UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
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| þ | | Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the fiscal year ended December 31, 20092010
OR
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| 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)
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Delaware
| | 75-1056913 |
(State or other jurisdiction of
| | (I.R.S Employer |
| incorporation or organization) | | 75-1056913
(I.R.S Employer
Identification No.) |
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100 Crescent Court, Suite 1600, Dallas, Texas
| | 75201-6915 |
| (Address of principle executive offices) | | 75201-6915
(Zip Code) |
Registrant’s telephone number, including area code(214) 871-3555
Securities registered pursuant to Section 12(b) of the Act:
Common Stock, $0.01 par value registered on the New York Stock Exchange.
Securities registered pursuant to 12(g) of the Act:
None.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.Yesþ Noo
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15 (d) of the Act.Yeso Noþ
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.Yesþ Noo
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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).Yesoþ Noo
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.oþ
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 definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act).Act. (Check one):
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| Large accelerated filerþ | | Accelerated filero | | AcceleratedNon-accelerated filero | | Non-accelerated filero | | Smaller reporting companyo |
| | (Do not check if a smaller reporting company)
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).Yeso Noþ
On June 30, 20092010 the aggregate market value of the Common Stock, par value $.01 per share, held by non-affiliates of the registrant was approximately $746$1,183 million. (This is not to be deemed an admission that any person whose shares were not included in the computation of the amount set forth in the preceding sentence necessarily is an “affiliate” of the registrant.)
53,103,33653,303,425 shares of Common Stock, par value $.01 per share, were outstanding on February 8, 2010.2011.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s proxy statement for its annual meeting of stockholders to be held on May 5, 2010,12, 2011, which proxy statement will be filed with the Securities and Exchange Commission within 120 days after December 31, 2009,2010, are incorporated by reference in Part III.
PART I
FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K 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-K, including, but not limited to, those under “Business and Properties” in Items 1 and 2, “Risk Factors” in Item 1A, “Legal Proceedings” in Item 3 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7, are forward-looking statements. These statements are based on management’s 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; and
other financial, operational and legal risks and uncertainties detailed from time to time in our Securities and Exchange Commission filings.
| • | | risks and uncertainties with respect to the actions of actual or potential competitive suppliers of refined petroleum products in our markets; |
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| • | | the demand for and supply of crude oil and refined products; |
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| • | | the spread between market prices for refined products and market prices for crude oil; |
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| • | | the possibility of constraints on the transportation of refined products; |
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| • | | the possibility of inefficiencies, curtailments or shutdowns in refinery operations or pipelines; |
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| • | | effects of governmental and environmental regulations and policies; |
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| • | | the availability and cost of our financing; |
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| • | | the effectiveness of our capital investments and marketing strategies; |
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| • | | our efficiency in carrying out construction projects; |
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| • | | our ability to acquire refined product operations or pipeline and terminal operations on acceptable terms and to integrate any existing or future acquired operations; |
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| • | | the possibility of terrorist attacks and the consequences of any such attacks; |
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| • | | general economic conditions; |
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| • | | 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 |
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| • | | 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-K, including without limitation the forward-looking statements that are referred to above. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in this Form 10-K under “Risk Factors” in Item 1A and in conjunction with the discussion in this Form 10-K in “Management’s 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-K 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.
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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 thea 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 the vaporturning 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.
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“LSG,” or low sulfur gasoline, means gasoline that contains less than 30 PPM of total sulfur.
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“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 applications 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 oiloils 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 of products per produced barrel of produced refined products.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 the vaporturning it back to a liquid in order to purify, fractionate or form the desired products.
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INDEX TO DEFINED TERMS AND NAMES
The following other terms and names that appear in this form 10-K are defined on the following pages:
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| | | Reference | |
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2005 ACT | | | 58 | |
ACESA | | | 31 | |
| Agreement | | | 4243 | |
| Alon | | | 13 | |
| Alon PTA | | | 23 | |
Amended NOV | | | 4124 | |
| Beeson Pipeline | | | 2223 | |
| CAA | | | 2526 | |
| CERCLA | | | 26 | |
| CWA | | | 26 | |
Centurion Pipeline | | | 22 | |
| Court of Appeals | | | 40 | |
Crude Pipelines and Tankage Assets | | | 841 | |
| EBITDA | | | 4748 | |
| EPA | | | 1415 | |
| Exchange Act | | | 115110 | |
| FERC | | | 23 | |
Fixed Rate SwapFrontier | | | 639 | |
| GAAP | | | 8 | |
| GHG | | | 31 | |
| Guarantor Restricted Subsidiaries | | | 106104 | |
| HEP | | | 8 | |
| HEP ATA | | | 23 | |
| HEP CPTA | | | 23 | |
| HEP ETA | | | 2223 | |
| HEP IPA | | | 2223 | |
| HEP NPA | | | 23 | |
| HEP PTA | | | 23 | |
| HEP PTTA | | | 2223 | |
| HEP RPA | | | 2223 | |
| HEP Amended Credit Agreement | | | 54 | |
| HEP Credit Agreement | | | 5354 | |
| HEP6.25% Senior Notes | | | 54 | |
| HEP8.25% Senior Notes | | | 54 | |
HEP Pipeline Operating AgreementSenior Notes | | | 2354 | |
HEPHolly 9.875% Senior Notes | | | 54 | |
| Holly Asphalt | | | 9 | |
| Holly Credit Agreement | | | 53 | |
| HPI | | | 5053 | |
| HRM-Tulsa | | | 4243 | |
| LIBOR | | | 62 | |
| LIFO | | | 3738 | |
| MDEQ | | | 4142 | |
| MRC | | | 4142 | |
| MSAT2 | | | 1415 | |
| Magellan | | | 1213 | |
| Merger | | | 9 | |
| NEP | | | 41 | |
NMED | | | 4142 | |
| NPDES | | | 26 | |
| Navajo Refinery | | | 9 | |
| Non-Guarantor Non-Restricted Subsidiaries | | | 106104 | |
| Non-Guarantor Restricted Subsidiaries | | | 106104 | |
| ODEQ | | | 43 | |
| OHSB | | | 42 | |
| OSHA | | | 4142 | |
| OSHRC | | | 42 | |
| Plains | | | 8 | |
| Plan | | | 103101 | |
| PPI | | | 23 | |
| PSM | | | 4243 | |
| Parent | | | 104 | |
| RCRA | | | 26 | |
| RINs | | | 33 | |
| Restricted Subsidiaries | | | 106104 | |
| Rio Grande | | | 2223 | |
| Roadrunner Pipeline | | | 2223 | |
| SEC | | | 8 | |
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| | Page |
| | Reference |
| SDWA | | | 26 | |
| SFPP | | | 12 | |
| SLC Pipeline | | | 9 | |
| Sinclair | | | 8 | |
| Sinclair Tulsa | | | 4243 | |
| Sunoco | | | 8 | |
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| | Reference | |
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| Tulsa Refinery | | | 8 | |
| Tulsa Refinery east facility | | | 8 | |
| Tulsa Refinery west facility | | | 8 | |
| UNEV Pipeline | | | 9 | |
UOSH | | | 41 | |
Variable Rate Swap | | | 62 | |
| VIE | | | 8 | |
| Woods Cross Refinery | | | 9 | |
| WRB | | | 1213 | |
Terms used in the financial statements and footnotes are as defined therein.
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Items 1 and 2. Business and Properties
COMPANY OVERVIEW
References herein to Holly Corporation include Holly Corporation and its consolidated subsidiaries. In accordance with the Securities and Exchange Commission’s (“SEC”) “Plain English” guidelines, this Annual Report on Form 10-K 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. For periods after our reconsolidation of Holly Energy Partners, L.P. (“HEP”) effective March 1, 2008, the words “we,” “our,” “ours” and “us” generally include HEP and its subsidiaries as consolidated subsidiaries of Holly Corporation with certain exceptions.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.
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. We were incorporated in Delaware in 1947 and maintain our principal corporate offices at 100 Crescent Court, Suite 1600, Dallas, Texas 75201-6915. Our telephone number is 214-871-3555 and our internet website address is www.hollycorp.com.www.hollycorp.com. The information contained on our website does not constitute part of this Annual Report on Form 10-K. A print copy of this Annual Report on Form 10-K will be provided without charge upon written request to the Vice President, Investor Relations at the above address. A direct link to our filings at the SEC website is available on our website on the Investors page. Also available on our website are copies of our Corporate Governance Guidelines, Audit Committee Charter, Compensation Committee Charter, Nominating / Corporate Governance Committee Charter and Code of Business Conduct and Ethics, all of which will be provided without charge upon written request to the Vice President, Investor Relations at the above address. Our Code of Business Conduct and Ethics applies to all of our officers, employees and directors, including our principal executive officer, principal financial officer and principal accounting officer. Our common stock is traded on the New York Stock Exchange under the trading symbol “HOC.”
On June 1, 2009, we acquired an 85,000 BPSD refinery located in Tulsa, Oklahoma (the “Tulsa Refinery west facility”) from an affiliate of Sunoco, Inc. (“Sunoco”) for $157.8 million in cash, including crude oil, refined product and other inventories valued at $92.8 million. The refinery produces fuel products including gasoline, diesel fuel and jet fuel and serves markets in the Mid-Continent region of the United States and also produces specialty lubricant products that are marketed throughout North America and are distributed in Central and South America. On October 20, 2009, we sold to an affiliate of Plains All American Pipeline, L.P. (“Plains”) a portion of the crude oil petroleum storage tanks and certain refining-related crude oil receiving pipeline facilities, that were acquired as part of the refinery assets for $40 million.
On December 1, 2009, we acquired a 75,000 BPSD refinery from an affiliate of Sinclair Oil Company (“Sinclair”) also located in Tulsa, Oklahoma (the “Tulsa Refinery east facility”) for $183.3 million, including crude oil, refined product and other inventories valued at $46.4 million. The total purchase price consisted of $109.3 million in cash and 2,789,155 shares of our common stock having a value of $74 million. Additionally, we will reimbursereimbursed Sinclair approximately $8$8.4 million upon their satisfactory completion of certain environmental projects at the refinery.refinery in July 2010. The refinery also produces gasoline, diesel fuel and jet fuel products and also serves markets in the Mid-Continent region of the United States. We are in the process of integrating the operations of both Tulsa Refinery facilities (collectively, the “Tulsa Refinery”). Upon completion,This will result in the Tulsa Refinery will havehaving an integrated crude processing rate of 125,000 BPSD.
On February 29, 2008, we sold certain crude pipelines and tankage assets (the “Crude Pipelines and Tankage Assets”) to HEP for $180 million. The assets consisted of crude oil trunk lines that deliver crude oil to our refinery in southeast New Mexico, gathering and connection pipelines located in west Texas and New Mexico, on-site crude tankage located within both of our refinerythe Woods Cross and Navajo Refinery complexes, a jet fuel products pipeline and leased terminal between Artesia and Roswell, New Mexico and crude oil and product pipelines that support our refinery in Woods Cross, Utah. HEP is a variable interest entity (“VIE”) as defined under U.S. generally accepted accounting principles (“GAAP”). Under GAAP, HEP’s purchaseacquisition of the Crude Pipelines and Tankage Assetsthese assets qualified as a reconsideration event whereby we reassessed our beneficial interest in HEP. Following this transaction, we
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determined that our beneficial interest in HEP exceeded 50%. Accordingly, Therefore,
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we reconsolidated HEP effective March 1, 2008. Therefore, intercompanyIntercompany transactions with HEP are eliminated in our consolidated financial statements.
HEP hadmade a number of acquisitions in 2010 and 2009. Information on these acquisitions can be found under the “Holly Energy Partners, L.P.��” section provided later in this discussion of Items 1 and 2, “Business and Properties.”
As of December 31, 2009,2010, 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 the Tulsa Refinery;
owned and operated Holly Asphalt Company (formerly, NK Asphalt Partners) 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 (which includes our 2% general partnership interest), which owns and operates logistics assets including approximately 2,500 miles of petroleum product and crude oil pipelines located principally in west Texas and New Mexico; ten refined product terminals; a jet fuel terminal; four refinery loading rack facilities; a refined products tank farm facility; on-site crude oil tankage at our Navajo, Woods Cross and Tulsa Refineries, on-site refined product tankage at our Tulsa Refinery and a 25% interest in a 95-mile, crude oil pipeline joint venture (the “SLC Pipeline”).
| • | | 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 the Tulsa Refinery; |
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| • | | owned and operated Holly Asphalt Company (“Holly Asphalt”) which manufactures and markets asphalt products from various terminals in Arizona, New Mexico and Texas; |
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| • | | 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 |
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| • | | owned a 34% interest in HEP (which includes our 2% general partnership interest), which owns and operates logistics assets including approximately 2,500 miles of petroleum product and crude oil pipelines located principally in west Texas and New Mexico; ten refined product terminals; a jet fuel terminal; eight refinery loading rack facilities; a refined products tank farm facility; on-site crude oil tankage at our Navajo, Woods Cross and Tulsa Refineries, on-site refined product tankage at our Tulsa Refinery and a 25% interest in a 95-mile, crude oil pipeline joint venture (the “SLC Pipeline”). |
Navajo Refining Company, L.L.C., one of our wholly-owned subsidiaries, owns the Navajo Refinery. The Navajo Refinery has a crude capacity of 100,000 BPSD, can process up to 100% sour crude oil and serves markets in the southwestern United States and northern Mexico. Our Woods Cross Refinery, located just north of Salt Lake City, Utah has a crude capacity of 31,000 BPSD and is operated by Holly Refining & Marketing Company — Woods Cross, one of our wholly-owned subsidiaries. The Woods Cross Refinery is a high conversion refinery that processes regional sweet and Canadian sour crude oils and serves markets in Utah, Idaho, Nevada, Wyoming, Wyoming and eastern Washington. Our Tulsa Refinery located in Tulsa, Oklahoma has a crude capacity of 125,000 BPSD and is owned and operated by Holly Refining & Marketing Company — Tulsa LLC, one of our wholly-owned subsidiaries. The Tulsa Refinery primarily processes sweet crude oils, however, has the capability to process sour crude oils when economics dictate, and serves the Mid-Continent region of the United States.
