | | | | | | |||||||||||||||||||||||
Inventories |
| 400,165 | | | 400,165 | 202 | | 400,367 | ||||||||||||||||||||||||
Income taxes receivable |
51,034 | | | | 51,034 | | | 51,034 | ||||||||||||||||||||||||
Prepayments and other assets |
10,210 | 20,942 | | | 31,152 | 573 | (3,251 | ) | 28,474 | |||||||||||||||||||||||
Total current assets |
(1,108,571 | ) | 2,386,884 | 427,540 | | 1,705,853 | 23,686 | (26,104 | ) | 1,703,435 | ||||||||||||||||||||||
Properties and equipment, net |
17,177 | 1,017,877 | 236,648 | | 1,271,702 | 492,098 | (7,109 | ) | 1,756,691 | |||||||||||||||||||||||
Investment in subsidiaries |
2,273,159 | 595,888 | (393,011 | ) | (2,476,036 | ) | | | | | ||||||||||||||||||||||
Intangibles and other assets |
8,569 | 77,600 | | | 86,169 | 154,036 | 1,144 | 241,349 | ||||||||||||||||||||||||
Total assets |
$ | 1,190,334 | $ | 4,078,249 | $ | 271,177 | $ | (2,476,036 | ) | $ | 3,063,724 | $ | 669,820 | $ | (32,069 | ) | $ | 3,701,475 | ||||||||||||||
LIABILITIES AND EQUITY |
||||||||||||||||||||||||||||||||
Current liabilities: |
||||||||||||||||||||||||||||||||
Accounts payable |
$ | 7,170 | $ | 1,319,316 | $ | 3,575 | $ | | $ | 1,330,061 | $ | 10,238 | $ | (22,853 | ) | $ | 1,317,446 | |||||||||||||||
Accrued liabilities |
25,512 | 28,145 | 797 | | 54,454 | 21,206 | (3,251 | ) | 72,409 | |||||||||||||||||||||||
Total current liabilities |
32,682 | 1,347,461 | 4,372 | | 1,384,515 | 31,444 | (26,104 | ) | 1,389,855 | |||||||||||||||||||||||
Long-term debt |
289,509 | 55,706 | | | 345,215 | 482,271 | (16,925 | ) | 810,561 | |||||||||||||||||||||||
Non-current liabilities |
42,655 | 27,521 | | | 70,176 | 10,809 | | 80,985 | ||||||||||||||||||||||||
Deferred income taxes |
126,160 | 259 | 565 | | 126,984 | | 4,951 | 131,935 | ||||||||||||||||||||||||
Distributions in excess of inv in HEP |
| 374,143 | | | 374,143 | | (374,143 | ) | | |||||||||||||||||||||||
Equity Holly Corporation |
699,328 | 2,273,159 | 266,240 | (2,539,399 | ) | 699,328 | 145,296 | (147,205 | ) | 697,419 | ||||||||||||||||||||||
Equity noncontrolling interest |
| | | 63,363 | 63,363 | | 527,357 | 590,720 | ||||||||||||||||||||||||
Total liabilities and equity |
$ | 1,190,334 | $ | 4,078,249 | $ | 271,177 | $ | (2,476,036 | ) | $ | 3,063,724 | $ | 669,820 | $ | (32,069 | ) | $ | 3,701,475 | ||||||||||||||
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Condensed Consolidating Statement of Income
Non- | Non-Guarantor | |||||||||||||||||||||||||||||||
Guarantor | Holly Corp. Before | Non-Restricted | ||||||||||||||||||||||||||||||
Three Months Ended | Guarantor Restricted | Restricted | Consolidation of | Subsidiaries | ||||||||||||||||||||||||||||
March 31, 2011 | Parent | Subsidiaries | Subsidiaries | Eliminations | HEP | (HEP Segment) | Eliminations | Consolidated | ||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||||||
Sales and other revenues |
$ | 648 | $ | 2,315,092 | $ | | $ | | $ | 2,315,740 | $ | 45,005 | $ | (34,160 | ) | $ | 2,326,585 | |||||||||||||||
Operating costs and expenses: |
||||||||||||||||||||||||||||||||
Cost of products sold |
| 2,017,926 | | | 2,017,926 | | (33,309 | ) | 1,984,617 | |||||||||||||||||||||||
Operating expenses |
| 121,685 | 388 | | 122,073 | 12,796 | (126 | ) | 134,743 | |||||||||||||||||||||||
General and administrative
expenses |
15,353 | 102 | | | 15,455 | 1,363 | | 16,818 | ||||||||||||||||||||||||
Depreciation and amortization |
940 | 23,161 | 179 | | 24,280 | 7,235 | (207 | ) | 31,308 | |||||||||||||||||||||||
Total operating costs and expenses |
16,293 | 2,162,874 | 567 | | 2,179,734 | 21,394 | (33,642 | ) | 2,167,486 | |||||||||||||||||||||||
Income (loss) from operations |
(15,645 | ) | 152,218 | (567 | ) | | 136,006 | 23,611 | (518 | ) | 159,099 | |||||||||||||||||||||
Other income (expense): |
||||||||||||||||||||||||||||||||
Equity in earnings of
subsidiaries and joint venture |
158,957 | 7,563 | 8,020 | (166,520 | ) | 8,020 | 740 | (8,020 | ) | 740 | ||||||||||||||||||||||
Interest income (expense) |
(6,808 | ) | (824 | ) | 13 | | (7,619 | ) | (9,112 | ) | 612 | (16,119 | ) | |||||||||||||||||||
Merger transaction costs |
(3,698 | ) | | | | (3,698 | ) | | | (3,698 | ) | |||||||||||||||||||||
148,451 | 6,739 | 8,033 | (166,520 | ) | (3,297 | ) | (8,372 | ) | (7,408 | ) | (19,077 | ) | ||||||||||||||||||||
Income before income taxes |
132,806 | 158,957 | 7,466 | (166,520 | ) | 132,709 | 15,239 | (7,926 | ) | 140,022 | ||||||||||||||||||||||
Income tax provision |
48,783 | | | | 48,783 | 228 | | 49,011 | ||||||||||||||||||||||||
Net income |
84,023 | 158,957 | 7,466 | (166,520 | ) | 83,926 | 15,011 | (7,926 | ) | 91,011 | ||||||||||||||||||||||
Less net income attributable to
noncontrolling interest |
| | | 97 | 97 | | (6,414 | ) | (6,317 | ) | ||||||||||||||||||||||
Net income attributable to Holly
Corporation stockholders |
$ | 84,023 | $ | 158,957 | $ | 7,466 | $ | (166,423 | ) | $ | 84,023 | $ | 15,011 | $ | (14,340 | ) | $ | 84,694 | ||||||||||||||
Condensed Consolidating Statement of Income
Non- | Non-Guarantor | |||||||||||||||||||||||||||||||
Guarantor | Holly Corp. Before | Non-Restricted | ||||||||||||||||||||||||||||||
Three Months Ended | Guarantor Restricted | Restricted | Consolidation of | Subsidiaries | ||||||||||||||||||||||||||||
March 31, 2010 | Parent | Subsidiaries | Subsidiaries | Eliminations | HEP | (HEP Segment) | Eliminations | Consolidated | ||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||||||
Sales and other revenues |
$ | 67 | $ | 1,867,173 | $ | | $ | | $ | 1,867,240 | $ | 40,689 | $ | (33,639 | ) | $ | 1,874,290 | |||||||||||||||
Operating costs and expenses: |
||||||||||||||||||||||||||||||||
Cost of products sold |
| 1,756,507 | (74 | ) | | 1,756,433 | | (32,569 | ) | 1,723,864 | ||||||||||||||||||||||
Operating expenses |
| 114,600 | | | 114,600 | 13,060 | (116 | ) | 127,544 | |||||||||||||||||||||||
General and administrative
expenses |
14,885 | 421 | | | 15,306 | 2,563 | | 17,869 | ||||||||||||||||||||||||
Depreciation and amortization |
943 | 20,954 | (650 | ) | | 21,247 | 6,805 | (295 | ) | 27,757 | ||||||||||||||||||||||
Total operating costs and expenses |
15,828 | 1,892,482 | (724 | ) | | 1,907,586 | 22,428 | (32,980 | ) | 1,897,034 | ||||||||||||||||||||||
Income (loss) from operations |
(15,761 | ) | (25,309 | ) | 724 | | (40,346 | ) | 18,261 | (659 | ) | (22,744 | ) | |||||||||||||||||||
Other income (expense): |
||||||||||||||||||||||||||||||||
Equity in earnings (loss) of
subsidiaries and joint ventures |
(20,108 | ) | 6,480 | 5,929 | 13,628 | 5,929 | | (5,929 | ) | | ||||||||||||||||||||||
Interest income (expense) |
(9,143 | ) | (1,279 | ) | 8 | | (10,414 | ) | (8,104 | ) | 855 | (17,663 | ) | |||||||||||||||||||
Other income (expense) |
| | | | | 481 | | 481 | ||||||||||||||||||||||||
(29,251 | ) | 5,201 | 5,937 | 13,628 | (4,485 | ) | (7,623 | ) | (5,074 | ) | (17,182 | ) | ||||||||||||||||||||
Income (loss) before income taxes |
(45,012 | ) | (20,108 | ) | 6,661 | 13,628 | (44,831 | ) | 10,638 | (5,733 | ) | (39,926 | ) | |||||||||||||||||||
Income tax provision |
(16,766 | ) | | | | (16,766 | ) | 94 | | (16,672 | ) | |||||||||||||||||||||
Net Income (loss) |
(28,246 | ) | (20,108 | ) | 6,661 | 13,628 | (28,065 | ) | 10,544 | (5,733 | ) | (23,254 | ) | |||||||||||||||||||
Less net income attributable to
noncontrolling interest |
| | | 181 | 181 | | 4,659 | 4,840 | ||||||||||||||||||||||||
Net income (loss) attributable to
Holly Corporation stockholders |
$ | (28,246 | ) | $ | (20,108 | ) | $ | 6,661 | $ | 13,447 | $ | (28,246 | ) | $ | 10,544 | $ | (10,392 | ) | $ | (28,094 | ) | |||||||||||
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Table of Contents
Condensed Consolidating Statement of Cash Flows
Non-Guarantor | ||||||||||||||||||||||||||||
Guarantor | Non-Guarantor | Holly Corp. Before | Non-Restricted | |||||||||||||||||||||||||
Three Months Ended | Restricted | Restricted | Consolidation of | Subsidiaries | ||||||||||||||||||||||||
March 31, 2011 | Parent | Subsidiaries | Subsidiaries | HEP | (HEP Segment) | Eliminations | Consolidated | |||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||
Cash flows from operating activities |
$ | 51,090 | $ | 57,174 | $ | 16,776 | $ | 125,040 | $ | 15,222 | $ | (9,720 | ) | $ | 130,542 | |||||||||||||
Cash flows from investing activities |
||||||||||||||||||||||||||||
Additions to properties, plants and equipment Holly |
(1,043 | ) | (22,995 | ) | (38,525 | ) | (62,563 | ) | | | (62,563 | ) | ||||||||||||||||
Additions to properties, plants and equipment HEP |
| | | | (11,475 | ) | | (11,475 | ) | |||||||||||||||||||
Purchases of marketable securities |
(98,937 | ) | | | (98,937 | ) | | | (98,937 | ) | ||||||||||||||||||
Sales and maturities of marketable securities |
31,925 | | | 31,925 | | | 31,925 | |||||||||||||||||||||
(68,055 | ) | (22,995 | ) | (38,525 | ) | (129,575 | ) | (11,475 | ) | | (141,050 | ) | ||||||||||||||||
Cash flows from financing activities |
||||||||||||||||||||||||||||
Net borrowings under credit agreements HEP |
| | | | 23,000 | | 23,000 | |||||||||||||||||||||
Repayments under financing obligation Holly |
| (277 | ) | | (277 | ) | | (277 | ) | |||||||||||||||||||
Purchase of treasury stock |
(2,051 | ) | | | (2,051 | ) | | | (2,051 | ) | ||||||||||||||||||
Contribution from joint venture partner |
| (25,500 | ) | 34,000 | 8,500 | | | 8,500 | ||||||||||||||||||||
Dividends |
(7,984 | ) | | | (7,984 | ) | | | (7,984 | ) | ||||||||||||||||||
Distributions to noncontrolling interest |
| | | | (22,205 | ) | 9,720 | (12,485 | ) | |||||||||||||||||||
Excess tax benefit from equity based compensation |
261 | | | 261 | | | 261 | |||||||||||||||||||||
Deferred financing costs |
| | | | (3,044 | ) | | (3,044 | ) | |||||||||||||||||||
Purchase of units for HEP restricted grants |
| | | | (399 | ) | | (399 | ) | |||||||||||||||||||
(9,774 | ) | (25,777 | ) | 34,000 | (1,551 | ) | (2,648 | ) | 9,720 | 5,521 | ||||||||||||||||||
Cash and cash equivalents |
||||||||||||||||||||||||||||
Increase (decrease) for the period |
(26,739 | ) | 8,402 | 12,251 | (6,086 | ) | 1,099 | | (4,987 | ) | ||||||||||||||||||
Beginning of period |
230,082 | (9,035 | ) | 7,651 | 228,698 | 403 | | 229,101 | ||||||||||||||||||||
End of period |
$ | 203,343 | $ | (633 | ) | $ | 19,902 | $ | 222,612 | $ | 1,502 | $ | | $ | 224,114 | |||||||||||||
Condensed Consolidating Statement of Cash Flows
Non-Guarantor | ||||||||||||||||||||||||||||
Guarantor | Non-Guarantor | Holly Corp. Before | Non-Restricted | |||||||||||||||||||||||||
Restricted | Restricted | Consolidation of | Subsidiaries | |||||||||||||||||||||||||
Three Months Ended March 31, 2010 | Parent | Subsidiaries | Subsidiaries | HEP | (HEP Segment) | Eliminations | Consolidated | |||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||
Cash flows from operating activities |
$ | (43,478 | ) | $ | (59,287 | ) | $ | 2,660 | $ | (100,105 | ) | $ | 18,723 | $ | (8,642 | ) | $ | (90,024 | ) | |||||||||
Cash flows from investing activities |
||||||||||||||||||||||||||||
Additions to properties, plants and equipment Holly |
(915 | ) | (19,209 | ) | (9,063 | ) | (29,167 | ) | | | (29,187 | ) | ||||||||||||||||
Additions to properties, plants and equipment HEP |
| | | | (39,145 | ) | 37,324 | (1,911 | ) | |||||||||||||||||||
Proceeds from sale of assets |