Our operations are currently organized into two reportable segments, Refining and HEP. The Refining segment includes the operations of our Navajo, Woods Cross and Tulsa Refineries and Holly Asphalt Company (“Holly Asphalt”).Asphalt. Information regarding Holly Asphalt can be found under our discussion of the Navajo Refinery provided under the “Refinery Operations” section provided below. The HEP segment involves all of the operations of HEP effective March 1, 2008 (date of reconsolidation).
Recent Developments
On February 21, 2011, we entered into a merger agreement providing for a “merger of equals” business combination of us and Frontier Oil Corporation (the “Merger”). Frontier Oil Corporation (“Frontier”) operates a 135,000 bpd refinery located in El Dorado, Kansas, and a 52,000 bpd refinery located in Cheyenne, Wyoming, and markets its refined products principally along the eastern slope of the Rocky Mountains and in other neighboring plains states.
Subject to the terms and conditions of the merger agreement which has been approved unanimously by both our and Frontier’s board of directors, Frontier shareholders will receive 0.4811 shares of Holly 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 Frontier’s stockholders in connection with the Merger, (ii) adoption of the merger agreement by Frontier’s 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.
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The foregoing description of the merger agreement is not a complete description of all the parties’ rights and obligations under the merger agreement and is qualified in its entirety by reference to the merger agreement, which is filed as Exhibit 2.1 to our Current Report on Form 8-K as filed with the SEC on February 22, 2011.
REFINERY OPERATIONS
Our refinery operations include the operations of our three refineries. The following table sets forth information, including performance measures about our refinery operations that are not calculations based upon GAAP. 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 7A of Part II of this Form 10-K.
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| | | Years Ended December 31, | | | Years Ended December 31, | |
| | | 2009 | | 2008 | | 2007 | | | 2010 | | 2009 | | 2008 | |
Consolidated | | |
Crude charge (BPD)(1) | | 142,430 | | 100,680 | | 103,490 | | | 221,440 | | 142,430 | | 100,680 | |
Refinery production (BPD)(2) | | 151,420 | | 110,850 | | 113,270 | | |
Refinery throughput (BPD)(2) | | | 234,910 | | 154,940 | | 114,130 | |
Refinery production (BPD)(3) | | | 225,980 | | 151,420 | | 110,850 | |
| Sales of produced refined products (BPD) | | 151,580 | | 111,950 | | 115,050 | | | 228,140 | | 151,580 | | 111,950 | |
Sales of refined products (BPD)(3) | | 155,820 | | 120,750 | | 126,800 | | |
Sales of refined products (BPD)(4) | | | 232,100 | | 155,820 | | 120,750 | |
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Refinery utilization(4) | | | 78.9 | % | | | 89.7 | % | | | 94.1 | % | |
Refinery utilization(5) | | | | 86.5 | % | | | 78.9 | % | | | 89.7 | % |
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Average per produced barrel(6) | | |
| Net sales | | | $ | 91.06 | | $ | 74.06 | | $ | 108.83 | |
Cost of products(7) | | | 82.27 | | 66.85 | | 97.87 | |
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| Refinery gross margin | | | 8.79 | | 7.21 | | 10.96 | |
Refinery operating expenses(8) | | | 5.08 | | 5.24 | | 5.14 | |
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| Net operating margin | | | $ | 3.71 | | $ | 1.97 | | $ | 5.82 | |
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| Refinery operating expenses per throughput barrel | | | $ | 4.94 | | $ | 5.12 | | $ | 5.05 | |
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| Feedstocks: | | |
| Sour crude oil | | | | 35 | % | | | 49 | % | | | 63 | % |
| Sweet crude oil | | | | 53 | % | | | 40 | % | | | 23 | % |
| Black wax crude oil | | | | 3 | % | | | 5 | % | | | 4 | % |
| Heavy sour crude oil | | | | 4 | % | | | — | % | | | — | % |
| Other feedstocks and blends | | | | 5 | % | | | 6 | % | | | 10 | % |
| | | | | | | | | |
| Total | | | | 100 | % | | | 100 | % | | | 100 | % |
| | | | | | | | | |
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| | | | | | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2009 | | | 2008 | | | 2007 | |
Average per produced barrel(5) | | | | | | | | | | | | |
| Net sales | | $ | 74.06 | | | $ | 108.83 | | | $ | 89.77 | |
Cost of products(6) | | | 66.85 | | | | 97.87 | | | | 73.03 | |
| | | | | | | | | | |
| Refinery gross margin | | | 7.21 | | | | 10.96 | | | | 16.74 | |
Refinery operating expenses(7) | | | 5.24 | | | | 5.14 | | | | 4.43 | |
| | | | | | | | | | |
| Net operating margin | | $ | 1.97 | | | $ | 5.82 | | | $ | 12.31 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Feedstocks: | | | | | | | | | | | | |
| Sour crude oil | | | 49 | % | | | 63 | % | | | 62 | % |
| Sweet crude oil | | | 40 | % | | | 23 | % | | | 23 | % |
| Black wax crude oil | | | 5 | % | | | 4 | % | | | 3 | % |
| Other feedstocks and blends | | | 6 | % | | | 10 | % | | | 12 | % |
| | | | | | | | | | |
| Total | | | 100 | % | | | 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. |
| |
(3)(4) | | Includes refined products purchased for resale. |
| |
(4)(5) | | Represents crude charge divided by total crude capacity (BPSD). Our consolidated crude capacity was increased from 109,000 BPSD to 111,000 BPSD in mid-year 2007 (our 2007 Navajo Refinery expansion) and by an additional 5,000 BPSD in the fourth quarter of 2008 (our 2008 Woods Cross Refinery expansion). During 2009, we increased our consolidated crude capacity by 15,000 BPSD in the first quarter ofeffective April 1, 2009 (our 2009 Navajo Refinery expansion), by 85,000 BPSD in second quarter ofeffective June 1, 2009 (our June 2009 Tulsa Refinery west facility acquisition) and by 40,000 BPSD in the fourth quarter ofeffective December 1, 2009 (our December 2009 Tulsa Refinery east facility acquisition), increasing our consolidated crude capacity to 256,000 BPSD. |
| |
(5)(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 7A of Part II of this Form 10-K. |
| |
(6)(7) | | Transportation, terminal and refinery storage costs billed from HEP are included in cost of products. |
| |
(7)(8) | | Represents operating expenses of our refineries, exclusive of depreciation and amortization. |
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Set forth below is information regarding our principal products.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | Years Ended December 31, |
| | | 2009 | | 2008 | | 2007 | | | 2010 | | 2009 | | 2008 |
Consolidated | | |
| Sales of produced refined products: | | |
| Gasolines | | | 51 | % | | | 58 | % | | | 60 | % | | | 49 | % | | | 51 | % | | | 58 | % |
| Diesel fuels | | | 31 | % | | | 32 | % | | | 29 | % | | | 31 | % | | | 31 | % | | | 32 | % |
| Jet fuels | | | 4 | % | | | 1 | % | | | 2 | % | | | 5 | % | | | 4 | % | | | 1 | % |
| Fuel oil | | | 2 | % | | | 3 | % | | | 4 | % | | | 2 | % | | | 2 | % | | | 3 | % |
| Asphalt | | | 2 | % | | | 3 | % | | | 2 | % | | | 3 | % | | | 2 | % | | | 3 | % |
| Lubricants | | | 4 | % | | | — | % | | | — | % | | | 5 | % | | | 4 | % | | | — | % |
| Gas oil / intermediates | | | 4 | % | | | — | % | | | — | % | | | 2 | % | | | 4 | % | | | — | % |
| LPG and other | | | 2 | % | | | 3 | % | | | 3 | % | | | 3 | % | | | 2 | % | | | 3 | % |
| | | | | | | | | | | | | | | |
| Total | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % |
| | | | | | | | | | | | | | | |
We have several significant customers, noneone of which accounted for more than 10% of our business in 2009. However, in conjunction2010. For the year ended December 31, 2010, Sinclair accounted for $1,616 million or 19% of our revenues. In connection with our refinery acquisition from Sinclair in 2009, we have entered into a refined products purchase agreement, or offtake agreement, with an affiliate of Sinclair. Information on this offtake agreement can be found under our discussion of the Tulsa Refinery provided later in this section of “Refinery Operations.” Our principal customers for gasoline include other refiners, convenience store chains, independent marketers, and retailers. Diesel fuel is sold to other refiners, truck stop chains, wholesalers and railroads. Jet fuel is sold for military and commercial airline use. Specialty lubricant products are sold in both commercial and specialty markets. Asphalt is sold to governmental entities or contractors. LPG’s are sold to LPG wholesalers and LPG retailers and carbon black oil is sold for further processing or blended into fuel oil.
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Navajo Refinery
Facilities
The Navajo Refinery has a crude oil capacity of 100,000 BPSD and has the ability to process sour crude oils into high value light products such as gasoline, diesel fuel and jet fuel. The Navajo Refinery converts approximately 92% of its raw materials throughput into high value light products. For 2009,2010, gasoline, diesel fuel and jet fuel (excluding volumes purchased for resale) represented 58%57%, 32% and 2%3%, respectively, of the Navajo Refinery’s sales volumes.
The following table sets forth information about the Navajo Refinery operations, including non-GAAP performance measures. 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 7A of Part II of this Form 10-K.
| | | | | | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2009 | | | 2008 | | | 2007 | |
Navajo Refinery | | | | | | | | | | | | |
Crude charge (BPD)(1) | | | 78,160 | | | | 79,020 | | | | 79,460 | |
Refinery production (BPD)(2) | | | 86,760 | | | | 88,680 | | | | 87,930 | |
| Sales of produced refined products (BPD) | | | 87,140 | | | | 89,580 | | | | 88,920 | |
Sales of refined products (BPD)(3) | | | 90,870 | | | | 97,320 | | | | 100,460 | |
| | | | | | | | | | | | | |
Refinery utilization(4) | | | 81.2 | % | | | 93.0 | % | | | 94.6 | % |
| | | | | | | | | | | | | |
Average per produced barrel(5) | | | | | | | | | | | | |
| Net sales | | $ | 73.15 | | | $ | 108.52 | | | $ | 89.68 | |
Cost of products(6) | | | 65.95 | | | | 98.97 | | | | 74.10 | |
| | | | | | | | | | |
| Refinery gross margin | | | 7.20 | | | | 9.55 | | | | 15.58 | |
Refinery operating expenses(7) | | | 4.81 | | | | 4.58 | | | | 4.30 | |
| | | | | | | | | | |
| Net operating margin | | $ | 2.39 | | | $ | 4.97 | | | $ | 11.28 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Feedstocks: | | | | | | | | | | | | |
| Sour crude oil | | | 85 | % | | | 79 | % | | | 82 | % |
| Sweet crude oil | | | 6 | % | | | 10 | % | | | 9 | % |
| Other feedstocks and blends | | | 9 | % | | | 11 | % | | | 9 | % |
| | | | | | | | | | |
| Total | | | 100 | % | | | 100 | % | | | 100 | % |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
Navajo Refinery | | | | | | | | | | | | |
Crude charge (BPD)(1) | | | 83,900 | | | | 78,160 | | | | 79,020 | |
Refinery throughput (BPD)(2) | | | 94,270 | | | | 88,900 | | | | 90,790 | |
Refinery production (BPD)(3) | | | 92,050 | | | | 86,760 | | | | 88,680 | |
| Sales of produced refined products (BPD) | | | 92,550 | | | | 87,140 | | | | 89,580 | |
Sales of refined products (BPD)(4) | | | 95,790 | | | | 90,870 | | | | 97,320 | |
| | | | | | | | | | | | | |
Refinery utilization(5) | | | 83.9 | % | | | 81.2 | % | | | 93.0 | % |
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| | | | | | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
Average per produced barrel(6) | | | | | | | | | | | | |
| Net sales | | $ | 90.37 | | | $ | 73.15 | | | $ | 108.52 | |
Cost of products(7) | | | 83.12 | | | | 65.95 | | | | 98.97 | |
| | | | | | | | | | |
| Refinery gross margin | | | 7.25 | | | | 7.20 | | | | 9.55 | |
Refinery operating expenses(8) | | | 4.95 | | | | 4.81 | | | | 4.58 | |
| | | | | | | | | | |
| Net operating margin | | $ | 2.30 | | | $ | 2.39 | | | $ | 4.97 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Refinery operating expenses per throughput barrel | | $ | 4.86 | | | $ | 4.71 | | | $ | 4.52 | |
| | | | | | | | | | | | | |
| Feedstocks: | | | | | | | | | | | | |
| Sour crude oil | | | 81 | % | | | 85 | % | | | 79 | % |
| Sweet crude oil | | | 5 | % | | | 6 | % | | | 10 | % |
| Heavy sour crude oil | | | 4 | % | | | — | % | | | — | % |
| Other feedstocks and blends | | | 10 | % | | | 9 | % | | | 11 | % |
| | | | | | | | | | |
| Total | | | 100 | % | | | 100 | % | | | 100 | % |
| | | | | | | | | | |
| | |
| (1) | | Crude charge represents the barrels per day of crude oil processed at our refinery. |
| |
| (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 refinery. |
|
| (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 refinery. |
| |
(3)(4) | | Includes refined products purchased for resale. |
| |
(4)(5) | | Represents crude charge divided by total crude capacity (BPSD). The crude capacity was increased from 83,000 BPSD to 85,000 BPSD in mid-year 2007 (our 2007 Navajo Refinery expansion) and by an additional 15,000 BPSD in the first quarter of 2009 (our 2009 Navajo Refinery expansion), increasing crude capacity to 100,000 BPSD. |
| |
(5)(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 7A of Part II of this Form 10-K. |
| |
(6)(7) | | Transportation costs billed from HEP are included in cost of products. |
| |
(7)(8) | | Represents operating expenses of our refinery, exclusive of depreciation and amortization. |
The Navajo Refinery’s Artesia, New Mexico facility is located on a 561-acre site and is a fully integrated refinery with crude distillation, vacuum distillation, FCC, ROSE (solvent deasphalter), HF alkylation, catalytic reforming, hydrodesulfurization, mild hydrocracking, isomerization, sulfur recovery and product blending units. Other supporting infrastructure includes approximately 2 million barrels of feedstock and product tankage at the site of which 0.2 million barrels of tankage are owned by HEP, maintenance shops, warehouses and office buildings. The operating units at the Artesia facility include newly constructed units, older units that have been relocated from other facilities and upgraded and re-erected in Artesia, and units that have been operating as part of the Artesia facility (with periodic major maintenance) for many years, in some very limited cases since before 1970. The Artesia facility is operated in conjunction with a refining facility located in Lovington, New Mexico, approximately 65 miles east of Artesia. The principal equipment at the Lovington facility consists of a crude distillation unit and associated vacuum distillation units that were constructed after 1970. The facility also has an additional 1.1 million barrels of feedstock and product tankage of which 0.2 million barrels of tankage are owned by HEP. The Lovington facility processes crude oil into intermediate products that are transported to Artesia by means of three intermediate pipelines owned by HEP. These products are then upgraded into finished products at the Artesia facility. The combined crude oil capacity of the Navajo Refinery facilities is 100,000 BPSD and it typically processes or blends an additional 10,000 BPSD of natural gasoline, butane, gas oil and naphtha. The Navajo Refinery completed a major maintenance turnaround in February 2009.2010.
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We distribute refined products from the Navajo Refinery to markets in Arizona, New Mexico, west Texas and northern Mexico primarily through two of HEP’s pipelines that extend from Artesia, New Mexico to El Paso, Texas and from El Paso to Albuquerque and to Mexico via products pipeline systems owned by Plains and from El Paso to Tucson and Phoenix via a products pipeline system owned by Kinder Morgan’s subsidiary, SFPP, L.P. (“SFPP”). In addition, we use pipelines owned and leased by HEP to transport petroleum products to markets in central and northwest New Mexico. We have refined product storage through our pipelines and terminals agreement with HEP at terminals in El Paso, Texas; Tucson, Arizona; and Artesia, Moriarty and Bloomfield, New Mexico.
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Holly Asphalt Company
We manufacture and market commodity and modified asphalt products in Arizona, New Mexico, Texas and northern Mexico under Holly Asphalt. We have four manufacturing facilities located in Glendale, Arizona, Albuquerque, New Mexico, Artesia, New Mexico and Lubbock, Texas. Our Albuquerque, Artesia and Lubbock facilities manufacture modified hot asphalt products and commodity emulsions from base asphalt materials provided by our Navajo Refinery and third-party suppliers. Our Lubbock facility is leased under a lease agreement expiring in 2011. Our Glendale facility manufactures modified hot asphalt products from base asphalt materials provided by our Navajo and Woods Cross Refineries and third-party suppliers. Our products are shipped via third-party trucking companies to commercial customers that provide asphalt based materials for commercial and government projects.
Markets and Competition
The Navajo Refinery primarily serves the southwestern United States market, which has historically experienced a high growth rate, including El Paso, Texas; Albuquerque, Moriarty and Bloomfield, New Mexico; Phoenix and Tucson, Arizona; and the northern Mexico market. Our products are shipped through HEP’s pipelines from Artesia, New Mexico to El Paso, Texas and from El Paso to Albuquerque and to Mexico via products pipeline systems owned by Plains and from El Paso to Tucson and Phoenix via a products pipeline system owned by SFPP. In addition, the Navajo Refinery transports petroleum products to markets in northwest New Mexico and to Moriarty, New Mexico, near Albuquerque, via HEP’s pipelines running from Artesia to San Juan County, New Mexico.
El Paso Market
The El Paso market for refined products is currently supplied by a number of area and gulf coast refiners and pipelines. Area refiners include Navajo, WRB Refining, LLC (“WRB”) (a joint venture between ConocoPhillips and EnCana Corp.), Valero, Alon USA, Inc. (“Alon”), and Western Refining. Pipelines serving this market are owned by Magellan Midstream Partners, L.P. (“Magellan”), NuStar Energy L.P. and HEP. Refined products from the Gulf Coast are transported via Magellan pipelines, including Magellan’s Longhorn Pipeline acquired in 2009. We supply approximately 17% — 20% of the refined products consumed in the El Paso market.
Arizona Market
The Arizona market for refined products is currently supplied by a number of refiners via pipelines and trucks. Refiners include companies located in west Texas, eastern New Mexico, northern New Mexico, the Gulf Coast and the West Coast. We supply approximately 17% — 20% of the refined products consumed in the Arizona market, comprised primarily of Phoenix and Tucson, via the SFPP Pipeline.
New Mexico Markets
The Artesia, Albuquerque, Moriarty and Bloomfield markets are supplied by a number of refiners via pipelines and trucks. Refiners include Navajo, Valero, Western Refining, Alon and WRB. We supply approximately 18% — 20% of the refined products consumed in the New Mexico market.
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TheWe use a common carrier pipeline we useout of El Paso to serve the Albuquerque market out of El Paso currently operates at near capacity.market. In addition, HEP leases from Mid-America Pipeline Company, L.L.C., a pipeline between White Lakes, New Mexico and the Albuquerque vicinity and Bloomfield, New Mexico. The lease agreement currently runs through 2017, and HEP has options to renew for two ten-year periods. HEP owns and operates a 12-inch pipeline from the Navajo Refinery to the leased pipeline as well as terminalling facilities in Bloomfield, New Mexico, which is located in the northwest corner of New Mexico, and in Moriarty, which is 40 miles east of Albuquerque. These facilities permit us to ship light products to the Albuquerque and Santa Fe, New Mexico areas, which have historically experienced high growth rates. If needed, additional pump stations could further increase the pipeline’s capabilities.
Magellan’s Longhorn Pipeline is a 72,000 BPD common carrier pipeline that has the ability to deliverdelivers refined products utilizing a direct route from the Texas Gulf Coast to El Paso and, through interconnections with third-party common carrier pipelines, into the Arizona market.
An additional factor that could affect some of our markets is the presence of pipeline capacity from El Paso and the West Coast into our Arizona markets. Additional increases in shipments of refined products from El Paso and the West Coast into our Arizona markets could result in additional downward pressure on refined product prices in these markets.
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Crude Oil and Feedstock Supplies
The Navajo Refinery is situated near the Permian Basin in an area that historically has had abundant supplies of crude oil available both for regional users, such as us, and for export to other areas. We purchase crude oil from producers in nearby southeastern New Mexico and west Texas and from major oil companies. Additionally, crude oil is gathered through HEP’s pipelines, our tank trucks and through third-party crude oil pipeline systems. Crude oil acquired in locations distant from the refinery is exchanged for crude oil that is transportable to the refinery.
Additionally, the Navajo Refinery has access to a wide variety of crude oils available at Cushing, Oklahoma via HEP’s Roadrunner Pipeline that connects to Centurion Pipeline L.P.’s pipeline running from west Texas to Cushing Oklahoma. Cushing Oklahoma is a significant crude oil pipeline crossroad and storage hub that has access to regional crude production as well as many United States onshore, Gulf of Mexico, Canadian and other foreign crudes.
We also purchase volumes of isobutane, natural gasoline and other feedstocks to supply the Navajo Refinery from sources in southeastern New Mexico and the Mid-Continent area that are delivered to our region on a common carrier pipeline owned by Enterprise Products, L.P. Ultimately all volumes of these products are shipped to the Artesia refining facilities on HEP’s intermediate pipelines running from Lovington to Artesia. From time to time, we also purchase gas oil, naphtha and light cycle oil from other oil companies for use as feedstock.
Principal Products and Customers
Set forth below is information regarding the principal products produced at our Navajo Refinery:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | Years Ended December 31, |
| | | 2009 | | 2008 | | 2007 | | | 2010 | | 2009 | | 2008 |
Navajo Refinery | | |
| Sales of produced refined products: | | |
| Gasolines | | | 58 | % | | | 57 | % | | | 59 | % | | | 57 | % | | | 58 | % | | | 57 | % |
| Diesel fuels | | | 32 | % | | | 33 | % | | | 30 | % | | | 32 | % | | | 32 | % | | | 33 | % |
| Jet fuels | | | 2 | % | | | 1 | % | | | 3 | % | | | 3 | % | | | 2 | % | | | 1 | % |
| Fuel oil | | | 3 | % | | | 3 | % | | | 3 | % | | | 4 | % | | | 3 | % | | | 3 | % |
| Asphalt | | | 3 | % | | | 3 | % | | | 2 | % | | | 2 | % | | | 3 | % | | | 3 | % |
| LPG and other | | | 2 | % | | | 3 | % | | | 3 | % | | | 2 | % | | | 2 | % | | | 3 | % |
| | | | | | | | | | | | | | | |
| Total | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % |
| | | | | | | | | | | | | | | |
Light products are shipped by product pipelines or are made available at various points by exchanges with others. Light products are also made available to customers through truck loading facilities at the refinery and at terminals.
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Our principal customers for gasoline include other refiners, convenience store chains, independent marketers, and retailers. Our gasoline produced at the Navajo Refinery is marketed in the southwestern United States, including the metropolitan areas of El Paso, Phoenix, Albuquerque, Bloomfield, and Tucson, and in portions of northern Mexico. The composition of gasoline differs, because of local regulatory requirements, depending on the area in which gasoline is to be sold. Diesel fuel is sold to other refiners, truck stop chains, wholesalers, and railroads. Jet fuel is sold for military and commercial airline use. All asphalt produced and purchased from third-parties is blended to fuel oil and is either sold locally, or is shipped by rail to the Gulf Coast, shipped by rail directly to our customers or marketed through Holly Asphalt to governmental entities, contractors or manufacturers. LPG’s are sold to LPG wholesalers and LPG retailers and carbon black oil is sold for further processing.
Crude Oil and Feedstock Supplies
The Navajo Refinery is situated near the Permian Basin, an area that has historically and continues to have abundant supplies of crude oil available both for regional users and for export to other areas. We purchase crude oil from independent producers in southeastern New Mexico and west Texas as well as from major oil companies. The crude oil is gathered through HEP’s pipelines, our tank trucks and through third-party crude oil pipeline systems for delivery to the Navajo Refinery.
The Navajo Refinery also has access to a wide variety of crude oils available at Cushing, Oklahoma via HEP’s Roadrunner Pipeline that connects to Centurion Pipeline L.P.’s pipeline running from west Texas to Cushing Oklahoma. In 2010, the Navajo Refinery began processing heavy sour crude oil transported from Cushing through these pipelines. Cushing Oklahoma is a significant crude oil pipeline trading and storage hub that has access to regional crude production as well as United States onshore, Gulf of Mexico, Canadian and other foreign crudes.
We also purchase volumes of isobutane, natural gasoline and other feedstocks to supply the Navajo Refinery from sources in southeastern New Mexico and the Mid-Continent area that are delivered to our region on a common carrier pipeline owned by Enterprise Products, L.P. Ultimately all volumes of these products are shipped to the Artesia refining facilities on HEP’s intermediate pipelines running from Lovington to Artesia. From time to time, we purchase gas oil, naphtha and light cycle oil from other oil companies for use as feedstock.
Capital Improvement Projects
Our total approved capital budget for the Navajo Refinery for 20102011 is $16.7$23.9 million. Additionally, capital costs of $11.5$2 million have been approved for refinery turnarounds and tank work. We expect to spend approximately $58.5$24 million in capital costs in 2010,2011, including capital projects approved in prior years. The following summarizes our key capital projects.
We completed Phase III of our Navajo Refinery major capital projects was mechanically completed in March 2009 increasing refinery capacity to 100,000 BPSD effective April 1, 2009. Phase I required the installation of a new 15,000 BPSD mild hydrocracker, 28 MMSCFSD hydrogen plant and the expansion of our Lovington crude and vacuum units at a cost of approximately $190 million.
We are nearing completion of phase II of the major capital projectsinitiative at the Navajo Refinery. These improvements will provideRefinery in the second quarter of 2010, providing the refinery with the capability to process up to 40,000 BPSD of heavy type crudes. Phase II involvesinvolved the installation of a new 18,000 BPSD solvent deasphalter and the revamp of our Artesia crude and vacuum units. The solvent deasphalter unit was complete in the fourth quarterWe completed Phase I of 2009 and is in operation. The crude / vacuum unit revamp is expected to be to be completedthis initiative in the first quarter of 2010. We expect2009, which increased refining capacity to 100,000 BPSD. Phase I
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included the phase II project to cost approximately $100 million.
We are also proceeding withinstallation of a project to add asphalt tankage atnew mild hydrocracker, hydrogen plant and the Navajo Refinery and at the Holly Asphalt facility in Artesia, New Mexico to enhance asphalt economics by storing asphalt during the winter months when asphalt prices are generally lower. These asphalt tank additions and an approved upgradeexpansion of our rail loading facilities at the Artesia refinery are estimated to cost $21 millionLovington crude and are expected to be completed about the same time as the phase II projects.
Once the Navajo projects discussed above are complete, the Navajo Refinery will be able to process up to 40% of lower cost heavy crude oil. The projects will also increase the yield of diesel, supply Holly Asphalt with all its performance grade asphalt requirements, increase refinery liquid volume yield, increase the refinery’s capacity to process outside feedstocks and enable the refinery to meet new LSG specifications required by the U.S. Environmental Protection Agency (“EPA”).vacuum units.
The Navajo Refinery currently plans to comply with new Control of Hazardous Air Pollutants from Mobile Sources (“MSAT2”) regulations issued by the EPAEnvironmental Protection Agency (“EPA”) by the fractionation of raw naphtha with existing equipment to achieve benzene in gasoline levels below 1.3%. The Navajo Refinery will purchase or use credits fromgenerated at the Woods Cross and Tulsa Refineries in orderRefinery to reduce benzene downcontent 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 20122011 to comply with the MSAT2 regulationregulations because we have lost ourno longer qualify for the small refiner’s exemptionexemption. Also, we will be installing a new storm water surge tank and as a large refiner we have 30 monthsupgrade several other processes at the refinery’s Artesia waste water treatment plant. These projects are expected to comply.
Additionally, our total approved capital budget for Holly Asphalt for 2010 is $1.2cost approximately $17 million.
Woods Cross Refinery
Facilities
The Woods Cross Refinery has a crude oil capacity of 31,000 BPSD and is located in Woods Cross, Utah. The Woods Cross Refinery processes regional sweet and black wax crude as well as Canadian sour crude oils into high value light products. For 2009,2010, gasoline, diesel fuel and dieseljet fuel (excluding volumes purchased for resale) represented 64%63%, 30% and 28%1%, respectively, of the Woods Cross Refinery’s sales volumes.