| 37,324 | | 37,324 | | (37,324 | ) | | ||||||||||||||||||||
(915 | ) | 18,025 | (9,063 | ) | 8,047 | (39,145 | ) | | (31,098 | ) | ||||||||||||||||||
Cash flows from financing activities |
||||||||||||||||||||||||||||
Net repayments under credit agreements HEP |
| | | | (35,000 | ) | | (35,000 | ) | |||||||||||||||||||
Proceeds from issuance of senior notes HEP |
| | | | 147,540 | | 147,540 | |||||||||||||||||||||
Repayments under financing obligation Holly |
| (345 | ) | | (345 | ) | | 99 | (246 | ) | ||||||||||||||||||
Purchase of treasury stock |
(1,055 | ) | | | (1,055 | ) | | | (1,055 | ) | ||||||||||||||||||
Contribution from joint venture partner |
| (3,750 | ) | 5,000 | 1,250 | | | 1,250 | ||||||||||||||||||||
Dividends |
(7,926 | ) | | | (7,926 | ) | | | (7,926 | ) | ||||||||||||||||||
Purchase price in excess of transferred basis in
assets |
| 55,766 | | 55,766 | (55,766 | ) | | | ||||||||||||||||||||
Distributions to noncontrolling interest |
| | | | (20,506 | ) | 8,543 | (11,963 | ) | |||||||||||||||||||
Excess tax expense from equity based compensation |
(1,045 | ) | | | (1,045 | ) | | | (1,045 | ) | ||||||||||||||||||
Deferred financing costs |
(56 | ) | | | (56 | ) | | (56 | ) | |||||||||||||||||||
Purchase of units for HEP restricted grants |
| | | | (1,745 | ) | | (1,745 | ) | |||||||||||||||||||
Other |
61 | | | 61 | | | 61 | |||||||||||||||||||||
(10,021 | ) | 51,671 | 5,000 | 46,650 | 34,523 | 8,642 | 89,815 | |||||||||||||||||||||
Cash and cash equivalents |
||||||||||||||||||||||||||||
Increase (decrease) for the period |
(54,414 | ) | 10,409 | (1,403 | ) | (45,408 | ) | 14,101 | | (31,307 | ) | |||||||||||||||||
Beginning of period |
127,560 | (12,477 | ) | 7,005 | 122,088 | 2,508 | | 124,596 | ||||||||||||||||||||
End of period |
$ | 73,146 | $ | (2,068 | ) | $ | 5,602 | $ | 76,680 | $ | 16,609 | $ | | $ | 93,289 | |||||||||||||
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Table of Contents
Item 2. Managements Discussion and Analysis of Financial Condition and Results of
Operations
This Item 2 contains forward-looking statements. See Forward-Looking Statements at the
beginning of Part I of this Quarterly Report on Form 10-Q. In this document, the words we,
our, ours and us refer only to Holly Corporation and its consolidated subsidiaries or to
Holly Corporation or an individual subsidiary and not to any other person. The words we, our,
ours and us generally include Holly Energy Partners, L.P. (HEP) and its subsidiaries as
consolidated subsidiaries of Holly Corporation with certain exceptions where there are transactions
or obligations between HEP and Holly Corporation or its other subsidiaries. This document contains
certain disclosures of agreements that are specific to HEP and its consolidated subsidiaries and do
not necessarily represent obligations of Holly Corporation. When used in descriptions of
agreements and transactions, HEP refers to HEP and its consolidated subsidiaries.
OVERVIEW
We are principally an independent petroleum refiner that produces high value light products
such as gasoline, diesel fuel, jet fuel, specialty lubricant products, and specialty and modified
asphalt. Navajo Refining Company, L.L.C., one of our wholly-owned subsidiaries, owns a petroleum
refinery in Artesia, New Mexico, which operates in conjunction with crude, vacuum distillation and
other facilities situated 65 miles away in Lovington, New Mexico (collectively, the Navajo
Refinery). The Navajo Refinery can process sour (high sulfur) crude oils and serves markets in
the southwestern United States and northern Mexico. Our refinery located just north of Salt Lake
City, Utah (the Woods Cross Refinery) is operated by Holly Refining & Marketing Company Woods
Cross, one of our wholly-owned subsidiaries. This facility is a high conversion refinery that
primarily processes regional sweet (lower sulfur) and sour Canadian crude oils. Our refinery
located in Tulsa, Oklahoma (the Tulsa Refinery) is comprised of two facilities, the Tulsa
Refinery west and east facilities.
At March 31, 2011, we owned a 34% interest in HEP, a consolidated variable interest entity (VIE),
which includes our 2% general partner interest. HEP has logistic assets including petroleum
product and crude oil pipelines located in Texas, New Mexico, Oklahoma and Utah; ten refined
product terminals; a jet fuel terminal; loading rack facilities at each of our three refineries, a
refined products tank farm facility and on-site crude oil tankage at our Navajo, Woods Cross and
Tulsa Refineries. Additionally, HEP owns a 25% interest in SLC Pipeline LLC (SLC Pipeline), a
new 95-mile intrastate pipeline system that serves refineries in the Salt Lake City area.
On February 21, 2011, we entered into a merger agreement providing for a merger of equals
business combination of us and Frontier Oil Corporation (Frontier). Subject to the terms and
conditions of the merger agreement which has been approved unanimously by both our and Frontiers
board of directors, Frontier shareholders will receive 0.4811 shares of our common stock for each
share of Frontier common stock if the merger is completed. Completion of the merger is subject to
certain conditions, including, among others, (i) approval by our stockholders of the issuance of
our common stock to Frontiers stockholders in connection with the merger, (ii) adoption of the
merger agreement by Frontiers stockholders, (iii) the expiration or termination of the applicable
waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, (iv) the
registration statement on Form S-4 used to register the common stock to be issued as consideration
for the merger having been declared effective by the SEC and (v) the entry into a new credit
facility for the combined company. In March 2011, the Federal Trade Commission (FTC) granted
early termination of its Hart-Scott-Rodino antitrust review of the proposed merger.
Our principal source of revenue is from the sale of high value light products such as gasoline,
diesel fuel, jet fuel and asphalt products in markets in the Southwest, Rocky Mountain and
Mid-Continent regions of the United States and northern Mexico. We also produce specialty
lubricant products that are marketed throughout North America and are distributed in Central and
South America. For the three months ended March 31, 2011, sales and other revenues were $2,326.6
million and net income attributable to Holly Corporation stockholders was $84.7 million. For the
three months ended March 31, 2010, sales and other revenues were $1,874.3 million and the net loss
attributable to Holly Corporation stockholders was $28.1 million. Our principal expenses are costs
of products sold and operating expenses. Our total operating costs and expenses for the three
months ended March 31, 2011 were $2,167.5 million compared to $1,897 million for the three months
ended March 31, 2010.
- 27 -
Table of Contents
RESULTS OF OPERATIONS
Financial Data (Unaudited)
Three Months Ended | ||||||||||||||||
March 31, | Change from 2010 | |||||||||||||||
2011 | 2010 | Change | Percent | |||||||||||||
(In thousands, except per share data) | ||||||||||||||||
Sales and other revenues |
$ | 2,326,585 | $ | 1,874,290 | $ | 452,295 | 24.1 | % | ||||||||
Operating costs and expenses: |
||||||||||||||||
Cost of products sold (exclusive of depreciation and
amortization) |
1,984,617 | 1,723,864 | 260,753 | 15.1 | ||||||||||||
Operating expenses (exclusive of depreciation and amortization) |
134,743 | 127,544 | 7,199 | 5.6 | ||||||||||||
General and administrative expenses (exclusive of depreciation
and amortization) |
16,818 | 17,869 | (1,051 | ) | (5.9 | ) | ||||||||||
Depreciation and amortization |
31,308 | 27,757 | 3,551 | 12.8 | ||||||||||||
Total operating costs and expenses |
2,167,486 | 1,897,034 | 270,452 | 14.3 | ||||||||||||
Income (loss) from operations |
159,099 | (22,744 | ) | 181,843 | 799.5 | |||||||||||
Other income (expense): |
||||||||||||||||
Equity in earnings of SLC Pipeline |
740 | 481 | 259 | 53.8 | ||||||||||||
Interest income |
85 | 59 | 26 | 44.1 | ||||||||||||
Interest expense |
(16,204 | ) | (17,722 | ) | 1,518 | 8.6 | ||||||||||
Merger transaction costs |
(3,698 | ) | | (3,698 | ) | (100.0 | ) | |||||||||
(19,077 | ) | (17,182 | ) | (1,895 | ) | 11.0 | ||||||||||
Income (loss) before income taxes |
140,022 | (39,926 | ) | 179,948 | 450.7 | |||||||||||
Income tax provision (benefit) |
49,011 | (16,672 | ) | 65,683 | 394.0 | |||||||||||
Net income (loss) |
91,011 | (23,254 | ) | 114,265 | 491.4 | |||||||||||
Less net income attributable to noncontrolling interest |
6,317 | 4,840 | 1,477 | 30.5 | ||||||||||||
Net income (loss) attributable to Holly Corporation stockholders |
$ | 84,694 | $ | (28,094 | ) | $ | 112,788 | 401.5 | % | |||||||
Earnings per share attributable to Holly Corporation stockholders: |
||||||||||||||||
Basic |
$ | 1.59 | $ | (0.53 | ) | $ | 2.12 | 400.0 | % | |||||||
Diluted |
$ | 1.58 | $ | (0.53 | ) | $ | 2.11 | 398.1 | % | |||||||
Cash dividends declared per common share |
$ | 0.15 | $ | 0.15 | $ | | | % | ||||||||
Average number of common shares outstanding: |
||||||||||||||||
Basic |
53,307 | 53,094 | 213 | 0.4 | % | |||||||||||
Diluted |
53,633 | 53,094 | 539 | 1.0 | % |
Balance Sheet Data (Unaudited)
March 31, | December 31, | |||||||
2011 | 2010 | |||||||
(In thousands) | ||||||||
Cash, cash equivalents and investments in marketable securities |
$ | 292,611 | $ | 230,444 | ||||
Working capital |
$ | 340,512 | $ | 313,580 | ||||
Total assets |
$ | 3,989,760 | $ | 3,701,475 | ||||
Long-term debt |
$ | 834,213 | $ | 810,561 | ||||
Total equity |
$ | 1,367,950 | $ | 1,288,139 |
- 28 -
Table of Contents
Other Financial Data (Unaudited)
Three Months Ended | ||||||||
March 31, | ||||||||
2011 | 2010 | |||||||
(In thousands) | ||||||||
Net cash provided by (used for) operating activities |
$ | 130,542 | $ | (90,024 | ) | |||
Net cash used for investing activities |
$ | (141,050 | ) | $ | (31,098 | ) | ||
Net cash provided by financing activities |
$ | 5,521 | $ | 89,815 | ||||
Capital expenditures |
$ | 74,038 | $ | 31,098 | ||||
EBITDA (1) |
$ | 181,132 | $ | 654 |
(1) | Earnings before interest, taxes, depreciation and amortization, which we refer to as (EBITDA), is calculated as net income plus (i) interest expense, net of interest income, (ii) income tax provision, and (iii) depreciation and amortization. EBITDA is not a calculation provided for under GAAP; however, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements. EBITDA should not be considered as an alternative to net income or operating income as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented here because it is a widely used financial indicator used by investors and analysts to measure performance. EBITDA is also used by our management for internal analysis and as a basis for financial covenants. EBITDA presented above is reconciled to net income under Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles following Item 3 of Part I of this Form 10-Q. |
Our operations are currently organized into two reportable segments, Refining and HEP. Our
operations that are not included in the Refining and HEP segment are included in Corporate and
Other. Intersegment transactions are eliminated in our consolidated financial statements and are
included in Eliminations.