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The following table sets forth information about the Woods Cross Refinery operations, including non-GAAP performance measures about our 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 7A of Part II of this Form 10-K.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | Years Ended December 31, | |
| | | 2009 | | 2008 | | 2007 | | | 2010 | | 2009 | | 2008 | |
Woods Cross Refinery | | |
Crude charge (BPD) (1) | | 24,900 | | 21,660 | | 24,030 | | | 25,870 | | 24,900 | | 21,660 | |
Refinery production (BPD)(2) | | 25,750 | | 22,170 | | 25,340 | | |
Refinery throughput (BPD)(2) | | | 27,540 | | 26,520 | | 23,340 | |
Refinery production (BPD)(3) | | | 27,020 | | 25,750 | | 22,170 | |
| Sales of produced refined products (BPD) | | 26,870 | | 22,370 | | 26,130 | | | 27,810 | | 26,870 | | 22,370 | |
Sales of refined products (BPD)(3) | | 27,250 | | 23,430 | | 26,340 | | |
Sales of refined products (BPD)(4) | | | 27,980 | | 27,250 | | 23,430 | |
| | | |
Refinery utilization(4) | | | 80.3 | % | | | 79.5 | % | | | 92.4 | % | |
Refinery utilization(5) | | | | 83.5 | % | | | 80.3 | % | | | 79.5 | % |
| | | |
Average per produced barrel(5) | | |
Average per produced barrel(6) | | |
| Net sales | | $ | 70.25 | | $ | 110.07 | | $ | 90.09 | | | $ | 94.26 | | $ | 70.25 | | $ | 110.07 | |
Cost of products(6) | | 58.98 | | 93.47 | | 69.40 | | |
Cost of products(7) | | | 75.54 | | 58.98 | | 93.47 | |
| | | | | | | | | | | | | | | |
| Refinery gross margin | | 11.27 | | 16.60 | | 20.69 | | | 18.72 | | 11.27 | | 16.60 | |
Refinery operating expenses(7) | | 6.60 | | 7.42 | | 4.86 | | |
Refinery operating expenses(8) | | | 6.09 | | 6.60 | | 7.42 | |
| | | | | | | | | | | | | | | |
| Net operating margin | | $ | 4.67 | | $ | 9.18 | | $ | 15.83 | | | $ | 12.63 | | $ | 4.67 | | $ | 9.18 | |
| | | | | | | | | | | | | | | |
| | | |
| Refinery operating expenses per throughput barrel | | | $ | 6.15 | | $ | 6.69 | | $ | 7.11 | |
| | | |
| Feedstocks: | | |
| Sour crude oil | | | 5 | % | | | 1 | % | | | 2 | % | |
| Heavy sour crude oil | | | | 6 | % | | | 5 | % | | | 1 | % |
| Sweet crude oil | | | 62 | % | | | 72 | % | | | 75 | % | | | 59 | % | | | 62 | % | | | 72 | % |
| Black wax crude oil | | | 28 | % | | | 21 | % | | | 15 | % | | | 30 | % | | | 28 | % | | | 21 | % |
| Other feedstocks and blends | | | 5 | % | | | 6 | % | | | 8 | % | | | 5 | % | | | 5 | % | | | 6 | % |
| | | | | | | | | | | | | | | |
| Total | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % |
| | | | | | | | | | | | | | | |
| | |
| (1) | | Crude charge represents the barrels per day of crude oil processed at our refinery. |
| |
| (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 refinery. |
|
| (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 refinery. |
| |
(3)(4) | | Includes refined products purchased for resale. |
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| | |
(4)(5) | | Represents crude charge divided by total crude capacity (BPSD). The crude capacity was increased by 5,000 BPSD in the fourth quarter of 2008 (our 2008 Woods Cross Refinery expansion), increasing crude capacity to 31,000 BPSD. |
| |
(5)(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 7A of Part II of this Form 10-K. |
| |
(6)(7) | | Transportation costs billed from HEP are included in cost of products. |
| |
(7)(8) | | Represents operating expenses of the refinery, exclusive of depreciation and amortization. |
The Woods Cross Refinery facility is located on a 200-acre site and is a fully integrated refinery with crude distillation, solvent deasphalter, FCC, HF alkylation, catalytic reforming, hydrodesulfurization, isomerization, sulfur recovery and product blending units. Other supporting infrastructure includes approximately 1.5 million barrels of feedstock and product tankage of which 0.2 million barrels of tankage are owned by HEP, maintenance shops, warehouses and office buildings. The operating units at the Woods Cross Refinery include newly constructed units, older units that have been relocated from other facilities, upgraded and re-erected in Woods Cross, and units that have been operating as part of the Woods Cross facility (with periodic major maintenance) for many years, in some very limited cases since before 1950. The crude oil capacity of the Woods Cross Refinery is 31,000 BPSD and the facility typically processes or blends an additional 2,000 BPSD of natural gasoline, butane and gas oil. The Woods Cross Refinery completed a major maintenance turnaround in September 2008.
We own and operate 4 miles of hydrogen pipeline that allows us to connect to a hydrogen plant located at Chevron’s Salt Lake City Refinery. Additionally, HEP owns and operates 12 miles of crude oil and refined products pipelines that allows us to connect our Woods Cross Refinery to common carrier pipeline systems.
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Markets and Competition
The Woods Cross Refinery is one of five refineries located in Utah. We estimate that the four refineries that compete with our Woods Cross Refinery have a combined capacity to process approximately 150,000 BPD of crude oil. The five Utah refineries collectively supply an estimated 70% of the gasoline and distillate products consumed in the states of Utah and Idaho, with the remainder imported from refineries in Wyoming and Montana via the Pioneer Pipeline owned jointly by Sinclair and ConocoPhillips. The Woods Cross Refinery’s primary markets include Utah, Idaho, Nevada, Wyoming and eastern Washington. Approximately 50%40% — 55%45% of the gasoline and diesel fuel produced by our Woods Cross Refinery is sold through a network of Phillips 66 branded marketers under a long-term supply agreement.
Utah Market
The Utah market for refined products is currently supplied primarily by a number of local refiners and the Pioneer Pipeline. Local area refiners include Woods Cross, Chevron, Tesoro, Big West and Silver Eagle. Other refiners that ship via the Pioneer Pipeline include Sinclair, ExxonMobil and ConocoPhillips. We supply approximately 15% — 20% of the refined products consumed in the Utah market, to branded and unbranded customers.
Idaho, Wyoming, Eastern Washington and Nevada Markets
We supply approximately 2% of the refined products consumed in the combined Idaho, Wyoming, eastern Washington and Nevada markets. Our Woods Cross Refinery ships refined products over Chevron’s common carrier pipeline system to numerous terminals, including HEP’s terminals at Boise and Burley, Idaho and Spokane, Washington and to terminals at Pocatello and Boise, Idaho and Pasco, Washington that are owned by Northwest Terminalling Pipeline Company. We sell to branded and unbranded customers in these markets. We also truck refined products to Las Vegas, Nevada.
The Idaho market for refined products is primarily supplied via Chevron’s common carrier pipeline system from refiners located in the Salt Lake City area and products supplied from the Pioneer Pipeline system. Refiners that could potentially supply the Chevron and Pioneer Pipeline systems include Woods Cross, Chevron, Tesoro, Big West, Silver Eagle, Sinclair, ConocoPhillips and ExxonMobil.
We market refined products in the Wyoming market on a limited basis. Refiners that supply Wyoming include Sinclair, ConocoPhillips, ExxonMobil and Frontier.
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The eastern Washington market is supplied by two common carrier pipelines, Chevron and Yellowstone. Product is also shipped into the area via rail from various points in the United States and Canada. Refined products shipped on Chevron’s pipeline system are supplied by refiners and other pipelines located in the Salt Lake City area and from refiners located in the Pacific Northwest. Pacific Northwest refiners include BP, Tesoro, Shell, ConocoPhillips and US Oil. Products supplied from the sources located in the Pacific Northwest area are generally shipped over the Columbia River via barge at Pasco, Washington.
The majority of the Las Vegas, Nevada market for refined products is supplied by various West Coast refiners and suppliers via Kinder Morgan’s CalNev common carrier pipeline system.
Principal Products and Customers
Set forth below is information regarding the principal products produced at our Woods Cross Refinery:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | Years Ended December 31, |
| | | 2009 | | 2008 | | 2007 | | | 2010 | | 2009 | | 2008 |
Woods Cross Refinery | | |
| Sales of produced refined products: | | |
| Gasolines | | | 64 | % | | | 63 | % | | | 63 | % | | | 63 | % | | | 64 | % | | | 63 | % |
| Diesel fuels | | | 28 | % | | | 29 | % | | | 27 | % | | | 30 | % | | | 28 | % | | | 29 | % |
| Jet fuels | | | 1 | % | | | — | % | | | 2 | % | | | 1 | % | | | 1 | % | | | — | % |
| Fuel oil | | | 3 | % | | | 5 | % | | | 5 | % | | | 1 | % | | | 3 | % | | | 5 | % |
| Asphalt | | | 2 | % | | | 1 | % | | | 1 | % | | | 3 | % | | | 2 | % | | | 1 | % |
| LPG and other | | | 2 | % | | | 2 | % | | | 2 | % | | | 2 | % | | | 2 | % | | | 2 | % |
| | | | | | | | | | | | | | | |
| Total | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % |
| | | | | | | | | | | | | | | |
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Light products are shipped by product pipelines or are made available at various points by exchanges with others. Light products are also made available to customers through truck loading facilities at the refinery and at terminals.
Our principal customers for gasoline include other refiners, convenience store chains, independent marketers and retailers. The composition of gasoline differs, due to local regulatory requirements, depending on the area in which gasoline is to be sold. Diesel fuel is sold to other refiners, truck stop chains and wholesalers. Limited quantities of jet fuel are sold for commercial airline use. Asphalt produced is either blended to fuel oil or is sold locally, or shipped by rail to the Gulf Coast, shipped by rail directly to our customers or marketed through Holly Asphalt to governmental entities or contractors. LPG’s are sold to LPG wholesalers and LPG retailers.
Crude Oil and Feedstock Supplies
The Woods Cross Refinery currently obtains its supply of crude oil primarily from suppliers in Canada, Wyoming, Utah and Colorado as delivered via common carrier pipelines that originate in Canada, Wyoming and Colorado. In 2009, we also began receiving crude oil via the SLC Pipeline, a joint venture common carrier pipeline in which HEP owns a 25% interest. Supplies of black wax crude oil are shipped via truck.
Capital Improvement Projects
Our total approved capital budget for the Woods Cross Refinery for 20102011 is $36.4$7.7 million. Additionally, capital costs of $3.3$0.4 million have been approved for refinery turnarounds and tank work. We expect to spend approximately $12.6$13 million in capital costs in 2010,2011, including capital projects approved in prior years. The following summarizes our key capital projects.
At the Woods Cross Refinery, we increased the refinery’s capacity from 26,000 BPSD to 31,000 BPSD while increasing its ability to process lower cost crude. The project involved installing a new 15,000 BPSD mild hydrocracker, sulfur recovery facilities, black wax desalting equipment and black wax unloading systems. The total cost of this project was approximately $122 million. The projects were mechanically complete in the fourth quarter of 2008.
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 Woods Crossthe refinery involves revamping its naphtha fractionation unit and installing a new reformate splitter and a benzene saturation unit at an estimated cost of $18$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 20122011 to comply with the MSAT2 regulations.
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Tulsa Refinery
Facilities
On June 1, 2009, we acquired the Tulsa Refinery west facility, an 85,000 BPSD refinery in Tulsa, Oklahoma from Sunoco. On December 1, 2009, we acquired the Tulsa Refinery east facility, a 75,000 BSPD refinery that is also located in Tulsa, Oklahoma from Sinclair. We are in the process of integrating the operations of both Tulsa Refinery facilities. Upon completion, the Tulsa Refinery will have an integrated crude processing rate of 125,000 BPSD.
The Tulsa Refinery primarily processes sweet crude oils into high value light products such as gasoline, diesel fuel, jet fuel and specialty lubricants, however, has the capability to process sour crude oils when economics dictate. For 2009,2010, gasoline, diesel fuel, jet fuel and specialty lubricants (excluding volumes purchased for resale) represented 26%38%, 29%31%, 10%8% and 16%11%, respectively, of the Tulsa Refinery’s sales volumes.
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The following table sets forth information about the Tulsa Refinery operations, including non-GAAP performance measures about our 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 7A of Part II of this Form 10-K.
| | | | | | |
| | | Year Ended | | | | | | | | | |
| | | December 31, | | | Years Ended December 31, | |
| | | 2009(8) | | | 2010 | | 2009(9) | |
Tulsa Refinery | | |
Crude charge (BPD) (1) | | 39,370 | | | 111,670 | | 39,370 | |
Refinery throughput (BPD)(2) | | | 113,100 | | 39,520 | |
Refinery production (BPD)(2)(3) | | 38,910 | | | 106,910 | | 38,910 | |
| Sales of produced refined products (BPD) | | 37,570 | | | 107,780 | | 37,570 | |
Sales of refined products (BPD)(3)(4) | | 37,700 | | | 108,330 | | 37,700 | |
| | | |
Refinery utilization(4)(5) | | | 74.0 | % | | | 89.3 | % | | | 74.0 | % |
| | | |
Average per produced barrel(5)(6) | | |
| Net sales | | $ | 78.89 | | | $ | 90.84 | | $ | 78.89 | |
Cost of products(6)(7) | | 74.56 | | | 83.29 | | 74.56 | |
| | | | | | | | | |
| Refinery gross margin | | 4.33 | | | 7.55 | | 4.33 | |
Refinery operating expenses(7)(8) | | 5.25 | | | 4.94 | | 5.25 | |
| | | | | | | | | |
| Net operating margin | | $ | (0.92 | ) | | $ | 2.61 | | $ | (0.92 | ) |
| | | | | | | | | |
| | | |
| Refinery operating expenses per throughput barrel | | | $ | 4.71 | | $ | 4.99 | |
| | | | |
| Feedstocks: | | |
| Sour crude oil | | | | 5 | % | | | — | % |
| Sweet crude oil | | | 100 | % | | | 92 | % | | | 100 | % |
| Heavy sour crude oil | | | | 3 | % | | | — | % |
| | | | | | | |
| Total | | | | 100 | % | | | 100 | % |
| | | | | | | |
| | |
| (1) | | Crude charge represents the barrels per day of crude oil processed at our refinery. |
| |
| (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 refinery. |
|
| (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 refinery. |
| |
(3)(4) | | Includes refined products purchased for resale. |
| |
(4)(5) | | Represents crude charge divided by total crude capacity (BPSD). The crude capacity of 85,000 BPSD (our June 2009 Tulsa Refinery west facility acquisition) was increased by 40,000 BPSD in the fourth quarter of 2009 (our December 2009 Tulsa Refinery east facility acquisition), increasing crude capacity to 125,000 BPSD. |
| |
(5)(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 7A of Part II of this Form 10-K. |
| |
(6)(7) | | Transportation costs billed from HEP are included in cost of products. |
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| | |
(7)(8) | | Represents operating expenses of the refinery, exclusive of depreciation and amortization. |
| |
(8)(9) | | The amounts reported for the Tulsa Refinery for the year ended December 31, 2009 include crude oil processed and products yielded from the refinery for the period from June 1, 2009 through December 31, 2009 only, and averaged over the 365 days for the year ended. Operating data for the period from June 1, 2009 (date of Tulsa Refinery west facility acquisition) through December 31, 2009 and for the period from December 1, 2009 (date of Tulsa Refinery east facility acquisition) through December 31, 2009 is as follows: |
| | | | | | | | | |
| | | Period From | | Period From |
| | | June 1, 2009 | | December 1, 2009 |
| | | Through | | Through |
| | | December 31, 2009 | | December 31, 2009 |
Tulsa Refinery | | | | | | | | |
| Crude charge (BPD) | | | 67,160 | | | | 93,810 | |
| Refinery production (BPD) | | | 66,360 | | | | 99,810 | |
| Sales of produced refined products (BPD) | | | 64,080 | | | | 96,170 | |
| Sales of refined products (BPD) | | | 64,300 | | | | 96,170 | |
The Tulsa Refinery west facility is located on a 750-acre site in Tulsa, Oklahoma situated along the Arkansas River. The principal process units at the Tulsa Refinery west facility consist of crude distillation (with light ends recovery), naphtha hydrodesulfurization, catalytic reforming, propane de-asphalting, lubelubes extraction, unit, MEK dewaxing, delayed coker and butane splitter units. Most of the operating units at the facility currently in service were built in the late 1950s and early 1960s. The refinery was reconfigured to emphasize specialty lubricant production in the early 1990s. The refinery completed a major maintenance turnaround in July 2007. The refinery’s supporting infrastructure includes approximately 3.2 million barrels of feedstock and product tankage, of which 0.4 million barrels of tankage is owned by Plains, and an additional 1.2 million barrels of tank capacity that are currently out of service and could be made available for future use.
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The Tulsa Refinery east facility is located on a 466-acre site also in Tulsa, Oklahoma situated along the Arkansas River. The principal process units at the Tulsa Refinery east facility consist of crude distillation, naphtha hydrodesulfurization, FCC, isomerization, catalytic reforming, alkylation, scanfiner, diesel hydrodesulfurization and sulfur units. Additions and improvements to the facility since late 2004 include a scanfining unit to meet 2006 gasoline sulfur content requirements, a new naphtha hydro desulphurizer unit in 2005, a new sulfur plant, modifications to the distillate hydro desulphurizer unit, a new tail gas unit installed on the new sulfur plant and the conversion of the reformer from a 17,000 BPD semi-regenerative reformer to a 22,000 BPD continuous catalyst regeneration reformer (thereby increasing its capacity, octane capability and yield of gasoline). The refinery completed a partial maintenance turnaround in 2007, including the crude and FCC units. The refinery’s supporting infrastructure includes approximately 3.75 million barrels of tankage capacity on the refinery’s premises, of which approximately 1.43.4 million barrels of whichtankage is owned by HEP. We recently completed a turnaround of both Tulsa Refinery west and east facilities in January 2011.
We are integrating the Tulsa Refinery west and east facilities that will result in a single, highly complex refinery having an integrated crude processing rate of approximately 125,000 BPSD, primarily by sending intermediate streams from one facility to the other for further processing. Pursuant to this plan, high sulfur diesel and various gas oil streams will be sent from the Tulsa Refinery west facility to be processed in the diesel hydrotreater and FCC units, respectively, at the Tulsa Refinery east facility. Various heavy oil streams will beare sent from the Tulsa Refinery east facility to be processed in our coker unit at our Tulsa Refinery west facility. Various other streams such asThe majority of the naphtha hydrogenfrom the west facility is processed at the east facility and is delivered along with gas oils via the existing interconnect line. Hydrogen and fuel gas will be shared between the two refinery facilities.facilities upon completion of additional interconnect pipelines.
The Tulsa Refinery produces fuel products including gasoline, diesel fuel, jet fuel, #1 fuel oil, asphalt, heavy fuels and LPGs and serves markets in the Mid-Continent region of the United States and also produces specialty lubricant products that are marketed throughout North America and are distributed in Central and South America.
Markets and Competition
The Tulsa Refinery primarily serves the Mid-Continent region of the United States. Distillates and gasolines are primarily delivered from the Tulsa Refinery to market via two pipelines owned and operated by Magellan. These pipelines connect the refinery to distribution channels throughout Oklahoma, Kansas, Missouri, Illinois, Iowa, Minnesota, Nebraska and Arkansas. Additionally, the Tulsa Refinery has a proprietary diesel transfer line to the
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local Burlington Northern Santa Fe Railroad depot, and the refinery’sHEP’s on-site truck and rail rack capability facilitatesracks facilitate access to local refined product markets.
In conjunction with our acquisition of the Tulsa Refinery east facility, we entered a five-year offtake agreement with an affiliate of Sinclair whereby Sinclair has agreed to purchase 45,000 to 50,000 BPD of gasoline and distillate products at market prices from us to supply its branded and unbranded marketing network throughout the Midwest. The offtake agreement can be renewed by Sinclair for an additional five-year term.
Our Tulsa Refinery also produces specialty lubricant products including agricultural oils, base oils, process oils and waxes that are sold throughout the United States and to customers with operations in Central America and South America. Our refinery’s production represents 6% of paraffinic oil capacity and 12% of wax production capacity in the United States market and is one of four refineries of specialty aromatic oils in North America.
The refinery’s asphalt and roofing flux products are sold via truck or railcar directly from the refinery or from a leased terminal in Phillipsburg, Kansas to customers throughout the Mid-Continent region.
Principal Products and Customers
Set forth below is information regarding the principal products produced at our Tulsa Refinery:
| | | | |
| | Year Ended | |
| | December 31, | |
| | 2009 | |
Tulsa Refinery| | | | | | | | | | | | | Years Ended December 31, | | | | 2010 | | 2009 | Tulsa Refinery | | | | | | | | | | Sales of produced refined products: | | | | | | | | | | Gasolines | | | 38 | % | | | 26 | % | | Diesel fuels | | | 31 | % | | | 29 | % | | Jet fuels | | | 8 | % | | | 10 | % | | Lubricants | | | 11 | % | | | 16 | % | | Gas oil / intermediates | | | 4 | % | | | 17 | % | | Asphalt | | | 5 | % | | | — | % | | LPG and other | | | 3 | % | | | 2 | % | | | | | | | | | | | | Total | | | 100 | % | | | 100 | % | | | | | | | | | | |
| | | | |
Sales of produced refined products: | | | | |
Gasolines | | | 26 | % |
Diesel fuels | | | 29 | % |
Jet fuels | | | 10 | % |
Lubricants | | | 16 | % |
Gas oil / intermediates | | | 17 | % |
LPG and other | | | 2 | % |
| | | |
Total | | | 100 | % |
| | | |
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Light products are shipped by product pipelines and are also made available to customers through truck and rail loading facilities. The Tulsa Refinery’s principal customers for conventional gasoline include Sinclair, other refiners, convenience store chains, independent marketers and retailers. The composition of gasoline differs, because of regulatory requirements, depending on the area in which gasoline is to be sold. Sinclair and railroads are the primary diesel customers. Jet fuel is sold primarily for commercial use. LPGs are sold to LPG wholesalers and retailers.
The specialty lubricant products produced at the Tulsa Refinery are high value products that provide a disproportionately highsignificantly higher margin contribution to the refinery. Specialty lubricant products are sold in both commercial and specialty markets. Base oil customers include blender-compounders who prepare the various finished lubricant and grease products sold to end users. Agricultural oils, primarily formulated as supplemental carriers for herbicides, are sold to product formulators. Process oil customers include rubber and chemical industry customers. Specialty waxes are sold primarily to packaging customers as coating material for paper and cardboard, and to non-packaging customers in the construction materials, adhesive orand candle-making businesses.markets.
Asphalt and roofing flux are sold primarily to paving contractors and manufacturers of roofing products.
Crude Oil and Feedstock Supplies
The Tulsa Refinery is located approximately 50 miles from Cushing, Oklahoma, a significant crude oil pipeline crossroadtrading and storage hub. Local pipelines provide direct access to regional Oklahoma crude production as well as manyaccess to United States onshore, Gulf of Mexico, Canadian and other foreign crudes. The proximity of the refinery to this pipeline and storage hub provides the refinery with the flexibility to optimize its crude slate and maintain lowerwith a wide variety of crude inventories than a typical refinery.oil supply options.
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The refinery also purchases other feedstocks on an opportunistic basis. From time to time, the refinery purchases naphtha, gasoline components, transmix, light cycle oil, lube blend stocks or residuals from other refineries. These feedstocks are delivered by truck, rail car or pipeline, depending on product and logistical requirements.
Capital Improvement Projects
Our total approved capital budget for the Tulsa Refinery for 20102011 is $101.6$100 million. Additionally, capital costs of $24$9.4 million have been approved for refinery turnarounds and tank work. We expect to spend approximately $63.2$70 million in capital costs in 2010,2011, including capital projects approved in prior years. 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. We have also signed a 10-year agreement with a third party for the use ofCurrently, we are using an additionalexisting third-party line for the transfer of gasoline blend stocks which is currently in service.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, we are planning to expandexpanding the diesel hydrotreater unit at the east facility to permit the processing of all high sulfur diesel produced to ULSD, eliminating the need to construct a new diesel hydrotreater at our west facility as previously planned.ULSD. This expansion is expected to cost approximately $20 million and will use the reactor that we acquired as part of the Tulsa Refinery west facility acquisition. We are currently planningexpect to complete the integration projects byin the endsecond quarter of the 2010.2011.
The combined Tulsa Refinery facilities also will be required to comply with 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 approximately $15$28.5 million. Our Tulsa Refinery is required to meet MSAT2 1.3% benzene levels in gasoline beginning in July 2012 and we expect complete this project well before then. 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.
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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. We estimatehave previously estimated a cost of $20 million to meet these requirements but our investmentBoard of Directors have approved a larger project for $44 million which would meet these requirements as well as increase our ability to comply withrun additional lower priced sour crudes at the requirements will be approximately $20 million. The consent decree also requires shutdown, replacement, or installation of low NOx burners in three low pressure boilers by the end of 2013. WeTulsa Refinery east facility. Also, we are still evaluating the best solution to thisthe 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.
Holly Asphalt Company
We believemanufacture and market commodity and modified asphalt products in Arizona, New Mexico, Oklahoma, Kansas, Missouri, Texas and northern Mexico. We have four manufacturing facilities located in Glendale, Arizona, Albuquerque, New Mexico, Artesia, New Mexico and Lubbock, Texas. Our Albuquerque, Artesia and Lubbock facilities manufacture modified hot asphalt products and commodity emulsions from base asphalt materials provided by our Navajo and Tulsa Refineries and third-party suppliers. Our Lubbock facility is leased under a lease agreement expiring December 31, 2011. Our Glendale facility manufactures modified hot asphalt products from base asphalt materials provided by our Navajo, Woods Cross and Tulsa Refineries and third-party suppliers. We sell additional modified asphalt and commodity emulsions into the Arizona and California markets through a third-party processing agreement in Phoenix. Our products are shipped via third-party trucking companies to commercial customers that provide asphalt based materials for commercial and government projects.
Our total capital budget for Holly Asphalt for 2011 is $3.6 million.
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We also completed our asphalt tankage project at the synergyNavajo Refinery and at the Holly Asphalt facility in Artesia, New Mexico in November 2010. This project consisted of asphalt tank additions and the Tulsaupgrade of our rail loading facilities at the Navajo Refinery west and east facilities operated as a single integrated facility will result in savings of approximately $110 million of expected capital expenditures related to ULSD compliance. Also as a result of the integrated facility, we expect to be able to reduce capital expenditures for the forthcoming benzene in gasoline requirements from approximately $30 million for the Tulsa Refinery west facility alone to approximately $15 million for the integrated complex. Even if we are able to realize the operating synergies of the integrated facility, our Tulsa Refinery will still require sulfur recovery investment, but we estimate combining the two refineries will reduce our net near-term capital expenditure requirements by approximately $125 million, excluding the cost to construct the pipelines that will integrate the west and east facilities.Artesia facility.
UNEV Pipeline
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. The current total cost of the pipeline project including terminals is expected to be $275approximately $325 million, with our share of the cost totaling $206$244 million. We expectThis 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 spend approximately $80 millionbe mechanically complete in capital costs in 2010, with our sharethe second quarter of the cost totaling $60 million.2011.
In connection with this project, we have entered into a 10-year commitment to ship an annual average of 15,000 BPD 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 BPDbarrels 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.
We currently anticipate that all regulatory approvals required to commence the construction of the UNEV Pipeline will be received by the end of the second quarter of 2010. Once such approvals are received, construction of the pipeline will take approximately nine months. Under this schedule, the pipeline would become operational during the first quarter of 2011.
HOLLY ENERGY PARTNERS, L.P.
In July 2004, we completed the initial public offering of limited partnership interests in HEP, a Delaware limited partnership that also trades on the New York Stock Exchange under the trading symbol “HEP.” HEP was formed to acquire, own and operate substantially all of the refined product pipeline and terminalling assets that support our refining and marketing operations in west Texas, New Mexico, Utah, Idaho, Arizona and Oklahoma.
HEP owns and operates a system of petroleum product and crude oil pipelines in Texas, New Mexico, Oklahoma and Utah and distribution terminals and refinery tankage in Texas, New Mexico, Arizona, Utah, Oklahoma, Idaho and Washington. HEP generates revenues by charging tariffs for transporting petroleum products and crude oil through its pipelines, by leasing certain pipeline capacity to Alon by charging fees for terminalling refined products and other hydrocarbons and storing and providing other services at its storage tanks and terminals. HEP does not take ownership of products that it transports or terminals; therefore, it is not directly exposed to changes in commodity prices.