Three Months Ended | ||||||||
March 31, | ||||||||
2011 | 2010 | |||||||
(In thousands) | ||||||||
Sales and other revenues |
||||||||
Refining (1) |
$ | 2,315,092 | $ | 1,867,174 | ||||
HEP (2) |
45,005 | 40,689 | ||||||
Corporate and Other |
648 | 66 | ||||||
Eliminations |
(34,160 | ) | (33,639 | ) | ||||
Consolidated |
$ | 2,326,585 | $ | 1,874,290 | ||||
Operating income (loss) |
||||||||
Refining (1) |
$ | 152,104 | $ | (24,579 | ) | |||
HEP (2) |
23,611 | 18,261 | ||||||
Corporate and Other |
(16,098 | ) | (15,767 | ) | ||||
Eliminations |
(518 | ) | (659 | ) | ||||
Consolidated |
$ | 159,099 | $ | (22,744 | ) | |||
(1) | The Refining segment includes the operations of our Navajo, Woods Cross and Tulsa Refineries and Holly Asphalt Company (Holly Asphalt) and involves the purchase and refining of crude oil and wholesale and branded marketing of refined products, such as gasoline, diesel fuel, jet fuel, specialty lubricant products, and specialty and modified asphalt. The petroleum products are primarily marketed in the Southwest, Rocky Mountain and Mid-Continent regions of the United States and northern Mexico. Additionally, specialty lubricant products produced at our Tulsa Refinery are marketed throughout North America and are distributed in Central and South America. Holly Asphalt manufactures and markets asphalt and asphalt products in Arizona, New Mexico, Oklahoma, Kansas, Missouri, Texas and northern Mexico. | |
(2) | The HEP segment involves all of the operations of HEP which owns and operates a system of petroleum product and crude gathering pipelines and refinery tankage in Texas, New Mexico, Oklahoma and Utah, and distribution terminals in Texas, New Mexico, Arizona, Utah, Idaho, Oklahoma and Washington. Revenues are generated by charging tariffs for transporting petroleum products and crude oil through its pipelines and by charging fees for |
- 29 -
Table of Contents
terminalling petroleum products and other hydrocarbons, and storing and providing other services at its storage tanks and terminals. Additionally, HEP owns a 25% interest in the SLC Pipeline that services refineries in the Salt Lake City, Utah area. Revenues from the HEP segment are earned through transactions with unaffiliated parties for pipeline transportation, rental and terminalling operations as well as revenues relating to pipeline transportation services provided for our refining operations. |
Refining Operating Data (Unaudited)
Our refinery operations include the Navajo, Woods Cross and Tulsa Refineries. The following tables
set forth information, including non-GAAP performance measures, about our consolidated refinery
operations. The cost of products and refinery gross margin do not include the effect of
depreciation and amortization. Reconciliations to amounts reported under GAAP are provided under
Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles following Item
3 of Part I of this Form 10-Q.
Three Months Ended | ||||||||
March 31, | ||||||||
2011 | 2010 | |||||||
Navajo Refinery |
||||||||
Crude charge (BPD) (1) |
69,980 | 78,910 | ||||||
Refinery throughput (BPD) (2) |
78,930 | 90,490 | ||||||
Refinery production (BPD) (3) |
76,720 | 87,530 | ||||||
Sales of produced refined products (BPD) |
79,840 | 86,930 | ||||||
Sales of refined products (BPD) (4) |
86,700 | 90,120 | ||||||
Refinery utilization (5) |
70.0 | % | 78.9 | % | ||||
Average per produced barrel (6) |
||||||||
Net sales |
$ | 110.99 | $ | 88.06 | ||||
Cost of products (7) |
95.60 | 82.96 | ||||||
Refinery gross margin |
15.39 | 5.10 | ||||||
Refinery operating expenses (8) |
6.34 | 5.18 | ||||||
Net operating margin |
$ | 9.05 | $ | (0.08 | ) | |||
Refinery operating expenses per throughput barrel |
$ | 6.42 | $ | 4.97 | ||||
Feedstocks: |
||||||||
Sour crude oil |
73 | % | 87 | % | ||||
Sweet crude oil |
5 | % | 4 | % | ||||
Heavy sour crude oil |
11 | % | | % | ||||
Other feedstocks and blends |
11 | % | 9 | % | ||||
Total |
100 | % | 100 | % | ||||
Sales of produced refined products: |
||||||||
Gasolines |
51 | % | 59 | % | ||||
Diesel fuels |
35 | % | 30 | % | ||||
Jet fuels |
1 | % | 4 | % | ||||
Fuel oil |
5 | % | 4 | % | ||||
Asphalt |
5 | % | 1 | % | ||||
LPG and other |
3 | % | 2 | % | ||||
Total |
100 | % | 100 | % | ||||
Woods Cross Refinery |
||||||||
Crude charge (BPD) (1) |
25,770 | 25,680 | ||||||
Refinery throughput (BPD) (2) |
27,900 | 27,110 | ||||||
Refinery production (BPD) (3) |
26,620 | 26,540 | ||||||
Sales of produced refined products (BPD) |
26,650 | 28,170 | ||||||
Sales of refined products (BPD) (4) |
26,740 | 28,360 | ||||||
Refinery utilization (5) |
83.1 | % | 82.8 | % |
- 30 -
Table of Contents
Three Months Ended | ||||||||
March 31, | ||||||||
2011 | 2010 | |||||||
Average per produced barrel (6) |
||||||||
Net sales |
$ | 108.77 | $ | 89.52 | ||||
Cost of products (7) |
89.87 | 74.72 | ||||||
Refinery gross margin |
18.90 | 14.80 | ||||||
Refinery operating expenses (8) |
6.43 | 6.20 | ||||||
Net operating margin |
$ | 12.47 | $ | 8.60 | ||||
Refinery operating expenses per throughput barrel |
$ | 6.14 | $ | 6.45 | ||||
Feedstocks: |
||||||||
Sweet crude oil |
57 | % | 61 | % | ||||
Heavy sour crude oil |
4 | % | 7 | % | ||||
Black wax crude oil |
31 | % | 28 | % | ||||
Other feedstocks and blends |
8 | % | 4 | % | ||||
Total |
100 | % | 100 | % | ||||
Sales of produced refined products: |
||||||||
Gasolines |
61 | % | 64 | % | ||||
Diesel fuels |
29 | % | 28 | % | ||||
Jet fuels |
2 | % | 1 | % | ||||
Fuel oil |
2 | % | 1 | % | ||||
Asphalt |
3 | % | 3 | % | ||||
LPG and other |
3 | % | 3 | % | ||||
Total |
100 | % | 100 | % | ||||
Tulsa Refinery |
||||||||
Crude charge (BPD) (1) |
105,600 | 103,600 | ||||||
Refinery throughput (BPD) (2) |
106,690 | 104,810 | ||||||
Refinery production (BPD) (3) |
106,160 | 102,890 | ||||||
Sales of produced refined products (BPD) |
100,010 | 98,760 | ||||||
Sales of refined products (BPD) (4) |
100,400 | 100,620 | ||||||
Refinery utilization (5) |
84.5 | % | 82.9 | % | ||||
Average per produced barrel (6) |
||||||||
Net sales |
$ | 115.29 | $ | 86.22 | ||||
Cost of products (7) |
100.50 | 82.89 | ||||||
Refinery gross margin |
14.79 | 3.33 | ||||||
Refinery operating expenses (8) |
5.98 | 5.91 | ||||||
Net operating margin |
$ | 8.81 | $ | (2.58 | ) | |||
Refinery operating expenses per throughput barrel |
$ | 5.61 | $ | 5.56 | ||||
Feedstocks: |
||||||||
Sweet crude oil |
97 | % | 99 | % | ||||
Heavy sour crude oil |
2 | % | | % | ||||
Other feedstocks and blends |
1 | % | 1 | % | ||||
Total |
100 | % | 100 | % | ||||
Sales of produced refined products: |
||||||||
Gasolines |
37 | % | 41 | % | ||||
Diesel fuels |
31 | % | 30 | % | ||||
Jet fuels |
8 | % | 9 | % | ||||
Lubricants |
11 | % | 10 | % | ||||
Asphalt |
4 | % | 4 | % | ||||
Gas oil / intermediates |
7 | % | 2 | % | ||||
LPG and other |
2 | % | 4 | % | ||||
Total |
100 | % | 100 | % | ||||
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Three Months Ended | ||||||||
March 31, | ||||||||
2011 | 2010 | |||||||
Consolidated |
||||||||
Crude charge (BPD) (1) |
201,350 | 208,190 | ||||||
Refinery throughput (BPD) (2) |
213,520 | 222,410 | ||||||
Refinery production (BPD) (3) |
209,500 | 216,960 | ||||||
Sales of produced refined products (BPD) |
206,500 | 213,860 | ||||||
Sales of refined products (BPD) (4) |
213,840 | 219,100 | ||||||
Refinery utilization (5) |
78.7 | % | 81.3 | % | ||||
Average per produced barrel (6) |
||||||||
Net sales |
$ | 113.28 | $ | 87.40 | ||||
Cost of products (7) |
97.56 | 81.84 | ||||||
Refinery gross margin |
15.72 | 5.56 | ||||||
Refinery operating expenses (8) |
6.24 | 5.65 | ||||||
Net operating margin |
$ | 9.48 | $ | (0.09 | ) | |||
Refinery operating expenses per throughput barrel |
$ | 5.98 | $ | 5.43 | ||||
Feedstocks: |
||||||||
Sour crude oil |
27 | % | 35 | % | ||||
Sweet crude oil |
58 | % | 56 | % | ||||
Heavy sour crude oil |
5 | % | 1 | % | ||||
Black wax crude oil |
4 | % | 3 | % | ||||
Other feedstocks and blends |
6 | % | 5 | % | ||||
Total |
100 | % | 100 | % | ||||
Sales of produced refined products: |
||||||||
Gasolines |
45 | % | 51 | % | ||||
Diesel fuels |
33 | % | 30 | % | ||||
Jet fuels |
4 | % | 6 | % | ||||
Fuel oil |
2 | % | 2 | % | ||||
Asphalt |
4 | % | 3 | % | ||||
Lubricants |
6 | % | 4 | % | ||||
Gas oil / intermediates |
3 | % | 1 | % | ||||
LPG and other |
3 | % | 3 | % | ||||
Total |
100 | % | 100 | % | ||||
(1) | Crude charge represents the barrels per day of crude oil processed at our refineries. | |
(2) | Refinery throughput represents the barrels per day of crude and other refinery feedstocks input to the crude units and other conversion units at our refineries. | |
(3) | Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstocks through the crude units and other conversion units at our refineries. | |
(4) | Includes refined products purchased for resale. | |
(5) | Represents crude charge divided by total crude capacity (BPSD). Our consolidated crude capacity is 256,000 BPSD. | |
(6) | Represents average per barrel amount for produced refined products sold, which is a non-GAAP measure. Reconciliations to amounts reported under GAAP are provided under Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles following Item 3 of Part I of this Form 10-Q. | |
(7) | Transportation costs billed from HEP are included in cost of products. | |
(8) | Represents operating expenses of our refineries, exclusive of depreciation and amortization. |
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Results of Operations Three Months Ended March 31, 2011 Compared to Three Months Ended March
31, 2010
Summary
Net income attributable to Holly Corporation stockholders for the three months ended March 31, 2011
was $84.7 million ($1.59 per basic and $1.58 per diluted share), a $112.8 million increase compared
to $28.1 million net loss ($(0.53) per basic and diluted share) for the three months ended March
31, 2010. Net income increased due principally to higher refinery gross margins during the three
months ended March 31, 2011. This was partially offset by a decrease in volumes of produced
refined products sold. Overall refinery gross margins for the three months ended March 31, 2011
increased to $15.72 per produced barrel compared to $5.56 for the three months ended March 31,
2010.
Overall production levels for the three months ended March 31, 2010 decreased by 3% over the same
period of 2010 due to the effects of production downtime at the Navajo Refinery during the current
year first quarter that was partially offset by current year production increases at our Tulsa
Refinery facilities. The Navajo Refinery experienced a plant-wide power outage in late January
2010. Inclement weather delayed the process of restoring production to planned operating levels
during the month of February.
Sales and Other Revenues
Sales and other revenues increased 24% from $1,874.3 million for the three months ended March 31,
2010 to $2,326.6 million for the three months ended March 31, 2011, due principally to the effects
of increased sales prices of produced refined products sold that was partially offset by a decrease
in year-over-year first quarter volumes of produced refined products sold. The average sales price
we received per produced barrel sold increased 30% from $87.40 for the three months ended March 31,
2010 to $113.28 for the three months ended March 31, 2011. Sales and other revenues for the three
months ended March 31, 2011 and 2010, include $10.9 million and $7.1 million, respectively, in HEP
revenues attributable to pipeline and transportation services provided to unaffiliated parties.
Cost of Products Sold
Cost of products sold increased 15% from $1,723.9 million for the three months ended March 31, 2010
to $1,984.6 million for the three months ended March 31, 2011, due principally to higher crude oil
costs, offset by a 3% decrease in volumes of produced refined products sold. The average price we
paid per barrel for crude oil and feedstocks and the transportation costs of moving the finished
products to the market place increased 19% from $81.84 for the three months ended March 31, 2010 to
$97.56 for the three months ended March 31, 2011.
Gross Refinery Margins
Gross refinery margin per produced barrel increased 183% from $5.56 for the three months ended
March 31, 2010 to $15.72 for the three months ended March 31, 2011 due to the effects of an
increase in the average sales price we received per barrel of produced refined products sold,
partially offset by an increase in the average per barrel price we paid for crude oil and
feedstocks. Our processing of 100% lower priced West Texas Intermediate related crude oil combined
with strong diesel and unseasonably high gasoline margins at all of our refineries helped fuel this
margin improvement. Gross refinery margin does not include the effects of depreciation and
amortization. See Reconciliations to Amounts Reported Under Generally Accepted Accounting
Principles following Item 3 of Part 1 of this Form 10-Q for a reconciliation to the income
statement of prices of refined products sold and cost of products purchased.
Operating Expenses
Operating expenses, exclusive of depreciation and amortization, increased 6% from $127.5 million
for the three months ended March 31, 2010 to $134.7 million for the three months ended March 31,
2011, due principally to increased repair and maintenance costs during the current year first
quarter.
General and Administrative Expenses
General and administrative expenses decreased 6% from $17.9 million for the three months ended
March 31, 2010 to $16.8 million for the three months ended March 31, 2011, due principally to lower
equity based compensation costs and fees for professional services.
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Depreciation and Amortization Expenses
Depreciation and amortization increased 13% from $27.8 million for the three months ended March 31,
2010 to $31.3 million for the three months ended March 31, 2011. The increase was due principally
to depreciation and amortization attributable to capitalized improvement projects in 2010.
Interest Expense
Interest expense was $16.2 million for the three months ended March 31, 2011 compared to $17.7
million for the three months ended March 31, 2010. The decrease was due principally to interest
capitalized on the UNEV Pipeline project. For the three months ended March 31, 2011 and 2010,
interest expense included $9.1 million and $8.1 million, respectively, in interest costs
attributable to HEP operations.