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2010 Acquisitions
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.
2009 Acquisitions
Sinclair Logistics and Storage Assets Transaction
On December 1, 2009, HEP acquired certain logistics and storage assets from an affiliate of Sinclair for $79.2 million consisting of storage tanks having approximately 1.4 million barrels of storage capacity and loading racks at Sinclair’s refinery located inwhat is now our Tulsa Oklahoma.Refinery east facility for $79.2 million. The purchase price consisted of $25.7 million in cash, including $4.2 million in taxes and 1,373,609 of HEP’s common units having a fair value of $53.5 million. Concurrent with this transaction we entered into a 15-year pipeline, tankage and loading rack throughput agreement with HEP (the “HEP PTTA”), whereby we agreed to transport, throughput and load volumes of product via HEP’s Tulsa logistics and storage assets that will initially result in minimum annual payments to HEP of $13.8 million.
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Roadrunner / Beeson Pipelines Transaction
Also on December 1, 2009, HEP acquired our two newly constructed pipelines for $46.5 million, consisting of a 65-mile, 16-inch crude oil pipeline (the “Roadrunner Pipeline”) that connects our Navajo Refinery facility located in Lovington New Mexicofacility to a terminus of Centurion Pipeline L.P.’s pipeline extending between west Texas and Cushing, Oklahoma (the “Centurion Pipeline”) and a 37-mile, 8-inch crude oil pipeline that connects HEP’s New Mexico crude oil gathering system to our Navajo Refinery Lovington facility (the “Beeson Pipeline”).
The Roadrunner Pipeline provides our Navajo Refinery with direct access to a wide variety of crude oils available at Cushing, Oklahoma. In connection with this transaction, we entered into a 15-year pipeline agreement with HEP, (the “HEP RPA”), whereby we agreed to transport volumes of crude oil on HEP’s Roadrunner Pipeline that will initially result in minimum annual payments to HEP of $9.2 million.
The Beeson Pipeline operates as a component of HEP’s crude pipeline system and provides us with added flexibility to move crude oil from HEP’s crude oil gathering system to our Navajo Refinery Lovington facility for processing.
Tulsa West Loading Racks Transaction
On August 1, 2009, HEP acquired from us, certain truck and rail loading/unloading facilities located at our Tulsa Refinery west facility for $17.5 million. The racks load refined products and lube oils produced at the Tulsa Refinery onto rail cars and/or tanker trucks.
In connection with this transaction, we entered into a 15-year equipment and throughput agreement with HEP, (the “HEP ETA”), whereby we agreed to throughput a minimum volume of products via HEP’s Tulsa loading racks that will initially result in minimum annual payments to HEP of $2.7 million.
Lovington-Artesia Pipeline Transaction
On June 1, 2009, HEP acquired our newly constructed, 16-inch intermediate pipeline for $34.2 million. The pipelinemillion that runs 65 miles from our Navajo Refinery’s crude oil distillation and vacuum facilities in Lovington, New Mexico to our petroleum refinery located in Artesia, New Mexico. This pipeline was placed in service effective June 1, 2009 and operates as a component of HEP’s intermediate pipeline system that services our Navajo Refinery.
In connection with this transaction, we agreed to amend our intermediate pipeline agreement with HEP (the “HEP IPA”). As a result, the term of the HEP IPA was extended by an additional four years and now expires in June 2024. Additionally, our minimum commitment under the HEP IPA was increased and currently results in minimum annual payments to HEP of $20.7 million.
SLC Pipeline Joint Venture Interest
On March 1, 2009, HEP acquired a 25% joint venture interest in the SLC Pipeline, a new 95-mile intrastate pipeline system jointly owned with Plains. The SLC Pipeline commenced operations effective March 2009 and allows various refineries in the Salt Lake City area, including our Woods Cross Refinery, to ship crude oil into the Salt Lake City area from the Utah terminus of the Frontier Pipeline as well as crude oil flowing from Wyoming and Utah via Plains’ Rocky Mountain Pipeline. HEP’s capitalized joint venture contribution was $25.5 million.
Rio Grande Pipeline Sale
On December 1, 2009, HEP sold its 70% interest in Rio Grande Pipeline Company (“Rio Grande”) to a subsidiary of Enterprise Products Partners LP for $35 million. Accordingly, the resultsResults of operations of Rio Grande and gain of $14.5 million on the sale are presented in discontinued operations.
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Transportation Agreements
Agreements with HEP
HEP serves our refineries in New Mexico, Utah and Oklahoma under severalthe following long-term pipeline and terminal, tankage and throughput agreements.agreements:
In connection with our 2009 asset transfers to HEP, as described above, we entered into three new 15-year transportation agreements with HEP, each expiring in 2024.
In addition, we have a transportation agreement with HEP that relates to the pipelines and terminals that we contributed to HEP at the time of its initial public offering in 2004 that expires in 2019 (the “HEP PTA”), the HEP IPA that relates to the intermediate pipelines sold to HEP in 2005 and in June 2009 that expires in 2024 and a transportation agreement that relates to the Crude Pipelines and Tankage Assets sold to HEP in 2008 that expires in 2023 (the “HEP CPTA”) | • | | 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); |
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| • | | HEP IPA (intermediate pipelines throughput agreement expiring in 2024 that relates to the intermediate pipelines sold to HEP in 2005 and 2009); |
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| • | | 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); |
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| • | | 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); |
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| • | | HEP RPA (pipeline throughput agreement expiring in 2024 that relates to the Roadrunner Pipeline sold to HEP in 2009); |
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| • | | HEP ETA (equipment and throughput agreement expiring in 2024 that relates to the Tulsa west loading rack facilities sold to HEP in 2009); |
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| • | | HEP NPA (natural gas pipeline throughput agreement expiring in 2024); and |
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| • | | 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 HEP’s pipeline and terminal, tankage and loading rack facilities that result in minimum annual payments to HEP. These minimum annual payments are adjusted each year at a percentage change based upon the change in the Producer Price Index (“PPI”) but will not decrease as a result of a decrease in the PPI. Under these agreements, the agreed upon tariff rates are adjusted each year on July 1 at a rate based upon the percentage change in 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. The FERC index is the change in the PPI plus a FERC
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adjustment factor that is reviewed periodically. Following the July 1, 20092010 PPI rate adjustments,adjustment, these agreements including our new 2009 agreements with HEP, will result in minimum annualized payments to HEP of $118.5$133 million for the twelve months endingended June 30, 2010.
Additionally, in February 2010, we entered into a pipeline systems operating agreement with HEP expiring in 2014 (the “HEP Pipeline Operating Agreement”). Under the HEP Pipeline Operating Agreement, effective December 1, 2009, HEP will operate certain of our tankage, pipelines, asphalt racks and terminal buildings for an annual management fee of $1.3 million.2011.
We reconsolidated HEP effective March 1, 2008. Following our reconsolidation, our transactions with HEP including fees that we pay under our HEP transportation agreements are eliminated and have no impact on our consolidated financial statements since HEP is a consolidated subsidiary.VIE.
Agreement with Alon
HEP also has a 15-year pipelines and terminals agreement with Alon expiring in 2020 (the “Alon PTA”), under which Alon has agreed to transport on HEP’s pipelines and throughput through its terminals, volumes of refined products that results in a minimum level of annual revenue. The agreed upon tariff rates are increased or decreased annually at a rate equal to the percentage change in PPI, but will not decrease below the initial $20.2 million annual amount. Following the March 1, 2009 PPI adjustment, Alon’s total minimum commitmenttariff rate.
HEP also has a capacity lease agreement with Alon under which Alon is leased space on HEP’s Orla to El Paso pipeline for the twelve months ending February 28, 2010 is $21.7 million. Furthermore, for the twelve months ending February 28, 2011, Alon’s minimum commitment will increaseshipment of up to $22.7 million as a result17,500 barrels of the upcoming March 1, 2010 PPI adjustment.refined product per day. The terms under this agreement expire beginning in 2012 through 2018.
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As of December 31, 2009,2010, HEP’s contractual minimum revenues under long-term service agreements are as follows:
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| | | | | | | | | | | Minimum Annualized | | | | |
| | | Minimum Annualized | | | | | | Commitment | | | | |
| Agreement | | Commitment
(In millions) | | Year of
Maturity | | Contract Type | | (In millions) | | Year of Maturity | | Contract Type |
| | | | | | |
HEP PTA(1) | | $ | 43.7 | | 2019 | | Minimum revenue commitment | | | $ 43.7 | | 2019 | | Minimum revenue commitment |
HEP IPA(2)(1) | | 20.7 | | 2024 | | Minimum revenue commitment | | 20.7 | | 2024 | | Minimum revenue commitment |
HEP CPTA(3)(1) | | 28.4 | | 2023 | | Minimum revenue commitment | | 28.4 | | 2023 | | Minimum revenue commitment |
HEP PTTA(1) | | 13.8 | | 2024 | | Minimum revenue commitment | | 27.2 | | 2024 | | Minimum revenue commitment |
HEP RPA(1) | | 9.2 | | 2024 | | Minimum revenue commitment | | 9.2 | | 2024 | | Minimum revenue commitment |
HEP ETA(1) | | 2.7 | | 2024 | | Minimum revenue commitment | | 2.7 | | 2024 | | Minimum revenue commitment |
Alon PTA(4) | | 21.7 | | 2020 | | Minimum volume commitment | |
Alon capacity lease(4) | | 6.4 | | Various | | Capacity lease | |
Holly ATA(1) | | | 0.5 | | 2025 | | Minimum revenue commitment |
Holly NPA(1) | | | 0.6 | | 2024 | | Minimum revenue commitment |
Alon PTA(2) | | | 22.7 | | 2020 | | Minimum volume commitment |
Alon capacity lease(2) | | | 6.6 | | Various | | Capacity lease |
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| Total | | $ | 146.6 | | | | | | | $162.3 | | |
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| (1) | | HEP’s revenue under these transportation agreements with us represents intercompany revenue and is eliminated in our consolidated financial statements. |
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| (2) | | Reflects amended terms of the Holly IPA effective June 2009. |
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(3) | | Reflects amended terms of the Holly CPTA effective January 2009. |
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(4) | | Minimum annual revenues attributable to long-term service contracts with unaffiliated parties are $28.1$29.3 million. |
As of December 31, 2009,2010, HEP’s assets include:
Pipelines
| • | | approximately 820 miles of refined product pipelines, including 340 miles of leased pipelines, that transport gasoline, diesel and jet fuel principally from our Navajo Refinery in New Mexico to our customers in the metropolitan and rural areas of Texas, New Mexico, Arizona, Colorado, Utah and northern Mexico; |
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| • | | approximately 510 miles of refined product pipelines that transport refined products from Alon’s Big Spring refinery in Texas to its customers in Texas and Oklahoma; |
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| • | | three 65-mile pipelines that transport intermediate feedstocks and crude oil from our Navajo Refinery crude oil distillation and vacuum facilities in Lovington, New Mexico to our petroleum refinery facilities in Artesia, New Mexico; |
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| • | | approximately 960 miles of crude oil trunk, gathering and connection pipelines located in west Texas, New Mexico and Oklahoma that deliver crude oil to our Navajo Refinery; |
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| • | | approximately 10 miles of crude oil and refined product pipelines that support our Woods Cross Refinery located near Salt Lake City, Utah; and |
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| • | | gasoline and diesel connecting pipelines that support our Tulsa Refinery east facility. |
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approximately 510 miles of refined product pipelines that transport refined products from Alon’s Big Spring refinery in Texas to its customers in Texas and Oklahoma;
three 65-mile pipelines that transport intermediate feedstocks and crude oil from our Navajo Refinery crude oil distillation and vacuum facilities in Lovington, New Mexico to our petroleum refinery facilities in Artesia, New Mexico;
approximately 960 miles of crude oil trunk, gathering and connection pipelines located in west Texas, New Mexico and Oklahoma that deliver crude oil to our Navajo Refinery;
approximately 10 miles of crude oil and refined product pipelines that support our Woods Cross Refinery located near Salt Lake City, Utah; and
gasoline and diesel connecting pipelines that support our Tulsa Refinery east facility.
Refined Product Terminals and Refinery Tankage
| • | | four refined product terminals located in El Paso, Texas; Moriarty and Bloomfield, New Mexico; and Tucson, Arizona, with an aggregate capacity of approximately 1,000,000 barrels, that are integrated with HEP’s refined product pipeline system that serves our Navajo Refinery; |
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| • | | three refined product terminals (two of which are 50% owned), located in Burley and Boise, Idaho and Spokane, Washington, with an aggregate capacity of approximately 500,000 barrels, that serve third-party common carrier pipelines; |
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| • | | one refined product terminal near Mountain Home, Idaho with a capacity of 120,000 barrels, that serves a nearby United States Air Force Base; |
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| • | | two refined product terminals, located in Wichita Falls and Abilene, Texas, and one tank farm in Orla, Texas with aggregate capacity of 480,000 barrels, that are integrated with HEP’s refined product pipelines that serve Alon’s Big Spring, Texas refinery; |
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| • | | a refined product truck loading rack facility at each of our Navajo and Woods Cross Refineries, an asphalt truck loading rack at our Navajo Refinery Lovington facility, refined product and lube oil rail loading racks and a lube oil truck loading rack at our Tulsa Refinery west facility and a refined product, asphalt and LPG truck loading rack, a truck unloading rack and a rail loading rack at our Tulsa Refinery east facility; |
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| • | | a Roswell, New Mexico jet fuel terminal leased through September 2011; |
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| • | | on-site crude oil tankage at our Navajo, Woods Cross and Tulsa Refineries having an aggregate storage capacity of approximately 600,000 barrels; and |
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| • | | on-site refined product tankage at our Tulsa Refinery having an aggregate storage capacity of approximately 3,400,000 barrels. |
three refined product terminals (two of which are 50% owned), located in Burley and Boise, Idaho and Spokane, Washington, with an aggregate capacity of approximately 500,000 barrels, that serve third-party common carrier pipelines;
one refined product terminal near Mountain Home, Idaho with a capacity of 120,000 barrels, that serves a nearby United States Air Force Base;
two refined product terminals, located in Wichita Falls and Abilene, Texas, and one tank farm in Orla, Texas with aggregate capacity of 480,000 barrels, that are integrated with HEP’s refined product pipelines that serve Alon’s Big Spring, Texas refinery;
a refined product truck loading rack facility at each of our Navajo and Woods Cross Refineries, refined product and lube oil rail loading racks and a lube oil truck loading rack at our Tulsa Refinery west facility and a refined product, asphalt and LPG truck loading rack at our Tulsa Refinery east facility;
a Roswell, New Mexico jet fuel terminal leased through September 2011;
on-site crude oil tankage at our Navajo, Woods Cross and Tulsa Refineries having an aggregate storage capacity of approximately 600,000 barrels; and
on-site refined product tankage at our Tulsa Refinery having an aggregate storage capacity of approximately 1,400,000 barrels.