Income Taxes
For the three months ended March 31, 2011 we recorded income tax expense of $49 million compared to
an income tax benefit of $16.7 million for the three months ended March 31, 2010.
LIQUIDITY AND CAPITAL RESOURCES
Holly Credit Agreement
We have a $400 million senior secured credit agreement expiring in March 2013 (the Holly Credit
Agreement) with Bank of America, N.A. as administrative agent and one of a syndicate of lenders.
The Holly Credit Agreement may be used to fund working capital requirements, capital expenditures,
permitted acquisitions or other general corporate purposes. We were in compliance with all
covenants at March 31, 2011. At March 31, 2011, we had no outstanding borrowings and outstanding
letters of credit totaling $70 million under the Holly Credit Agreement. At that level of usage,
the unused commitment was $330 million.
If any particular lender could not honor its commitment, we believe the unused capacity that would
be available from the remaining lenders would be sufficient to meet our borrowing needs.
Additionally, we have reviewed publicly available information on our lenders in order to review and
monitor their financial stability and assess their ongoing ability to honor their commitments under
the Holly Credit Agreement. We have not experienced, nor do we expect to experience, any
difficulty in the lenders ability to honor their respective commitments, and if it were to become
necessary, we believe there would be alternative lenders or options available.
HEP Credit Agreement
HEP has a $275 million senior secured revolving Credit Agreement (the HEP Credit Agreement) that
is available to fund capital expenditures, investments, acquisitions, distribution payments and
working capital and for general partnership purposes. In February 2011, HEP amended its previous
credit agreement (expiring in August 2011), slightly, reducing the size of the credit facility from
$300 million to $275 million. The size was reduced based on managements review of past and
forecasted utilization of the facility. The HEP Credit Agreement expires in February
2016; however, in the event that the 6.25% HEP Senior Notes (discussed later) are not repurchased,
refinanced, extended or repaid prior to September 1, 2014, the HEP Credit Agreement will expire on
that date. At March 31, 2011, HEP had outstanding borrowings totaling $182 million under the HEP
Credit Agreement, with unused borrowing capacity of $93 million.
HEPs obligations under the HEP Credit Agreement are collateralized by substantially all of HEPs
assets (presented parenthetically in our Consolidated Balance Sheets). Indebtedness under the HEP
Credit Agreement is recourse to HEP Logistics Holdings, L.P., its general partner, and guaranteed
by HEPs wholly-owned subsidiaries. Any recourse to the general partner would be limited to the
extent of HEP Logistics Holdings, L.P.s assets, which other than its investment in HEP, are not
significant. HEPs creditors have no other recourse to our assets. Furthermore, our creditors have
no recourse to the assets of HEP and its consolidated subsidiaries.
If any particular lender could not honor its commitment under the HEP Credit agreement, HEP
believes the unused capacity that would be available from the remaining lenders would be sufficient
to meet its borrowing needs. Additionally, publicly available information on these lenders is
reviewed in order to monitor their financial stability and assess their ongoing ability to honor
their commitments under the HEP Credit Agreement.
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HEP does not expect to experience any difficulty in the lenders ability to honor their respective
commitments, and if it were to become necessary, HEP believes there would be alternative lenders or
options available.
Holly Senior Notes Due 2017
Our $300 million 9.875% senior notes (the Holly 9.875% Senior Notes) mature in June 2017 and are
unsecured and impose certain restrictive covenants, including limitations on our ability to incur
additional debt, incur liens, enter into sale-and-leaseback transactions, pay dividends, enter into
mergers, sell assets and enter into certain transactions with affiliates. At any time when the
Holly 9.875% Senior Notes are rated investment grade by both Moodys and Standard & Poors and no
default or event of default exists, we will not be subject to many of the foregoing covenants.
Additionally, we have certain redemption rights under the Holly 9.875% Senior Notes.
HEP Senior Notes Due 2018 and 2015
In March 2010, HEP issued $150 million in aggregate principal amount of 8.25% senior notes maturing
in March 2018 (the HEP 8.25% Senior Notes). A portion of the $147.5 million in net proceeds
received was used to fund HEPs $93 million purchase of certain storage assets at our Tulsa
Refinery east facility and Navajo Refinery Lovington facility on March 31, 2010. Additionally, HEP
used a portion to repay $42 million in outstanding HEP Credit Agreement borrowings, with the
remaining proceeds available for general partnership purposes, including working capital and
capital expenditures.
HEP also has $185 million in aggregate principal amount outstanding of 6.25% senior notes maturing
in March 2015 (the HEP 6.25% Senior Notes) that are registered with the SEC. The HEP 6.25%
Senior Notes and HEP 8.25% Senior Notes (collectively, the HEP Senior Notes) are unsecured and
impose certain restrictive covenants, including limitations on HEPs ability to incur additional
indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into
transactions with affiliates, and enter into mergers. At any time when the HEP Senior Notes are
rated investment grade by both Moodys and Standard & Poors and no default or event of default
exists, HEP will not be subject to many of the foregoing covenants. Additionally, HEP has certain
redemption rights under the HEP Senior Notes.
Indebtedness under the HEP Senior Notes is recourse to HEP Logistics Holdings, L.P., its general
partner, and guaranteed by HEPs wholly-owned subsidiaries. However, any recourse to the general
partner would be limited to the extent of HEP Logistics Holdings, L.P.s assets, which other than
its investment in HEP, are not significant. HEPs creditors have no other recourse to our assets.
Furthermore, our creditors have no recourse to the assets of HEP and its consolidated subsidiaries.
See Risk Management for a discussion of HEPs interest rate swap contracts.
Holly Financing Obligation
In October 2009, we sold approximately 400,000 barrels of crude oil tankage at our Tulsa Refinery
west facility as well as certain crude oil pipeline receiving facilities to an affiliate of Plains
All American Pipeline, L.P. (Plains) for $40 million in cash. In connection with this
transaction, we entered into a 15-year lease agreement with Plains, whereby we agreed to pay a
fixed monthly fee for the exclusive use of this tankage as well as a fee for volumes received at
the receiving facilities purchased by Plains. Additionally, we have a margin sharing agreement
with Plains under which we will equally share contango profits with Plains for crude oil purchased
by them and delivered to our Tulsa Refinery west facility for storage. Due to our continuing
involvement in these assets, this transaction has been accounted for as a financing obligation. As
a result, we retained these assets on our books and recorded a liability representing the $40
million in proceeds received.
Liquidity
We believe our current cash and cash equivalents, along with future internally generated cash flow
and funds available under our credit facilities will provide sufficient resources to fund currently
planned capital projects, including our planned integration of the Tulsa Refinery facilities, and
our liquidity needs for the foreseeable future. In addition, components of our growth strategy may
include construction of new refinery processing units and the expansion of existing units at our
facilities and selective acquisition of complementary assets for our refining operations intended
to increase earnings and cash flow. Our ability to acquire complementary assets will be dependent
upon several factors, including our ability to identify attractive acquisition candidates,
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consummate acquisitions on favorable terms, successfully integrate acquired assets and obtain
financing to fund acquisitions and to support our growth, and many other factors beyond our
control.
We consider all highly-liquid instruments with a maturity of three months or less at the time of
purchase to be cash equivalents. Cash equivalents are stated at cost, which approximates market
value, and are invested primarily in conservative, highly-rated instruments issued by financial
institutions or government entities with strong credit standings. As of March 31, 2011, we had
cash and cash equivalents of $224.1 million and short-term investments in marketable securities of
$48.9 million.
Cash and cash equivalents decreased by $5 million during the three months ended March 31, 2011.
Net cash used for investing activities of $141 million exceeded cash provided by operating
activities and financing activities of $130.5 million and $5.5 million, respectively. Working
capital increased by $26.4 million during the three months ended March 31, 2011.
Cash Flows Operating Activities
Three Months Ended March 31, 2011 Compared to Three Months Ended March 31, 2010
Net cash flows provided by operating activities were $130.5 million for the three months ended
March 31, 2011 compared to net cash used by operating activities of $90 million for the three
months ended March 31, 2010, an increase of $220.5 million. Net income for the three months ended
March 31, 2011 was $91 million, an increase of $114.3 million compared to a net loss of $23.3
million for the three months ended March 31, 2010. Non-cash adjustments consisting of depreciation
and amortization, deferred income taxes, equity-based compensation expense and fair value
adjustments to derivative instruments resulted in an increase to operating cash flows of $33.7
million for the three months ended March 31, 2011 compared to $10.1 million for the same period in
2010. Additionally, SLC Pipeline earnings, net of distributions decreased operating cash flows by
$0.4 million and $0.5 million for the three months ended March 31, 2011 and March 31, 2010,
respectively. Changes in working capital items increased cash flows by $18.9 million for the three
months ended March 31, 2011 compared to a decrease of $71.1 million for the three months ended
March 31, 2010. Additionally, for the three months ended March 31, 2011, turnaround expenditures
increased to $16.9 million from $7.3 million in 2010 due to a major maintenance turnaround project
at our Tulsa Refinery facilities that was completed in January 2011.
Cash Flows Investing Activities and Planned Capital Expenditures
Three Months Ended March 31, 2011 Compared to Three Months Ended March 31, 2010
Net cash flows used for investing activities were $141 million for the three months ended March 31,
2011 compared to $31.1 million for the three months ended March 31, 2010, an increase of $109.9
million. Cash expenditures for properties, plants and equipment for the first three months of 2011
increased to $74 million from $31.1 million for the same period in 2010. These include HEP capital
expenditures of $11.5 million and $1.9 million for the three months ended March 31, 2011 and 2010,
respectively. Capital expenditures were significantly higher in the three months ending March 31,
2011 due to construction of the UNEV Pipeline system. Also, for the three months ended March 31,
2011, we invested $98.9 million in marketable securities and received proceeds of $31.9 million
from the sale or maturity of marketable securities.
Planned Capital Expenditures
Holly Corporation
Each year our Board of Directors approves in our annual capital budget projects that our management
is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities
arise, other or special projects may be approved. The funds allocated for a particular capital
project may be expended over a period of several years, depending on the time required to complete
the project. Therefore, our planned capital expenditures for a given year consist of expenditures
approved for capital projects included in the current years capital budget as well as, in certain
cases, expenditures approved for capital projects in capital budgets for prior years. Our total
capital budget for 2011 is $142.4 million. Additionally, capital costs of $11.7 million have been
approved for refinery turnarounds and tank work. We expect to spend approximately $185 million in
capital costs in 2011, including capital projects approved in prior years. Our capital spending
for 2011 is comprised of $24 million for projects at the Navajo Refinery, $13 million for projects
at the Woods Cross Refinery, $70
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million for projects at the Tulsa Refinery, $69 million for our portion of the UNEV Pipeline
project, $3 million for asphalt plant projects and $6 million for marketing-related and
miscellaneous projects. The following summarizes our key capital projects.
We are proceeding with the integration project of our Tulsa Refinery west and east facilities.
Upon completion, the Tulsa Refinery will have an integrated crude processing rate of 125,000 BPSD.
The integration project involves the installation of interconnect pipelines that will permit us to
transfer various intermediate streams between the two facilities. Currently, we are using an
existing third-party line for the transfer of intermediates from the west facility to the east
facility under a 10-year agreement. These interconnect lines will allow us to eliminate the sale
of gas oil at a discount to WTI under our 5-year gas oil off take agreement with a third party,
optimize gasoline blending, increase our utilization of better process technology, improve yields
and reduce operating costs. HEP is currently constructing five additional interconnect pipelines
and we are currently negotiating terms for a long-term agreement with HEP to transfer intermediate
products via these pipelines that will commence upon completion of the project. Also, as part of
the integration, during the first quarter of 2011 we completed the expansion of the diesel
hydrotreating unit at the east facility at an expected cost of $27 million. This expanded unit will
permit the processing of all high sulfur diesel produced to ULSD once the interconnecting pipelines
are complete and available to move high sulfur diesel and hydrogen produced in the west facility to
the east facility. We are currently planning to complete the integration projects in the summer of
2011.
The combined Tulsa Refinery facilities also will be required to comply with new MSAT2 regulations
in order to meet new federal benzene reduction requirements for gasoline. We have elected to
largely use existing equipment at the Tulsa Refinery east facility to split reformate from
reformers at both west and east facilities and install a new benzene saturation unit to achieve the
required benzene reduction at an estimated cost of $28.5 million. We will be required to buy
benzene credits to get the gasoline pool below 0.62% by volume until this project is complete, as
required by law, beginning in 2011. There is an additional requirement to meet 1.3% benzene levels
on an annual average beginning in July 2012. We expect to complete this project well before then.
Our consent decree with the EPA requires recovery of sulfur from the refinery fuel gas system and
the shutdown or replacement of two low pressure boilers at the Tulsa Refinery west facility by the
end of 2013. Our Board of Directors have approved a project for $44 million which would meet these
requirements as well as increase our ability to run additional lower priced sour crude types at the
Tulsa Refinery east facility. Also, we are evaluating the best solution to the low pressure boiler
issue. In addition to the consent decree requirements, flare gas recovery and coker blowdown
modifications are required to comply with new flare regulations at an estimated cost of $10
million.
The Navajo Refinery currently plans to comply with the new MSAT2 regulations by the fractionation
of naphtha with existing equipment to achieve benzene in gasoline levels below 1.3% . The Navajo
Refinery will purchase or use credits generated at the Tulsa Refinery to reduce benzene content to
the required 0.62%. Due to our acquisition of the Tulsa Refinery facilities from Sunoco and
Sinclair, our Navajo Refinery has until the end of 2011 to comply with the MSAT2 regulations
because we no longer qualify for the small refiners exemption. Also, we will be installing a new
storm water surge tank and upgrade several other processes at the refinerys Artesia waste water
treatment plant. These projects are expected to cost approximately $17 million.