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HEP also owns a 25% joint venture interest in the SLC Pipeline, a new 95-mile intrastate crude oil pipeline system that serves refineries in the Salt Lake City area.
Capital Improvement Projects
HEP’s capital budget for 20102011 is comprised of $4.8$5.8 million for maintenance capital expenditures and $6$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 $28 million with completion in the second quarter 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.
ADDITIONAL OPERATIONS AND OTHER INFORMATION
Corporate Offices
We lease our principal corporate offices in Dallas, Texas. The lease for our principal corporate offices expiringexpires in June 2011 and requires lease payments of approximately $115,000 per month plus certain operating expenses and providesexpenses. Prior to expiration, we will be relocating our corporate offices to a nearby office building complex, also located in Dallas, Texas. The lease for one five-year renewal period.our new office expires in 2021. Functions performed in the Dallas office include overall corporate management, refinery and HEP management, planning and strategy, corporate finance, crude acquisition, logistics, contract administration, marketing, investor relations, governmental affairs, accounting, tax, treasury, information technology, legal and human resources support functions.
Employees and Labor Relations
As of December 31, 2009,2010, we had 1,6321,661 employees, of which 347353 are currently covered by collective bargaining agreements. We consider our employee relations to be good. We are currently negotiating thehave collective bargaining agreement for certain of our Navajo Refinery Lovington facility employees, which agreement expires in April 2010. We also have a collective bargaining agreementagreements for certain of our Woods Cross Refinery employees that expiresexpire in 2012.2012 and agreements with certain of our Navajo Refinery Artesia and Lovington facility employees that expire in 2016.
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Regulation
Refinery and pipeline operations are subject to federal, state and local laws regulating the discharge of matter into the environment or otherwise relating to the protection of the environment. Permits are required under these laws for the operation of our refineries, pipelines and related operations, and these permits are subject to revocation, modification and renewal. Over the years, there have been and continue to be ongoing communications, including notices of violations, and discussions about environmental matters between us and federal and state authorities, some of which have resulted or will result in changes to operating procedures and in capital expenditures. Compliance with applicable environmental laws, regulations and permits will continue to have an impact on our operations, results of operations and capital requirements. We believe that our current operations are in substantial compliance with existing environmental laws, regulations and permits.
Our operations and many of the products we manufacture are subject to certain specific requirements of the Federal Clean Air Act (“CAA”) and related state and local regulations. The CAA contains provisions that require capital expenditures for the installation of certain air pollution control devices at our refineries. Subsequent rule making authorized by the CAA or similar laws or new agency interpretations of existing rules, may necessitate additional expenditures in future years.
Under the CAA, the EPA has the authority to modify the formulation of the refined transportation fuel products we manufacture in order to limit the emissions associated with their final use. In June 2004, the EPA issued new regulations limiting emissions from diesel fuel powered engines used in non-road activities such as mining, construction, agriculture, railroad and marine and simultaneously limiting the sulfur content of diesel fuel used in these engines to facilitate compliance with the new emission standards. Our Navajo and Woods Cross Refineries as well as our Tulsa Refinery east facility meetproduce non-road and highway diesel that meets the ultimate 15 PPM standard for both our non-road and highway diesel.sulfur standard. Currently, however, our Tulsa Refinery west facility does not meet these regulations.produce diesel that meets that standard. Under our Tulsa Refinery integration project, we will be expanding our Tulsa Refinery east facility’s diesel hydrotreater unit, enabling it to process all diesel fuel produced at the Tulsa Refinery.
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Additionally, as of January 1, 2011 we will beare required to meet another EPA regulation limiting the average concentration of sulfur content in gasoline to 30 PPM by January 1, 2011. Our Tulsa Refinery east facility meets this new LSG standard. Products produced at our Tulsa Refinery west facility will also meet this standard, once the interconnecting lines that connect the two Tulsa facilities are in service. Additionally, we are proceeding with capital projects at our Navajo and Woods Cross Refineries in orderPPM. We plan to meet this requirement.requirement using previously internally generated sulfur credits.
WeAlso as of January 1, 2011, we are currently making plansrequired to comply with the EPA’s new MSAT2 regulations on gasoline that will impose further reductions in the benzene content of our produced gasoline beginning January 1, 2011.gasoline. We plan to purchase benzene credits to meet these requirements. Our planned capital projects will reduce the amount of benzene credits that we need to purchase and we could implement additional benzene reduction projects to completely eliminate our benzene credit purchase requirements if we can justify such a project from a cost benefit standpoint. In addition, , the renewable fuel standards will mandate the blending of prescribed percentages of renewable fuels (e.g., ethanol and biofuels) into our produced gasoline.gasoline and diesel. These new requirements, other requirements of the CAA, and other presently existing or future environmental regulations may cause us to make substantial capital expenditures as well as the purchase of credits at significant cost, to enable our refineries to produce products that meet applicable requirements.
Our operations are also subject to the Federal Clean Water Act (“CWA”), the Federal Safe Drinking Water Act (“SDWA”) and comparable state and local requirements. The CWA, the SDWA and analogous laws prohibit any discharge into surface waters, ground waters, injection wells and publicly-owned treatment works except in strict conformance with permits, such as pre-treatment permits and National Pollutant Discharge Elimination System (“NPDES”) permits, issued by federal, state and local governmental agencies. NPDES permits and analogous water discharge permits are valid for a maximum of five years and must be renewed.
We generate wastes that may be subject to the Resource Conservation and Recovery Act (“RCRA”) and comparable state and local requirements. The EPA and various state agencies have limited the approved methods of disposal for certain hazardous and non-hazardous wastes.
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as “Superfund,” imposes liability, without regard to fault or the legality of the original conduct, on certain classes of
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persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Analogous state laws impose similar responsibilities and liabilities on responsible parties. In the course of our historical operations, as well as in our current normal operations, we have generated waste, some of which falls within the statutory definition of a “hazardous substance” and some of which may have been disposed of at sites that may require cleanup under Superfund.
As is the case with all companies engaged in industries similar to ours, we face potential exposure to future claims and lawsuits involving environmental matters. These matters include soil and water contamination, air pollution, personal injury and property damage allegedly caused by substances which we manufactured, handled, used, released or disposed of.
We currently have environmental remediation projects that relate to recovery, treatment and monitoring activities resulting from past releases of refined product and crude oil into the environment. As of December 31, 20092010 we had an accrual of $30.4$26.2 million related to such environmental liabilities of which $24.2$20.4 million was classified as long-term.
We are and have been the subject of various state, federal and private proceedings relating to environmental regulations, conditions and inquiries, including those discussed above. Current and future environmental regulations are expected to require additional expenditures, including expenditures for investigation and remediation, which may be significant, at our refineries and at pipeline transportation facilities. To the extent that future expenditures for these purposes are material and can be reasonably determined, these costs are disclosed and accrued.
Our operations are also subject to various laws and regulations relating to occupational health and safety. We maintain safety, training and maintenance programs as part of our ongoing efforts to ensure compliance with applicable laws and regulations. Compliance with applicable health and safety laws and regulations has required and continues to require substantial expenditures.
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We cannot predict what additional health and environmental legislation or regulations will be enacted or become effective in the future or how existing or future laws or regulations will be administered or interpreted with respect to our operations. Compliance with more stringent laws or regulations or adverse changes in the interpretation of existing regulations by government agencies could have an adverse effect on the financial position and the results of our operations and could require substantial expenditures for the installation and operation of systems and equipment that we do not currently possess.
Insurance
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 1A. Risk Factors
Investing in us involves a degree of risk, including the risks described below. Our operating results have been, and will continue to be, affected by a wide variety of risk factors, many of which are beyond our control, that could have adverse effects on profitability during any particular period. You should carefully consider the following risk factors together with all of the other information included in this Annual Report on Form 10-K, including the financial statements and related notes, when deciding to invest in us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also materially and adversely affect our business operations. If any of the following risks were to actually occur, our business, financial condition or results of operations could be materially and adversely affected.
The prices of crude oil and refined products materially affect our profitability, and are dependent upon many factors that are beyond our control, including general market demand and economic conditions, seasonal and weather-related factors and governmental regulations and policies.
Among these factors is the demand for crude oil and refined products, which is largely driven by the conditions of local and worldwide economies as well as by weather patterns and the taxation of these products relative to other energy sources. Governmental regulations and policies, particularly in the areas of taxation, energy and the environment, also have a significant impact on our activities. Operating results can be affected by these industry factors, product and crude pipeline capacities, changes in transportation costs, accidents or interruptions in transportation, competition in the particular geographic areas that we serve, and factors that are specific to us, such as the success of particular marketing programs and the efficiency of our refinery operations. The demand for crude oil and refined products can also be reduced due to a local or national recession or other adverse economic condition that results in lower spending by businesses and consumers on gasoline and diesel fuel, higher gasoline prices due to higher crude oil prices, a shift by consumers to more fuel-efficient vehicles or alternative fuel vehicles (such as ethanol or wider adoption of gas/electric hybrid vehicles), or an increase in vehicle fuel economy, whether as a result of technological advances by manufacturers, legislation mandating or encouraging higher fuel economy or the use of alternative fuel.
We do not produce crude oil and must purchase all our crude oil, the price of which fluctuates based upon worldwide and local market conditions. Our profitability depends largely on the spread between market prices for refined petroleum products and crude oil prices. This margin is continually changing and may fluctuate significantly from time to time. Crude oil and refined products are commodities whose price levels are determined by market forces beyond our control. Additionally, due to the seasonality of refined products markets and refinery maintenance schedules, results of operations for any particular quarter of a fiscal year are not necessarily indicative of results for the full year. In general, prices for refined products are influenced by the price of crude oil. Although an increase or decrease in the price for crude oil may result in a similar increase or decrease in prices
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for refined products, there may be a time lag in the realization of the similar increase or decrease in prices for refined products. The effect of changes in crude oil prices on operating results therefore depends in part on how quickly refined product prices adjust to reflect these changes. A substantial or prolonged increase in crude oil prices without a corresponding increase in refined product prices, a substantial or prolonged decrease in refined product prices without a corresponding decrease in crude oil prices, or a substantial or prolonged decrease in demand for refined products could have a significant negative effect on our earnings and cash flows. Also, crude oil supply contracts are generally short-term contracts with market-responsive pricing provisions. We purchase our refinery feedstocks weeks before manufacturing and selling the refined products. Price level changes during the period between purchasing feedstocks and selling the manufactured refined products from these feedstocks could have a significant effect on our financial results.
We may not be able to successfully execute our business strategies to grow our business. Further, if we are unable to complete capital projects at their expected costs or in a timely manner, or if the market conditions assumed in our project economics deteriorate, our financial condition, results of operations, or cash flows could be materially and adversely affected.
One of the ways we may grow our business is through the construction of new refinery processing units (or the purchase and refurbishment of used units from another refinery) and the expansion of existing ones. Projects are generally initiated to increase the yields of higher-value products, increase the amount of lower cost crude oils that
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can be processed, increase refinery production capacity, meet new governmental requirements, or maintain the operations of our existing assets. Additionally, our growth strategy includes projects that permit access to new and/or more profitable markets such as our UNEV Pipeline joint venture, a 12-inch refined products pipeline running from Salt Lake City, Utah to Las Vegas, Nevada that is currently under construction and in which our subsidiary owns a 75% interest. The construction process involves numerous regulatory, environmental, political, and legal uncertainties, most of which are not fully within our control, including:
| • | | denial or delay in issuing requisite regulatory approvals and/or permits; |
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| • | | compliance with or liability under environmental regulations; unplanned increases in the cost of construction materials or labor; |
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| • | | unplanned increases in the cost of construction materials or labor; |
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| • | | disruptions in transportation of modular components and/or construction materials; |
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| • | | severe adverse weather conditions, natural disasters, or other events (such as equipment malfunctions explosions, fires, spills) affecting our facilities, or those of vendors and suppliers; |
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| • | | shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages; |
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| • | | market-related increases in a project’s debt or equity financing costs; and/or |
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| • | | nonperformance or force majeure by, or disputes with, vendors, suppliers, contractors, or sub-contractors involved with a project. |
If we are unable to complete capital projects at their expected costs or delay in issuing requisite regulatory approvals and/a timely manner our financial condition, results of operations, or permits; compliance with or liability under environmental regulations; unplanned increases in the cost of construction materials or labor; disruptions in transportation of modular components and/or construction materials; severe adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendorscash flows could be materially and suppliers; shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages; and/or nonperformance or force majeure by, or disputes with, vendors, suppliers, contractors or sub-contractors involved with a project. These projects may not be completed on schedule or at all or at the budgeted cost.adversely affected. Delays in making required changes or upgrades to our facilities could subject us to fines or penalties as well as affect our ability to supply certain products we make. In addition, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new refinery processing unit, the construction will occur over an extended period of time and we will not receive any material increases in revenues until after completion of the project. Moreover, we may construct facilities to capture anticipated future growth in demand for refined products in a region in which such growth does not materialize. As a result, new capital investments may not achieve our expected investment return, which could adversely affect our results of operations and financial condition.
Our forecasted internal rates of return are also based upon our projections of future market fundamentals which are not within our control, including changes in general economic conditions, available alternative supply and customer demand.