Our Woods Cross Refinery is required to install a wet gas scrubber on its FCC unit by the end of
2012. We estimate the total cost to be $12 million. The MSAT2 solution for the refinery involves
revamping its naphtha fractionation unit and installing a benzene saturation unit at an estimated
cost of $10 million. These projects will reduce benzene levels in gasoline below the 1.3% annual
average level. The Woods Cross Refinery will purchase credits to meet the 0.62% benzene
requirement. Like our Navajo Refinery, our Woods Cross Refinery has until the end of 2011 to
comply with the MSAT2 regulations.
Under a definitive agreement with Sinclair, we are jointly building the UNEV Pipeline, a 12-inch
refined products pipeline from Salt Lake City, Utah to Las Vegas, Nevada, together with terminal
facilities in the Cedar City, Utah and North Las Vegas areas. Under the agreement, we own a 75%
interest in the joint venture pipeline with Sinclair, our joint venture partner, owning the
remaining 25% interest. The initial capacity of the pipeline will be 62,000 BPD (based on gasoline
equivalents), with the capacity for further expansion to 120,000 BPD.
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The current total cost of the pipeline project including terminals is expected to be approximately
in the $340 million range, with our share of the cost totaling $255 million. This project includes
the construction of ethanol blending and storage facilities at the Cedar City terminal. The
pipeline is in the final construction phase and is expected to be mechanically complete in the
third quarter of 2011.
In connection with this project, we have entered into a 10-year commitment to ship an annual
average of 15,000 barrels per day of refined products on the UNEV Pipeline at an agreed tariff.
Our commitment for each year is subject to reduction by up to 5,000 barrels per day in specified
circumstances relating to shipments by other shippers. We have an option agreement with
HEP granting them an option to purchase all of our equity interests in this joint venture pipeline
effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase
price equal to our investment in this joint venture pipeline plus interest at 7% per annum.
Regulatory compliance items or other presently existing or future environmental regulations /
consent decrees could cause us to make additional capital investments beyond those described above
and incur additional operating costs to meet applicable requirements.
HEP
Each year the Holly Logistic Services, L.L.C. board of directors approves HEPs annual capital
budget, which specifies capital projects that HEP management is authorized to undertake.
Additionally, at times when conditions warrant or as new opportunities arise, special projects may
be approved. The funds allocated for a particular capital project may be expended over a period of
several years, depending on the time required to complete the project. Therefore, HEPs planned
capital expenditures for a given year consist of expenditures approved for capital projects
included in its current year capital budget as well as, in certain cases, expenditures approved for
capital projects in capital budgets for prior years. The 2011 HEP capital budget is comprised of
$5.8 million for maintenance capital expenditures and $20.1 million for expansion capital
expenditures.
As described under our Tulsa Refinery integration project, HEP is currently constructing five
interconnecting pipelines between our Tulsa east and west refining facilities. The project is
expected to cost approximately $35 million with completion in the summer of 2011. We are currently
negotiating terms for a long-term agreement with HEP to transfer intermediate products via these
pipelines that will commence upon completion of the project.
Cash Flows Financing Activities
Three Months Ended March 31, 2011 Compared to Three Months Ended March 31, 2010
Net cash flows provided by financing activities were $5.5 million for the three months ended March
31, 2011 compared to $89.8 million for the three months ended March 31, 2010, a decrease of $84.3
million. During the three months ended March 31, 2011, we paid $0.3 million under our financing
obligation to Plains, purchased $2.1 million in common stock from employees to provide funds for
the payment of payroll and income taxes due upon the vesting of certain share-based incentive
awards, paid $8 million in dividends, received an $8.5 million contribution from our UNEV Pipeline
joint venture partner and recognized $0.3 million excess tax benefit on our equity based
compensation. During the three months ended March 31, 2011, HEP received $30 million and repaid $7
million under the HEP Credit Agreement, paid distributions of $12.5 million to noncontrolling
interests, incurred $3 million in deferred financing costs and purchased $0.4 million in HEP common
units in the open market for recipients of its restricted unit grants. During the three months
ended March 31, 2010, we received and repaid $310 million in advances under the Holly Credit
Agreement, paid $0.2 million under our financing obligation to Plains, paid $7.9 million in
dividends, purchased $1.1 million in common stock from employees to provide funds for the payment
of payroll and income taxes due upon the vesting of certain share-based incentive awards, received
a $1.3 million contribution from our UNEV Pipeline joint venture partner and recognized $1 million
in excess tax expense on our equity based compensation. During the three months ended March 31,
2010, HEP received $147.5 million in net proceeds upon the issuance of the HEP 8.25% Senior Notes,
received $33 million and repaid $68 million under the HEP Credit Agreement, paid distributions of
$12 million to noncontrolling interests and purchased $1.7 million in HEP common units in the open
market for recipients of its restricted unit grants.
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Contractual Obligations and Commitments
Holly Corporation
There were no significant changes to our contractual obligations during the three months ended
March 31, 2011.
HEP
In February 2011, HEP amended its previous credit agreement (expiring in August 2011), slightly,
reducing the size of the credit facility from $300 million to $275 million. The size was reduced
based on managements review of past and forecasted utilization of the facility. The HEP
Credit Agreement expires in February 2016; however, in the event that the 6.25% HEP Senior Notes
are not repurchased, refinanced, extended or repaid prior to September 1, 2014, the HEP Credit
Agreement will expire on that date. During the three months ended March 31, 2011, HEP received net
advances of $23 million resulting in $182 million of outstanding principal under the HEP Credit
Agreement at March 31, 2011.
There were no other significant changes to HEPs long-term contractual obligations during this
period.
CRITICAL ACCOUNTING POLICIES
Our discussion and analysis of our financial condition and results of operations are based upon our
consolidated financial statements, which have been prepared in accordance with accounting
principles generally accepted in the United States. The preparation of these financial statements
requires us to make estimates and judgments that affect the reported amounts of assets,
liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities as
of the date of the financial statements. Actual results may differ from these estimates under
different assumptions or conditions.
Our significant accounting policies are described in Item 7. Managements Discussion and Analysis
of Financial Condition and Results of Operations Critical Accounting Policies in our Annual
Report on Form 10-K for the year ended December 31, 2010. Certain critical accounting policies
that materially affect the amounts recorded in our consolidated financial statements are the use of
the LIFO method of valuing certain inventories, the amortization of deferred costs for regular
major maintenance and repairs at our refineries, assessing the possible impairment of certain
long-lived assets, and assessing contingent liabilities for probable losses. There have been no
changes to these policies in 2011.
We use the LIFO method of valuing inventory. Under the LIFO method, an actual valuation of
inventory can only be made at the end of each year based on the inventory levels. Accordingly,
interim LIFO calculations are based on managements estimates of expected year-end inventory levels
and are subject to the final year-end LIFO inventory valuation.
RISK MANAGEMENT
We use certain strategies to reduce some commodity price and operational risks. We do not attempt
to eliminate all market risk exposures when we believe that the exposure relating to such risk
would not be significant to our future earnings, financial position, capital resources or liquidity
or that the cost of eliminating the exposure would outweigh the benefit.
Commodity Price Risk Management
Our primary market risk is commodity price risk. We are exposed to market risks related to the
volatility in crude oil and refined products, as well as volatility in the price of natural gas
used in our refining operations.
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We periodically enter into derivative contracts in the form of commodity price swaps to mitigate
price exposure with respect to:
| our inventory positions; |
| natural gas purchases; |
| costs of crude oil; |
| prices of refined products; and |
| our refining margins. |
As of March 31, 2011, we have outstanding commodity price swap contracts serving as economic hedges
to protect the value of a temporary crude oil inventory build of 105,000 barrels against price
volatility and to protect refining margins on forecasted sales of 6.2 million barrels of produced
gasoline. These contracts are measured quarterly at fair value with offsetting adjustments (gains /
losses) recorded directly to cost of products sold.
Interest Rate Risk Management
HEP uses interest rate swaps to manage its exposure to interest rate risk.
As of March 31, 2011, HEP has an interest rate swap that hedges its exposure to the cash flow risk
caused by the effects of LIBOR changes on a $155 million HEP Credit Agreement advance. This
interest rate swap effectively converts $155 million of LIBOR based debt to fixed rate debt having
an interest rate of 3.74% plus an applicable margin, currently 2.5%, which equaled an effective
interest rate of 6.24% as of March 31, 2011. This interest rate swap contract has been designated
as a cash flow hedge and matures in February 2013.
This contract initially hedged variable LIBOR interest on $171 million in outstanding HEP Credit
Agreement debt. In May 2010, HEP repaid $16 million of the HEP Credit Agreement debt and also
settled a corresponding portion of its interest rate swap agreement having a notional amount of $16
million for $1.1 million. Upon payment, HEP reduced its swap liability and reclassified a $1.1
million charge from accumulated other comprehensive loss to interest expense, representing the
application of hedge accounting prior to settlement.
The following table presents balance sheet locations and related fair values of outstanding
derivative instruments.
Balance Sheet | Location of Offsetting | Offsetting | ||||||||||||||
Derivative Instruments | Location | Fair Value | Balance | Amount | ||||||||||||
(Dollars in thousands) | ||||||||||||||||
March 31, 2011 |
||||||||||||||||
Derivative designated as cash flow hedging instrument: |
||||||||||||||||
Variable-to-fixed interest rate swap contract
($155 million LIBOR based debt interest
payments) |
Other long-term liabilities | $ | 8,743 | Accumulated other comprehensive loss | $ | 8,743 | ||||||||||
Derivatives not designated as hedging instruments: |
||||||||||||||||
Variable-to-fixed commodity price swap contracts
(various inventory positions) |
Prepayments and other current assets | $ | 6,555 | Cost of products sold (decrease) | $ | 6,555 | ||||||||||
Fixed/variable-to-variable/fixed commodity price
contracts (various inventory positions) |
Accrued liabilities | $ | 5,960 | Cost of products sold (increase) | $ | 5,960 | ||||||||||
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Balance Sheet | Location of Offsetting | Offsetting | ||||||||||||||
Derivative Instruments | Location | Fair Value | Balance | Amount | ||||||||||||
(Dollars in thousands) | ||||||||||||||||
December 31, 2010 |
||||||||||||||||
Derivative designated as cash flow hedging instruments: |
||||||||||||||||
Variable-to-fixed commodity price swap contracts
(forecasted volumes of natural gas
purchases) |
Accrued liabilities | $ | 38 | Accumulated other comprehensive loss | $ | 38 | ||||||||||
Variable-to-fixed interest rate swap contract
($155 million LIBOR based debt interest
payments) |
Other long-term liabilities | $ | 10,026 | Accumulated other comprehensive loss | $ | 10,026 | ||||||||||
Derivatives not designated as hedging instruments: |
||||||||||||||||
Fixed-to-variable rate swap contracts
(various inventory positions) |
Accrued liabilities | $ | 497 | Cost of products sold (increase) | $ | 497 | ||||||||||
For the three months ended March 31, 2011, maturities and fair value adjustments attributable
to our economic hedges resulted in a $3.7 million increase to costs of products sold.
For the three months ended March 31, 2010, HEP recognized $1.5 million in charges to interest
expense as a result of fair value changes to interest rate swap contracts that were settled in the
first quarter of 2010.
There was no ineffectiveness on the cash flow hedges during the periods covered in these
consolidated financial statements.
Publicly available information is reviewed on the counterparties in order to review and monitor
their financial stability and assess their ongoing ability to honor their commitments under the
swap contracts. These counterparties are large financial institutions. We have not experienced,
nor do we expect to experience, any difficulty in the counterparties honoring their commitments.
The market risk inherent in our fixed-rate debt and positions is the potential change arising from
increases or decreases in interest rates as discussed below.
At March 31, 2011, outstanding principal under the Holly 9.875% Senior Notes, HEP 6.25% Senior
Notes and HEP 8.25% Senior Notes was $300 million, $185 million and $150 million, respectively.
For these fixed rate notes, changes in interest rates will generally affect fair value of the debt,
but not our earnings or cash flows. At March 31, 2011, the estimated fair values of the Holly
9.875% Senior Notes, HEP 6.25% Senior Notes and HEP 8.25% Senior Notes were $338.3 million, $185
million and $160.5 million, respectively. We estimate that a hypothetical 10% change in the
yield-to-maturity rates applicable to these notes would result in a fair value change to the notes
of approximately $12.5 million, $4.2 million and $6 million, respectively.
For the variable rate HEP Credit Agreement, changes in interest rates would affect cash flows, but
not the fair value. At March 31, 2011, borrowings outstanding under the HEP Credit Agreement were
$182 million. By means of its cash flow hedge, HEP has effectively converted the variable rate on
$155 million of outstanding principal to a fixed rate of 6.24%. For the unhedged $27 million
portion, a hypothetical 10% change in interest rates applicable to the HEP Credit Agreement would
not materially affect cash flows.
At March 31, 2011, cash and cash equivalents included investments in investment grade, highly
liquid investments with maturities of three months or less at the time of purchase and hence the
interest rate market risk implicit in these cash investments is low. Due to the short-term nature
of our cash and cash equivalents, a hypothetical 10% increase in interest rates would not have a
material effect on the fair market value of our portfolio. Since we have the ability to liquidate
this portfolio, we do not expect our operating results or cash flows to be materially affected by
the effect of a sudden change in market interest rates on our investment portfolio.
Our operations are subject to normal hazards of operations, including fire, explosion and
weather-related perils. We maintain various insurance coverages, including business interruption
insurance, subject to certain deductibles. We are not fully insured against certain risks because
such risks are not fully insurable, coverage is unavailable, or premium costs, in our judgment, do
not justify such expenditures.
We have a risk management oversight committee that is made up of members from our senior
management. This committee oversees our risk enterprise program, monitors our risk environment and
provides direction for activities to mitigate identified risks that may adversely affect the
achievement of our goals.
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Item 3. Quantitative and Qualitative Disclosures About Market Risk
See Risk Management under Managements Discussion and Analysis of Financial Condition and
Results of Operations.
Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles
Reconciliations of earnings before interest, taxes, depreciation and amortization (EBITDA) to
amounts reported under generally accepted accounting principles in financial statements.
Earnings before interest, taxes, depreciation and amortization, which we refer to as EBITDA, is
calculated as net income attributable to Holly Corporation stockholders plus (i) interest expense,
net of interest income, (ii) income tax provision, and (iii) depreciation and amortization. EBITDA
is not a calculation provided for under GAAP; however, the amounts included in the EBITDA
calculation are derived from amounts included in our consolidated financial statements. EBITDA
should not be considered as an alternative to net income or operating income as an indication of
our operating performance or as an alternative to operating cash flow as a measure of liquidity.
EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is
presented here because it is a widely used financial indicator used by investors and analysts to
measure performance. EBITDA is also used by our management for internal analysis and as a basis
for financial covenants.
Set forth below is our calculation of EBITDA.
Three Months Ended | ||||||||
March 31, | ||||||||
2011 | 2010 | |||||||
(In thousands) | ||||||||
Net income (loss) attributable to Holly Corporation stockholders |
$ | 84,694 | $ | (28,094 | ) | |||
Add income tax provision (subtract benefit) |
49,011 | (16,672 | ) | |||||
Add interest expense |
16,204 | 17,722 | ||||||
Subtract interest income |
(85 | ) | (59 | ) | ||||
Add depreciation and amortization |
31,308 | 27,757 | ||||||
EBITDA |
$ | 181,132 | $ | 654 | ||||
Reconciliations of refinery operating information (non-GAAP performance measures) to amounts
reported under generally accepted accounting principles in financial statements.
Refinery gross margin and net operating margin are non-GAAP performance measures that are used by
our management and others to compare our refining performance to that of other companies in our
industry. We believe these margin measures are helpful to investors in evaluating our refining
performance on a relative and absolute basis.
We calculate refinery gross margin and net operating margin using net sales, cost of products and
operating expenses, in each case averaged per produced barrel sold. These two margins do not
include the effect of depreciation and amortization. Each of these component performance measures
can be reconciled directly to our Consolidated Statements of Income.
Other companies in our industry may not calculate these performance measures in the same manner.
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Refinery Gross Margin
Refinery gross margin per barrel is the difference between average net sales price and average cost
of products per barrel of produced refined products. Refinery gross margin for each of our
refineries and for our three refineries on a consolidated basis is calculated as shown below.
Three Months Ended | ||||||||
March 31, | ||||||||
2011 | 2010 | |||||||
Average per produced barrel: |
||||||||
Navajo Refinery |
||||||||
Net sales |
$ | 110.99 | $ | 88.06 | ||||
Less cost of products |
95.60 | 82.96 | ||||||
Refinery gross margin |
$ | 15.39 | $ | 5.10 | ||||
Woods Cross Refinery |
||||||||
Net sales |
$ | 108.77 | $ | 89.52 | ||||
Less cost of products |
89.87 | 74.72 | ||||||
Refinery gross margin |
$ | 18.90 | $ | 14.80 | ||||
Tulsa Refinery |
||||||||
Net sales |
$ | 115.29 | $ | 86.22 | ||||
Less cost of products |
100.50 | 82.89 | ||||||
Refinery gross margin |
$ | 14.79 | $ | 3.33 | ||||
Consolidated |
||||||||
Net sales |
$ | 113.28 | $ | 87.40 | ||||
Less cost of products |
97.56 | 81.84 | ||||||
Refinery gross margin |
$ | 15.72 | $ | 5.56 | ||||
Net Operating Margin
Net operating margin per barrel is the difference between refinery gross margin and refinery
operating expenses per barrel of produced refined products. Net operating margin for each of our
refineries and for our three refineries on a consolidated basis is calculated as shown below.
Three Months Ended | ||||||||
March 31, | ||||||||
2011 | 2010 | |||||||
Average per produced barrel: |
||||||||
Navajo Refinery |
||||||||
Refinery gross margin |
$ | 15.39 | $ | 5.10 | ||||
Less refinery operating expenses |
6.34 | 5.18 | ||||||
Net operating margin |
$ | 9.05 | $ | (0.08 | ) | |||
Woods Cross Refinery |
||||||||
Refinery gross margin |
$ | 18.90 | $ | 14.80 | ||||
Less refinery operating expenses |
6.43 | 6.20 | ||||||
Net operating margin |
$ | 12.47 | $ | 8.60 | ||||
Tulsa Refinery |
||||||||
Refinery gross margin |
$ | 14.79 | $ | 3.33 | ||||
Less refinery operating expenses |
5.98 | 5.91 | ||||||
Net operating margin |
$ | 8.81 | $ | (2.58 | ) | |||
Consolidated |
||||||||
Refinery gross margin |
$ | 15.72 | $ | 5.56 | ||||
Less refinery operating expenses |
6.24 | 5.65 | ||||||
Net operating margin |
$ | 9.48 | $ | (0.09 | ) | |||
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Below are reconciliations to our Consolidated Statements of Income for (i) net sales, cost of
products and operating expenses, in each case averaged per produced barrel sold, and (ii) net
operating margin and refinery gross margin. Due to rounding of reported numbers, some amounts may
not calculate exactly.
Reconciliations of refined product sales from produced products sold to total sales and other
revenues
Three Months Ended | ||||||||
March 31, | ||||||||
2011 | 2010 | |||||||
Navajo Refinery |
||||||||
Average sales price per produced barrel sold |
$ | 110.99 | $ | 88.06 | ||||
Times sales of produced refined products sold (BPD) |
79,840 | 86,930 | ||||||
Times number of days in period |
90 | 90 | ||||||
Refined product sales from produced products sold |
$ | 797,530 | $ | 688,955 | ||||
Woods Cross Refinery |
||||||||
Average sales price per produced barrel sold |
$ | 108.77 | $ | 89.52 | ||||
Times sales of produced refined products sold (BPD) |
26,650 | 28,170 | ||||||
Times number of days in period |
90 | 90 | ||||||
Refined product sales from produced products sold |
$ | 260,885 | $ | 226,960 | ||||
Tulsa Refinery |
||||||||
Average sales price per produced barrel sold |
$ | 115.29 | $ | 86.22 | ||||
Times sales of produced refined products sold (BPD) |
100,010 | 98,760 | ||||||
Times number of days in period |
90 | 90 | ||||||
Refined product sales from produced products sold |
$ | 1,037,714 | $ | 766,358 | ||||
Sum of refined products sales from produced products sold from our three refineries (1) |
$ | 2,096,129 | $ | 1,682,273 | ||||
Add refined product sales from purchased products and rounding (2) |
75,804 | 41,506 | ||||||
Total refined products sales |
2,171,933 | 1,723,779 | ||||||
Add direct sales of excess crude oil (3) |
135,409 | 134,862 | ||||||
Add other refining segment revenue (4) |
7,750 | 8,533 | ||||||
Total refining segment revenue |
2,315,092 | 1,867,174 | ||||||
Add HEP segment sales and other revenues |
45,005 | 40,689 | ||||||
Add corporate and other revenues |
648 | 66 | ||||||
Subtract consolidations and eliminations |
(34,160 | ) | (33,639 | ) | ||||
Sales and other revenues |
$ | 2,326,585 | $ | 1,874,290 | ||||
(1) | The above calculations of refined product sales from produced products sold can also be computed on a consolidated basis. These amounts may not calculate exactly due to rounding of reported numbers. | |
(2) | We purchase finished products when opportunities arise that provide a profit on the sale of such products, or to meet delivery commitments. | |
(3) | We purchase crude oil that at times exceeds the supply needs of our refineries. Quantities in excess of our needs are sold at market prices to purchasers of crude oil that are recorded on a gross basis with the sales price recorded as revenues and the corresponding acquisition cost as inventory and then upon sale as cost of products sold. Additionally, we enter into buy/sell exchanges of crude oil with certain parties to facilitate the delivery of quantities to certain locations that are netted at carryover cost. | |
(4) | Other refining segment revenue includes the revenues associated with Holly Asphalt and revenue derived from feedstock and sulfur credit sales. |
Three Months Ended | ||||||||
March 31, | ||||||||
2011 | 2010 | |||||||
Average sales price per produced barrel sold |
$ | 113.28 | $ | 87.40 | ||||
Times sales of produced refined products sold (BPD) |
206,500 | 213,860 | ||||||
Times number of days in period |
90 | 90 | ||||||
Refined product sales from produced products sold |
$ | 2,096,129 | $ | 1,682,273 | ||||
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Reconciliation of average cost of products per produced barrel sold to total cost of
products sold
Three Months Ended | ||||||||
March 31, | ||||||||
2011 | 2010 | |||||||
Navajo Refinery |
||||||||
Average cost of products per produced barrel sold |
$ | 95.60 | $ | 82.96 | ||||
Times sales of produced refined products sold (BPD) |
79,840 | 86,930 | ||||||
Times number of days in period |
90 | 90 | ||||||
Cost of products for produced products sold |
$ | 686,943 | $ | 649,054 | ||||
Woods Cross Refinery |
||||||||
Average cost of products per produced barrel sold |
$ | 89.87 | $ | 74.72 | ||||
Times sales of produced refined products sold (BPD) |
26,650 | 28,170 | ||||||
Times number of days in period |
90 | 90 | ||||||
Cost of products for produced products sold |
$ | 215,553 | $ | 189,438 | ||||
Tulsa Refinery |
||||||||
Average cost of products per produced barrel sold |
$ | 100.50 | $ | 82.89 | ||||
Times sales of produced refined products sold (BPD) |
100,010 | 98,760 | ||||||
Times number of days in period |
90 | 90 | ||||||
Cost of products for produced products sold |
$ | 904,590 | $ | 736,759 | ||||
Sum of cost of products for produced products sold from our three refineries (1) |
$ | 1,807,086 | $ | 1,575,251 | ||||
Add refined product costs from purchased products sold and rounding (2) |
75,622 | 41,464 | ||||||
Total refined cost of products sold |
1,882,708 | 1,616,715 | ||||||
Add crude oil cost of direct sales of excess crude oil (3) |
132,880 | 133,667 | ||||||
Add other refining segment cost of products sold (4) |
2,338 | 6,051 | ||||||
Total refining segment cost of products sold |
2,017,926 | 1,756,433 | ||||||
Subtract consolidations and eliminations |
(33,309 | ) | (32,569 | ) | ||||
Costs of products sold (exclusive of depreciation and amortization) |
$ | 1,984,617 | $ | 1,723,864 | ||||
(1) | The above calculations of cost of products for produced products sold can also be computed on a consolidated basis. These amounts may not calculate exactly due to rounding of reported numbers. | |
(2) | We purchase finished products when opportunities arise that provide a profit on the sale of such products, or to meet delivery commitments. | |
(3) | We purchase crude oil that at times exceeds the supply needs of our refineries. Quantities in excess of our needs are sold at market prices to purchasers of crude oil that are recorded on a gross basis with the sales price recorded as revenues and the corresponding acquisition cost as inventory and then upon sale as cost of products sold. Additionally, we enter into buy/sell exchanges of crude oil with certain parties to facilitate the delivery of quantities to certain locations that are netted at carryover cost. | |
(4) | Other refining segment cost of products sold includes the cost of products for Holly Asphalt and costs attributable to feedstock and sulfur credit sales. |
Three Months Ended | ||||||||
March 31, | ||||||||
2011 | 2010 | |||||||
Average cost of products per produced barrel sold |
$ | 97.56 | $ | 81.84 | ||||
Times sales of produced refined products sold (BPD) |
206,500 | 213,860 | ||||||
Times number of days in period |
90 | 90 | ||||||
Cost of products for produced products sold |
$ | 1,807,086 | $ | 1,575,251 | ||||
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Reconciliation of average refinery operating expenses per produced barrel sold to total
operating expenses
Three Months Ended | ||||||||
March 31, | ||||||||
2011 | 2010 | |||||||
Navajo Refinery |
||||||||
Average refinery operating expenses per produced barrel sold |
$ | 6.34 | $ | 5.18 | ||||
Times sales of produced refined products sold (BPD) |
79,840 | 86,930 | ||||||
Times number of days in period |
90 | 90 | ||||||
Refinery operating expenses for produced products sold |
$ | 45,557 | $ | 40,527 | ||||
Woods Cross Refinery |
||||||||
Average refinery operating expenses per produced barrel sold |
$ | 6.43 | $ | 6.20 | ||||
Times sales of produced refined products sold (BPD) |
26,650 | 28,170 | ||||||
Times number of days in period |
90 | 90 | ||||||
Refinery operating expenses for produced products sold |
$ | 15,422 | $ | 15,719 | ||||
Tulsa Refinery |
||||||||
Average refinery operating expenses per produced barrel sold |
$ | 5.98 | $ | 5.91 | ||||
Times sales of produced refined products sold (BPD) |
100,010 | 98,760 | ||||||
Times number of days in period |
90 | 90 | ||||||
Refinery operating expenses for produced products sold |
$ | 53,825 | $ | 52,530 | ||||
Sum of refinery operating expenses per produced products sold from our three
refineries (1) |
$ | 114,804 | $ | 108,776 | ||||
Add other refining segment operating expenses and rounding (2) |
7,275 | 5,818 | ||||||
Total refining segment operating expenses |
122,079 | 114,594 | ||||||
Add HEP segment operating expenses |
12,796 | 13,060 | ||||||
Add corporate and other costs |
(6 | ) | 6 | |||||
Subtract consolidations and eliminations |
(126 | ) | (116 | ) | ||||
Operating expenses (exclusive of depreciation and amortization) |
$ | 134,743 | $ | 127,544 | ||||
(1) | The above calculations of refinery operating expenses from produced products sold can also be computed on a consolidated basis. These amounts may not calculate exactly due to rounding of reported numbers. | |
(2) | Other refining segment operating expenses include the marketing costs associated with our refining segment and the operating expenses of Holly Asphalt. |
Three Months Ended | ||||||||
March 31, | ||||||||
2011 | 2010 | |||||||
Average refinery operating expenses per produced barrel sold |
$ | 6.24 | $ | 5.65 | ||||
Times sales of produced refined products sold (BPD) |
206,500 | 213,860 | ||||||
Times number of days in period |
90 | 90 | ||||||
Refinery operating expenses for produced products sold |
$ | 114,804 | $ | 108,776 | ||||
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Reconciliation of net operating margin per barrel to refinery gross margin per barrel to
total sales and other revenues
Three Months Ended | ||||||||
March 31, | ||||||||
2011 | 2010 | |||||||
Navajo Refinery |
||||||||
Net operating margin per barrel |
$ | 9.05 | $ | (0.08 | ) | |||
Add average refinery operating expenses per produced barrel |
6.34 | 5.18 | ||||||
Refinery gross margin per barrel |
15.39 | 5.10 | ||||||
Add average cost of products per produced barrel sold |
95.60 | 82.96 | ||||||
Average sales price per produced barrel sold |
$ | 110.99 | $ | 88.06 | ||||
Times sales of produced refined products sold (BPD) |
79,840 | 86,930 | ||||||
Times number of days in period |
90 | 90 | ||||||
Refined products sales from produced products sold |
$ | 797,530 | $ | 688,955 | ||||
Woods Cross Refinery |
||||||||
Net operating margin per barrel |
$ | 12.47 | $ | 8.60 | ||||
Add average refinery operating expenses per produced barrel |
6.43 | 6.20 | ||||||
Refinery gross margin per barrel |
18.90 | 14.80 | ||||||
Add average cost of products per produced barrel sold |
89.87 | 74.72 | ||||||
Average sales price per produced barrel sold |
$ | 108.77 | $ | 89.52 | ||||
Times sales of produced refined products sold (BPD) |
26,650 | 28,170 | ||||||
Times number of days in period |
90 | 90 | ||||||
Refined products sales from produced products sold |
$ | 260,885 | $ | 226,960 | ||||
Tulsa Refinery |
||||||||
Net operating margin per barrel |
$ | 8.81 | $ | (2.58 | ) | |||
Add average refinery operating expenses per produced barrel |
5.98 | 5.91 | ||||||
Refinery gross margin per barrel |
14.79 | 3.33 | ||||||
Add average cost of products per produced barrel sold |
100.50 | 82.89 | ||||||
Average sales price per produced barrel sold |
$ | 115.29 | $ | 86.22 | ||||
Times sales of produced refined products sold (BPD) |
100,010 | 98,760 | ||||||
Times number of days in period |
90 | 90 | ||||||
Refined products sales from produced products sold |
$ | 1,037,714 | $ | 766,358 | ||||
Sum of refined products sales from produced products sold from our three refineries (1) |
$ | 2,096,129 | $ | 1,682,273 | ||||
Add refined product sales from purchased products and rounding (2) |
75,804 | 41,506 | ||||||
Total refined products sales |
2,171,933 | 1,723,779 | ||||||
Add direct sales of excess crude oil (3) |
135,409 | 134,862 | ||||||
Add other refining segment revenue (4) |
7,750 | 8,533 | ||||||
Total refining segment revenue |
2,315,092 | 1,867,174 | ||||||
Add HEP segment sales and other revenues |
45,005 | 40,689 | ||||||
Add corporate and other revenues |
648 | 66 | ||||||
Subtract consolidations and eliminations |
(34,160 | ) | (33,639 | ) | ||||
Sales and other revenues |
$ | 2,326,585 | $ | 1,874,290 | ||||
(1) | The above calculations of refined product sales from produced products sold can also be computed on a consolidated basis. These amounts may not calculate exactly due to rounding of reported numbers. | |
(2) | We purchase finished products when opportunities arise that provide a profit on the sale of such products or to meet delivery commitments. | |
(3) | We purchase crude oil that at times exceeds the supply needs of our refineries. Quantities in excess of our needs are sold at market prices to purchasers of crude oil that are recorded on a gross basis with the sales price recorded as revenues and the corresponding acquisition cost as inventory and then upon sale as cost of products sold. Additionally, we enter into buy/sell exchanges of crude oil with certain parties to facilitate the delivery of quantities to certain locations that are netted at carryover cost. | |
(4) | Other refining segment revenue includes the revenues associated with Holly Asphalt and revenue derived from feedstock and sulfur credit sales. |
- 47 -
Table of Contents
Three Months Ended | ||||||||
March 31, | ||||||||
2011 | 2010 | |||||||
Net operating margin per barrel |
$ | 9.48 | $ | (0.09 | ) | |||
Add average refinery operating expenses per produced barrel |
6.24 | 5.65 | ||||||
Refinery gross margin per barrel |
15.72 | 5.56 | ||||||
Add average cost of products per produced barrel sold |
97.56 | 81.84 | ||||||
Average sales price per produced barrel sold |
$ | 113.28 | $ | 87.40 | ||||
Times sales of produced refined products sold (BPD) |
206,500 | 213,860 | ||||||
Times number of days in period |
90 | 90 | ||||||
Refined product sales from produced products sold |
$ | 2,096,129 | $ | 1,682,273 | ||||
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Item 4. Controls and Procedures
Evaluation of disclosure controls and procedures. Our principal executive officer and principal
financial officer have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act
of 1934 (the Exchange Act), 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
on Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance
that the information we are required to disclose in the reports that we file or submit 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 Securities and Exchange Commissions rules and forms. Based upon the evaluation,
our principal executive officer and principal financial officer have concluded that our disclosure
controls and procedures were effective as of March 31, 2011.
Changes in internal control over financial reporting. There have been no changes in our internal
control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that
occurred during our last fiscal quarter that have materially affected or are reasonably likely to
materially affect our internal control over financial reporting.
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PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Commitment and Contingency Reserves
When deemed necessary, we establish reserves for certain legal proceedings. The establishment of a
reserve involves an estimation process that includes the advice of legal counsel and subjective
judgment of management. While management believes these reserves to be adequate, future changes in
the facts and circumstances could result in the actual liability exceeding the estimated ranges of
loss and amounts accrued.
While the outcome and impact on us cannot be predicted with certainty, management believes that the
resolution of these proceedings through settlement or adverse judgment will not have a material
adverse effect on our consolidated financial position or cash flow. Operating results, however,
could be significantly impacted in the reporting periods in which such matters are resolved.
SFPP Litigation
a. The Early Complaint Cases
In May 2007, the United States Court of Appeals for the District of Columbia Circuit (Court of
Appeals) issued its decision on petitions for review, brought by us and other parties, concerning
rulings by the FERC in proceedings brought by us and other parties against SFPP. These proceedings
relate to tariffs of common carrier pipelines, which are owned and operated by SFPP, for shipments
of refined products from El Paso, Texas to Tucson and Phoenix, Arizona and from points in
California to points in Arizona. We are one of several refiners that regularly utilize the SFPP
pipeline to ship refined products from El Paso, Texas to Tucson and Phoenix, Arizona on SFPPs East
Line. The Court of Appeals in its May 2007 decision approved a FERC position, which is adverse to
us, on the treatment of income taxes in the calculation of allowable rates for pipelines operated
as limited partnerships and ruled in our favor on an issue relating to our rights to reparations
when it is determined that certain tariffs we paid to SFPP in the past were too high. The case was
remanded to FERC and consolidated with other cases that together addressed SFPPs rates for the
period from January 1992 through May 2006. In 2003 we received an initial payment of $15.3 million
from SFPP as reparations for the period from 1992 through July 2000. On April 16, 2010, a
settlement among us, SFPP, and other shippers was filed with FERC for its approval. FERC approved
the settlement on May 28, 2010. Pursuant to the settlement, we received an additional settlement
payment of $8.6 million. This settlement finally resolves the amount of additional payments SFPP
owes us for the period January 1992 through May 2006.
b. Other Settlements
We and other shippers also engaged in settlement discussions with SFPP relating to East Line
service in the FERC proceedings that address periods after May 2006. A partial settlement regarding
the East Lines Phase I expansion rates covering the period June 2006 through November 2007, which
became final in February 2008, resulted in a payment from SFPP to us of $1.3 million in April 2008.
On October 22, 2008, we and other shippers jointly filed at the FERC with SFPP a settlement
regarding the East Lines Phase II expansion rates covering the period from December 2007 through
November 2010. The FERC approved the settlement on January 29, 2009. The settlement reduced SFPPs
current rates and required SFPP to make additional payments to us of $2.9 million, which were
received on May 18, 2009.
c. The Latest Rate Proceeding
On June 2, 2009, SFPP notified us that it would terminate the October 22, 2008 settlement, as
provided under the settlement, effective August 31, 2009. On July 31, 2009, SFPP filed substantial
rate increases for East Line service to become effective September 1, 2009. We and several other
shippers filed protests at the FERC, challenging the rate increase and asking the FERC to suspend
the effectiveness of the increased rates. On August 31, 2009, the FERC issued an order suspending
the effective date of the rate increase until January 1,
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2010, on
which date the rate increase was placed into effect subject to refund, and setting the rate
increase for a full evidentiary hearing. The hearing was held from June 29, 2010 to August 2, 2010.
On September 15, 2010, the FERC approved an interim partial settlement pursuant to which SFPP
reduced its rates for the East Line service, effective September 1, 2010. The rates placed in
effect on January 1, 2010, and the lower rates put into effect on September 1, 2010, remain subject
to refund subject to the outcome of the evidentiary hearing. On February 10, 2011, the
Administrative Law Judge that presided over the evidentiary hearing issued an initial decision
holding that certain elements of SFPPs rate increases are unjust and unreasonable. The initial
decision is subject to review by the FERC and the courts. We are not in a position to predict the
ultimate outcome of the rate proceeding.
Cut Bank Hill Environmental Claims
Prior to the sale by Holly Corporation of the Montana Refining Company (MRC) assets in 2006, MRC,
along with other companies was the subject of several environmental claims at the Cut Bank Hill
site in Montana. These claims include: (1) a U.S. Environmental Protection Agency administrative
order requiring MRC and other companies to undertake cleanup actions; (2) a U.S. Coast Guard claim
against MRC and other companies for response costs of $0.3 million in connection with its cleanup
efforts at the Cut Bank Hill site; and (3) a unilateral order by the Montana Department of
Environmental Quality (MDEQ) directing MRC and other companies to complete a remedial
investigation and a request by the MDEQ that MRC and other companies pay $0.2 million to reimburse
the States costs for remedial actions. MRC has denied responsibility for the requested EPA and the
MDEQ cleanup actions and the MDEQ and Coast Guard response costs. MRC is considering an invitation
by the other companies to participate in the group based on an allocation of 9.16 percent of the
groups past and ongoing investigation and other costs.
Navajo Tank Fire
On March 2, 2010, a tank caught fire while under construction. At the time of the incident, four
individuals were working on top of the tank. These individuals were all employees of a third-party
contractor who was placing insulation on the tank. Two individuals sustained injuries and two
individuals died as a result of the incident. Two wrongful death lawsuits and two personal injury
lawsuits seeking damages, including punitive damages, were filed on behalf of the estates of the
two deceased workers and on behalf of the two survivors in state court in Dallas County, Texas (two
lawsuits) and state court in Eddy County, New Mexico (two lawsuits). The two Texas cases have been
consolidated and are set for trial in September of 2011. One of the cases in New Mexico is set for
trial in March of 2012. At the date of this report, it is not possible to predict the likely
outcome of this litigation. This matter is being reported due to the serious nature of the
injuries. Because of our insurance coverage, the total cost to the Company for these cases is not
expected to be material.
New Mexico OHSB Complaint Navajo Tank Fire
On March 3, 2010, the New Mexico Occupational Health and Safety Bureau (OHSB), the New Mexico
regulatory agency responsible for enforcing certain state occupational health and safety
regulations, which are identical to Federal Occupational Safety and Health Administration (OSHA)
regulations, commenced an inspection in relation to the tank fire that took place on March 2, 2010
at the Navajo facility in Artesia, New Mexico. On August 31, 2010, OHSB issued two citations to
Navajo Refining Company, LLC (Navajo), alleging 10 willful violations and 1 serious violation of
various construction safety standards. OHSB proposed penalties in the amount of $0.7 million.
Navajo filed a notice of contest, challenging the citations. An informal administrative review of
the citations took place on November 17, 2010, at which time counsel for the parties discussed
possible settlement options. The parties were unable to reach an agreement. Thus, OHSB filed an
administrative complaint with New Mexicos Occupational Health and Safety Review Commission
(OHSRC) on December 20, 2010. Navajo will challenge the citations before the OHSRC, and filed its
answer to the complaint on January 6, 2011. Discovery is under way at this time. OHSRC granted
the parties joint request that a hearing commence no sooner than September 5, 2011, but the
specific hearing date has not yet been established.
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OSHA Inspections Tulsa Refinery
In June 2007, OSHA announced a national emphasis program (NEP) for inspecting approximately 80
refineries within its jurisdiction. As part of the NEP, OSHA conducted an inspection of Sinclair
Tulsa Refining Companys (Sinclair Tulsa) refinery in Tulsa, Oklahoma (our Tulsa Refinery east
facility) from February 4, 2009 through August 3, 2009. On August 4, 2009, OSHA issued two
citations to Sinclair Tulsa, alleging 51 serious violations and 1 willful violation of various
safety standards including the Process Safety Management (PSM) standard and the General Duty
Clause. OSHA proposed penalties totaling $0.2 million. Sinclair filed a notice of contest,
challenging the citations.
Our subsidiary, Holly Refining & Marketing Tulsa LLC (HRM-Tulsa), entered into an Asset Sale &
Purchase Agreement (the Agreement) with Sinclair Tulsa dated October 19, 2009 to acquire the
Tulsa Refinery east facility, and the sale closed on December 1, 2009. HRM-Tulsa intervened in the
case against Sinclair Tulsa pending before the OHSRC shortly after the sale closed. Under the terms
of the Agreement, Sinclair retains responsibility for defending the OSHA citations and paying any
penalties, and HRM-Tulsa has the discretion to select the means and methods of improving the PSM
program. HRM-Tulsa has evaluated the feasibility of various PSM program improvements and developed
a plan to implement a number of safety enhancements at the Tulsa Refinery east facility. HRM-Tulsa
management presented its safety improvement plan to OSHA and OSHA approved the plan. HRM-Tulsa and
OSHA negotiated a settlement agreement which memorializes OSHAs approval of the safety improvement
plan. The settlement agreement between HRM-Tulsa and OSHA was filed with the OHSRC on August 11,
2010. On August 23, 2010, the OHSRC entered an order approving both the settlement agreement
between Sinclair Tulsa and OSHA and the agreement between HRM-Tulsa and OSHA.
OSHA conducted an inspection of our Tulsa Refinery west facility from January 20, 2010 through June
9, 2010. On July 12, 2010, OSHA issued a citation, alleging 10 serious violations of various safety
standards, including the PSM standard. OSHA proposed penalties totaling $57,150. HRM-Tulsa filed a
notice of contest, and challenged each citation item. The matter has been assigned to Judge Patrick
B. Augustine. Discovery is currently underway, and the hearing in this matter is scheduled to begin
July 25, 2011.
OSHA began the NEP inspection of our Tulsa Refinery west facility on September 14, 2010. On March
14, 2011, OSHA issued a citation alleging 15 serious violations of federal workplace standards.
OSHA proposed penalties totaling $62,500. On April 4, a settlement was reached that was favorable
to HRM-Tulsa and the penalty was reduced to $31,750.
On March 28, 2011, OSHA issued a serious citation to HRM-Tulsa with respect to the Tulsa west
facility, alleging one facility siting and two housekeeping violations, which stemmed from its
investigation of an employee complaint that it received during the NEP inspection. OSHA proposed
penalties of $6,275. HRM Tulsa is engaged in informal settlement negotiations with OSHA, but was
unable to reach a resolution and filed its notice of contest, challenging each citation item, on
April 18, 2011. It is too early to predict the likely outcome or cost, if any, of this matter.
Discharge Permit Appeal Tulsa Refinery West Facility
Our subsidiary, HRM-Tulsa is party to parallel Oklahoma administrative and state district court
proceedings involving a challenge to the terms of the Oklahoma Department of Environmental Quality
(ODEQ) permit that governs the discharge of industrial wastewater from our Tulsa Refinery west
facility. Pursuant to a settlement agreement between HRM-Tulsa and ODEQ, both proceedings have been
stayed to allow ODEQ to issue a revised permit that modifies the existing permits requirements for
toxicity testing and for managing storm flows. The parties are now in discussions regarding the
appropriate changes in the permit language to accomplish these modifications. Once agreed-upon
revisions are made and become effective, both proceedings will be dismissed. Any changes to
refinery processes that result from the permit revisions are subject to regulatory review and
approval. Accordingly, it is not possible to estimate the costs of compliance with the new permit
provisions at this time.
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Clean Air Act Notice of Violation Tulsa Refinery East and West Facilities
HRM Tulsa received a notification from the ODEQ that the agency intends to seek a fine of $192,500
for alleged violations of the Clean Air Act at the Tulsa Refinery West Facility. The ODEQs
primary area of concern is the number of valves that the facility has classed as Difficult to
Monitor. The agency maintains that no more than 3% of valves can be so designated. HRM Tulsa
interprets the applicable regulation as instead only imposing the 3% cap on new units. The parties
have agreed to ask for a formal regulatory interpretation from the Environmental Protection Agency
to assist them in resolving the dispute. HRM Tulsa believes that even if the ODEQs interpretation
is correct, the proposed fine is excessive. The company will seek to have the fine reduced. The
same notification also disclosed the agencys intent to seek a separate fine of $17,500 for alleged
Clean Air Act violations at the Tulsa Refinery East Facility. These alleged violations include a
failure to conduct monthly monitoring of components previously found to be leaking and the
discovery of three open ended lines, one of which was alleged to be leaking at the time of
discovery. HRM Tulsa is currently in discussions with ODEQ regarding the alleged violations at the
East Facility. It is not possible at this point to estimate what amount, if any, will ultimately
be assessed for any of the foregoing items.
Litigation Related to the Merger with Frontier Oil Corporation
Twelve substantially similar shareholder lawsuits styled as class actions have been filed by
alleged Frontier shareholders challenging our proposed merger of equals with Frontier and naming
as defendants Frontier, its board of directors and, in certain instances, us and our wholly owned
subsidiary, North Acquisition, Inc., as aiders and abettors. To date, such shareholder actions have
been filed in Harris County, Texas, Laramie County, Wyoming, the U.S. District Court for the
Northern District of Texas, and the U.S. District Court for the Southern District of Texas.
The lawsuits filed in the District Courts of Harris County, Texas are entitled: Adam Walker,
Individually and On Behalf of All Others Similarly Situated vs. Frontier Oil Corporation, et al.
(filed February 22, 2011), Andrew Goldberg, on Behalf of Himself and All Other Similarly Situated
Shareholders of Frontier Oil Corporation v. Frontier Oil Corporation, et al. (filed February 24,
2011), L.A. Murphy, On Behalf of Herself and All Others Similarly Situated v. Paul B. Loyd, Jr., et
al. (filed February 24, 2011), Zhixin Huang v. Frontier Oil Corp., et al. (filed February 24,
2011), Robert Pettigrew, individually and on behalf of all others similarly situated v. Frontier
Oil Corporation, et al. (filed February 25, 2011), Walter E. Ryan, Jr., On Behalf of Himself and
All Others Similarly Situated v. Frontier Oil Corporation, et al. (filed February 25, 2011),
Christopher Borrelli, Individually and on Behalf of All Others Similarly Situated v. Frontier Oil
Corporation, et al. (filed March 2, 2011), and Randy Whitman, Individually and on behalf of all
others similarly situated v. Frontier Oil Corporation, et al. (filed on March 8, 2011). The lawsuit
filed in the District Court of Laramie County, Wyoming is entitled Thomas Greulich, Individually
and on Behalf of All Others Similarly Situated v. Frontier Oil Corporation, et al. (filed March 1,
2011). The lawsuit filed in the U.S. District Court for the Northern District of Texas is entitled
Angelo Chiarelli, On Behalf of Himself and All Others Similarly Situated v. Holly Corporation, et
al. (filed on March 2, 2011). The lawsuits filed in the U.S. District Court for the Southern
District of Texas are entitled Tim Wilcox, Individually and on behalf of all others similarly
situated v. Frontier Oil Corporation, et al. (filed on March 7, 2011), and Jackie A. Rhymes,
individually and on behalf of others similarly situated v. Michael Jennings, et al. (filed on March
17, 2011).
These lawsuits generally allege that (1) the consideration to be received by Frontiers
shareholders in the merger is inadequate, (2) the Frontier directors breached their fiduciary
duties by, among other things, approving the merger at an inadequate price under circumstances
involving certain alleged conflicts of interest, (3) the merger agreement includes preclusive deal
protection provisions, and (4) Frontier, and in some cases we and North Acquisition, Inc., aided
and abetted Frontiers board of directors in breaching its fiduciary duties to Frontiers
shareholders. The shareholder actions seek various remedies, including enjoining the transaction
from being consummated in accordance with its agreed-upon terms, compensatory damages, and costs
and disbursements relating to the lawsuits.
In the cases pending in Texas state court, on March 21, 2011, plaintiff in the Walker lawsuit filed
an amended petition alleging that Frontiers current directors also breached their fiduciary duties
by failing to disclose
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material information or making materially inadequate disclosures concerning the proposed merger in
the registration statement on Form S-4. On March 25, 2011, the lawsuits pending in the District
Court of Harris County, Texas, were consolidated under the style In re: Frontier Oil Corp., Cause
No. 2011-11451, and interim class counsel was appointed on April 12, 2011.
With respect to the federal lawsuits, on March 24, 2011, plaintiffs in the lawsuits pending in the
United States District Court for the Southern District of Texas filed a motion to consolidate the
Wilcox and Rhymes cases pending in that district and to appoint interim lead counsel. On April 7,
2011, plaintiffs in the Wilcox and Rhymes cases filed substantially similar amended complaints. In
addition to the claims described in general above, these lawsuits also allege that the defendants
violated Sections 14(a) and 20(a) of the Exchange Act by making untrue statements of material fact
and omitting to state material facts necessary to make the statements that were made not misleading
in the registration statement on Form S-4.
The defendants intend to vigorously defend these and any future lawsuits, as they believe that they
have valid defenses to all claims and that the lawsuits are entirely without merit.
Unclaimed Property Audit
A multi-state audit of our unclaimed property compliance and reporting is being conducted by Kelmar
Associates, LLC on behalf of eleven states. We are currently in the third year of this ongoing
audit that covers the period 1981 2004. It is not yet possible to accurately estimate the
amount, if any, that is owed to each of the states.
Other
We are a party to various other litigation and proceedings that we believe, based on advice of
counsel, will not either individually or in the aggregate have a materially adverse impact on our
financial condition, results of operations or cash flows.
Item 6. Exhibits
The Exhibit Index on page 56 of this Quarterly Report on Form 10-Q lists the exhibits that are
filed or furnished, as applicable, as part of the Quarterly Report on Form 10-Q.
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SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has
duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
HOLLY CORPORATION (Registrant) |
||||
Date: May 6, 2011 | /s/ Bruce R. Shaw | |||
Bruce R. Shaw | ||||
Senior Vice President and Chief Financial Officer (Principal Financial Officer) |
||||
/s/ Scott C. Surplus | ||||
Scott C. Surplus | ||||
Vice President and Controller (Principal Accounting Officer) |
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Exhibit Index
Exhibit | ||
Number | Description | |
2.1
|
Agreement and Plan of Merger, dated as of February 21, 2011, among Holly Corporation, North Acquisition, Inc. and Frontier Oil Corporation (incorporated by reference to Exhibit 2.1 of the Registrants Current Report on Form 8-K filed February, 22, 2011, File No. 1-03876). | |
10.1
|
Assignment and Assumption Agreement (Amended and Restated Intermediate Pipelines Agreement), effective January 1, 2011, between Navajo Refining Company, L.L.C. and Holly Refining & Marketing Company LLC (incorporated by reference to Exhibit 10.5 of the Registrants Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876). | |
10.2
|
Assignment and Assumption Agreement (Tulsa Equipment and Throughput Agreement), effective January 1, 2011, between Holly Refining & Marketing Tulsa, LLC and Holly Refining & Marketing Company LLC (incorporated by reference to Exhibit 10.8 of the Registrants Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876). | |
10.3
|
Assignment and Assumption Agreement (Amended and Restated Refined Product Pipelines and Terminals Agreement), effective January 1, 2011, among Navajo Refining Company, L.L.C., Holly Refining & Marketing-Woods Cross and Holly Refining & Marketing Company LLC (incorporated by reference to Exhibit 10.12 of the Registrants Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876). | |
10.4
|
Assignment and Assumption Agreement (Pipeline Throughput Agreement (Roadrunner)), effective January 1, 2011, between Navajo Refining Company, L.L.C. and Holly Refining & Marketing Company LLC (incorporated by reference to Exhibit 10.14 of the Registrants Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876). | |
10.5
|
Assignment and Assumption Agreement (First Amended and Restated Pipelines, Tankage and Loading Rack Throughput Agreement (Tulsa East)), effective January 1, 2011, between Holly Refining & Marketing-Tulsa LLC and Holly Refining & Marketing Company LLC (incorporated by reference to Exhibit 10.17 of the Registrants Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876). | |
10.6
|
Second Amended and Restated Credit Agreement, dated as of February 14, 2011, among Holly Energy Partners Operating, L.P., Wells Fargo Bank, N.A., as administrative agent and an issuing bank, Union Bank, N.A., as syndication agent, BBVA Compass Bank and U.S. Bank N.A., as co-documentation agents, and certain other lenders (incorporated by reference to Exhibit 10.1 of Holly Energy Partners, L.P.s Current Report on Form 8-K filed February 18, 2011, File No. 1-32225). | |
10.7*
|
Holly Corporation Amended and Restated Change in Control Agreement Policy (incorporated by reference to Exhibit 10.1 of the Registrants Current Report on Form 8-K filed March 1, 2011, File No. 1-03876). | |
10.8*
|
Holly Corporation Form of Change in Control Agreement (incorporated by reference to Exhibit 10.2 of the Registrants Current Report on Form 8-K filed February 20, 2008, File No. 1-03876). |
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Exhibit | ||
Number | Description | |
10.9* +
|
Waiver Agreement, dated as of February 21, 2011, by and between Holly Corporation and Matthew P. Clifton | |
10.10* +
|
Waiver Agreement, dated as of February 21, 2011, by and between Holly Corporation and Bruce R. Shaw | |
31.1+
|
Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002. | |
31.2+
|
Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002. | |
32.1++
|
Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002. | |
32.2++
|
Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002. | |
101**
|
The following financial information from Holly Corporations Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, formatted in XBRL (Extensible Business Reporting Language): | |
(i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income, (iii) Consolidated Statements of Cash Flows, (iv) Consolidated Statements of Comprehensive Income, and (v) Notes to the Consolidated Financial Statements (tagged as blocks of text). |
+ | Filed herewith. | |
++ | Furnished herewith. | |
* | Constitutes management contracts or compensatory plans or arrangements | |
** | Furnished electronically herewith. |
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