In addition, a component of our growth strategy is to selectively acquire complementary assets for our refining operations in order to increase earnings and cash flow. Our ability to do so will be dependent upon a number of factors, including our ability to identify attractive acquisition candidates, consummate acquisitions on favorable terms, successfully integrate acquired assets and obtain financing to fund acquisitions and to support our growth, and other factors beyond our control. Risks associated with acquisitions include those relating to:
| • | | diversion of management time and attention from our existing business; |
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| • | | challenges in managing the increased scope, geographic diversity and complexity of operations; |
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| • | | difficulties in integrating the financial, technological and management standards, processes, procedures and controls of an acquired business with those of our existing operations; |
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| • | | liability for known or unknown environmental conditions or other contingent liabilities not covered by indemnification or insurance; |
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| • | | greater than anticipated expenditures required for compliance with environmental or other regulatory standards or for investments to improve operating results; |
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| • | | difficulties in achieving anticipated operational improvements; |
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| • | | incurrence of additional indebtedness to finance acquisitions or capital expenditures relating to acquired assets; and |
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| • | | issuance of additional equity, which could result in further dilution of the ownership interest of existing stockholders. |
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We may not be successful in acquiring additional assets, and any acquisitions that we do consummate may not produce the anticipated benefits or may have adverse effects on our business and operating results.
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Our leverage may limit our ability to borrow additional funds, comply with the terms of our indebtedness or capitalize on business opportunities.
As of December 31, 2010, the principal amount of our total consolidated outstanding debt was $833 million, including $494 million of HEP debt.
Our leverage could have important consequences. We require substantial cash flow to meet our payment obligations with respect to our indebtedness. Our ability to make scheduled payments, to refinance our obligations with respect to our indebtedness or our ability to obtain additional financing in the future will depend on our financial and operating performance, which, in turn, is subject to prevailing economic conditions and to financial, business and other factors. We believe that we will have sufficient cash flow from operations and available borrowings under our Credit Agreement to service our indebtedness. However, a significant downturn in our business or other development adversely affecting our cash flow could materially impair our ability to service our indebtedness. If our cash flow and capital resources are insufficient to fund our debt service obligations, we may be forced to refinance all or a portion of our debt or sell assets. We cannot assure you that we would be able to refinance our existing indebtedness at maturity or otherwise or sell assets on terms that are commercially reasonable.
We may not be able to obtain funding on acceptable terms or at all because of volatility and uncertainty in the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.
Although the domestic capital markets have shown signs of improvement in recent months, global financial markets and economic conditions have been, and continue to be, disrupted and volatile due to a variety of factors, including uncertainty in the financial services sector, low consumer confidence, continued high unemployment, geopolitical issues and the current weak economic conditions. In addition, the fixed-income markets have experienced periods of extreme volatility that have negatively impacted market liquidity conditions. As a result, the cost of raising money in the debt and equity capital markets has increased substantially at times while the availability of funds from those markets diminished significantly. In particular, as a result of concerns about the stability of financial markets generally and the solvency of lending counterparties specifically, the cost of obtaining money from the credit markets may increase as many lenders and institutional investors increase interest rates, enact tighter lending standards, refuse to refinance existing debt on similar terms or at all and reduce, or in some cases cease, to provide funding to borrowers. In addition, lending counterparties under existing revolving credit facilities and other debt instruments may be unwilling or unable to meet their funding obligations. Due to these factors, we cannot be certain that new debt or equity financing will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due. Moreover, without adequate funding, we may be unable to execute our growth strategy, complete future acquisitions, take advantage of other business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations.
We may incur significant costs to comply with new or changing environmental, energy, health and safety laws and regulations, and face potential exposure for environmental matters.
Refinery and pipeline operations are subject to federal, state and local laws regulating, among other things, the generation, storage, handling, use and transportation of petroleum and hazardous substances, the emission and discharge of materials into the environment, waste management, and characteristics and composition of gasoline and diesel fuels, and other matters otherwise relating to the protection of the environment. Permits are required under these laws for the operation of our refineries, pipelines and related operations, and these permits are subject to revocation, modification and renewal or may require operational changes, which may involve significant costs. Furthermore, a violation of permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions, and/or refinery shutdowns. In addition, major modifications of our operations due to changes in the law could require changes to our existing permits or expensive upgrades to our existing pollution control equipment, which could have a material adverse effect on our business, financial condition, or results of operations. Over the years, there have been and continue to be ongoing communications, including notices of violations, and discussions about environmental matters between us and federal and state authorities, some of which have resulted or will result in changes to operating procedures and in capital expenditures. Compliance with applicable environmental laws, regulations and permits will continue to have an impact on our operations, results of operations and capital requirements.
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As is the case with all companies engaged in industries similar to ours, we face potential exposure to future claims and lawsuits involving environmental matters. The matters include soil and water contamination, air pollution, personal injury and property damage allegedly caused by substances which we manufactured, handled, used, released or disposed.
We are and have been the subject of various state, federal and private proceedings relating to environmental regulations, conditions and inquiries. Current and future environmental regulations are expected to require additional expenditures, including expenditures for investigation and remediation, which may be significant, at our facilities. To the extent that future expenditures for these purposes are material and can be reasonably determined, these costs are disclosed and accrued.
Our operations are also subject to various laws and regulations relating to occupational health and safety. We maintain safety, training and maintenance programs as part of our ongoing efforts to ensure compliance with applicable laws and regulations. Compliance with applicable health and safety laws and regulations has required and continues to require substantial expenditures.
We cannot predict what additional health and environmental legislation or regulations will be enacted or become effective in the future or how existing or future laws or regulations will be administered or interpreted with respect to our operations. However, new environmental laws and regulations, including new regulations relating to alternative energy sources and the risk of global climate change, new interpretations of existing laws and regulations, increased governmental enforcement or other developments could require us to make additional unforeseen expenditures. The EPA has begun regulating certain emissions of greenhouse gases, or “GHGs,” (including carbon dioxide, methane and nitrous oxides) from large stationary sources like refineries under the authority of the CAA, and it is possible that Congress could pass federal legislation that creates a comprehensive GHG regulatory program, either directly or indirectly, such as via a federal renewal energy standard. Also, new federal or state legislation or regulatory programs that restrict emissions of GHGs in areas where we conduct business could adversely affect our operations and demand for our products.
The costs of environmental and safety regulations are already significant and compliance with more stringent laws or regulations or adverse changes in the interpretation of existing regulations by government agencies could have an adverse effect on the financial position and the results of our operations and could require substantial expenditures for the installation and operation of systems and equipment that we do not currently possess.
From time to time, new federal energy policy legislation is enacted by the U.S. Congress. For example, in December 2007, the U.S. Congress passed the Energy Independence and Security Act, which, among other provisions, mandates annually increasing levels for the use of renewable fuels such as ethanol, commencing in 2008 and escalating for 15 years, as well as increasing energy efficiency goals, including higher fuel economy standards for motor vehicles, among other steps. These statutory mandates may have the impact over time of offsetting projected increases in the demand for refined petroleum products in certain markets, particularly gasoline. In the near term, the new renewable fuel standard presents ethanol production and logistics challenges for both the ethanol and refining industries and may require additional capital expenditures or expenses by us to accommodate increased ethanol use. Other legislative changes may similarly alter the expected demand and supply projections for refined petroleum products in ways that cannot be predicted.
For additional information on regulations and related liabilities or potential liabilities affecting our business, see “Regulation” under Items 1 and 2, “Business and Properties,” and Item 3, “Legal Proceedings.”
The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the refined products we produce.
In December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the federal CAA. The EPA recently adopted two sets of rules regulating GHG emissions under the CAA, one of which requires
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a reduction in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources, effective January 2, 2011. The EPA’s rules relating to emissions of GHGs from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent EPA from implementing or requiring state environmental agencies to implement the rules. The EPA has also adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, including petroleum refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010.
In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. These cap and trade programs generally work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and on an annual basis surrender emission allowances. The number of allowances available for purchase is reduced over time in an effort to achieve the overall GHG emission reduction goal.
The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the refined products that we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations.
In addition, some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such events were to occur, they could have an adverse effect on our financial condition and results of operations.
To successfully operate our petroleum refining facilities, we are required to expend significant amounts for capital outlays and operating expenditures.
The refining business is characterized by high fixed costs resulting from the significant capital outlays associated with refineries, terminals, pipelines and related facilities. We are dependent on the production and sale of quantities of refined products at refined product margins sufficient to cover operating costs, including any increases in costs resulting from future inflationary pressures or market conditions and increases in costs of fuel and power necessary in operating our facilities. Furthermore, future regulatory requirements or competitive pressures could result in additional capital expenditures, which may not produce a return on investment. Such capital expenditures may require significant financial resources that may be contingent on our access to capital markets and commercial bank loans. Additionally, other matters, such as regulatory requirements or legal actions, may restrict our access to funds for capital expenditures.
Our refineries consist of many processing units, a number of which have been in operation for many years. One or more of the units may require unscheduled downtime for unanticipated maintenance or repairs that are more frequent than our scheduled turnaround for such units. Scheduled and unscheduled maintenance could reduce our revenues during the period of time that the units are not operating. We have taken significant measures to expand and upgrade units in our refineries by installing new equipment and redesigning older equipment to improve refinery capacity. The installation and redesign of key equipment at our refineries involves significant uncertainties, including the following: our upgraded equipment may not perform at expected throughput levels; the yield and product quality of new equipment may differ from design and/or specifications and redesign or modification of the equipment may be required to correct equipment that does not perform as expected, which could require facility shutdowns until the equipment has been redesigned or modified. Any of these risks associated with new equipment, redesigned older equipment, or repaired equipment could lead to lower revenues or higher costs or otherwise have a negative impact on our future results of operations and financial condition.
In addition, we expect to execute turnarounds at our refineries, every three to five years, which involve numerous risks and uncertainties. These risks include delays and incurrence of additional and unforeseen costs. The turnarounds allow us to perform
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maintenance, upgrades, overhaul and repair of process equipment and materials, during which time all or a portion of the refinery will be under scheduled downtime. The Woods Cross refinery turnaround occurred in August/September, 2008, and the Navajo refinery turnaround occurred in January/February, 2009.
We may incur significant costs to comply with new or changing environmental, energy, health and safety laws and regulations, and face potential exposure for environmental matters.
Refinery and pipelineOur operations are subject to federal, stateoperational hazards and local laws regulating, among other things, the generation, storage, handling, use and transportation of petroleum and hazardous substances, the emission and discharge of materials into the environment, waste management, and characteristics and composition of gasoline and diesel fuels, and other matters otherwise relating to the protection of the environment. Permits are required under these lawsunforeseen interruptions for the operation of our refineries, pipelines and relatedwhich we may not be adequately insured.
Our operations and these permits are subject to revocation, modificationoperational hazards and renewal or may require operational changes, which may involve significant costs. Furthermore, a violation of permit conditions orunforeseen interruptions such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, power failures, mechanical failures and other legal or regulatory requirements couldevents beyond our control. These events might result in substantial fines, criminal sanctions, permit revocations, injunctions, and/a loss of equipment or refinery shutdowns. In addition, major modificationslife or destruction of property, injury, or extensive property damage, as well as a curtailment or an interruption in our operations and may affect our ability to meet marketing commitments. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies could increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position. If any refinery were to experience an interruption in operations, dueearnings from the refinery could be materially adversely affected (to the extent not recoverable through insurance) because of lost production and repair costs.
We maintain significant insurance coverage, but it does not cover all potential losses, costs or liabilities, and our business interruption insurance coverage generally does not apply unless a business interruption exceeds 45 days. We could suffer losses for uninsurable or uninsured risks or in amounts in excess of our existing insurance coverage. Our ability to changesobtain and maintain adequate insurance may be affected by conditions in the law could require changes to our existing permits or expensive upgrades to our existing pollution control equipment,insurance market over which we have no control. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition orand results of operations. Over
The energy industry is highly capital intensive, and the years, there have been and continueentire or partial loss of individual facilities can result in significant costs to be ongoing communications, including notices of violations, and discussions about environmental matters betweenboth industry companies, such as us, and federal and state authorities, some of whichtheir insurance carriers. In recent years, several large energy industry claims have resulted or will result in changes to operating procedures and in capital expenditures. Compliance with applicable environmental laws, regulations and permits will continue to have an impact on our operations, results of operations and capital requirements.
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As is the case with all companies engaged in industries similar to ours, we face potential exposure to future claims and lawsuits involving environmental matters. The matters include soil and water contamination, air pollution, personal injury and property damage allegedly caused by substances which we manufactured, handled, used, released or disposed.
We are and have been the subject of various state, federal and private proceedings relating to environmental regulations, conditions and inquiries. Current and future environmental regulations are expected to require additional expenditures, including expenditures for investigation and remediation, which may be significant at our facilities. To the extent that future expenditures for these purposes are material and can be reasonably determined, these costs are disclosed and accrued.
Our operations are also subject to various laws and regulations relating to occupational health and safety. We maintain safety, training and maintenance programs as part of our ongoing efforts to ensure compliance with applicable laws and regulations. Compliance with applicable health and safety laws and regulations has required and continues to require substantial expenditures.
We cannot predict what additional health and environmental legislation or regulations will be enacted or become effectiveincreases in the future or how existing or future laws or regulations will be administered or interpreted with respect to our operations. However, new environmental lawslevel of premium costs and regulations, including new regulations relating to alternative energy sources and the risk of global climate change, new interpretations of existing laws and regulations, increased governmental enforcement or other developments could require us to make additional unforeseen expenditures. There is growing consensus that some form of regulation will be forthcoming at the federal leveldeductible periods for participants in the United States with respectenergy industry. As a result of large energy industry claims, insurance companies that have historically participated in underwriting energy-related facilities may discontinue that practice, or demand significantly higher premiums or deductible periods to emissions of greenhouse gases, or “GHGs,” (including carbon dioxide, methane and nitrous oxides). Also, new federal or state legislation or regulatory programs that restrict emissions of GHGs in areas where we conduct business could adversely affect our operations and demand for our products.
The costs of environmental and safety regulations are alreadycover these facilities. If significant and compliance with more stringent laws or regulations or adverse changes in the interpretationnumber or financial solvency of existing regulations by government agenciesinsurance underwriters for the energy industry occur, or if other adverse conditions over which we have no control prevail in the insurance market, we may be unable to obtain and maintain adequate insurance at reasonable cost. In addition, we cannot assure you that our insurers will renew our insurance coverage on acceptable terms, if at all, or that we will be able to arrange for adequate alternative coverage in the event of non-renewal. Further, our underwriters could have an adverse effect on the financial position and the resultscredit issues that affect their ability to pay claims. The unavailability of our operations and could require substantial expenditures for the installation and operation of systems and equipment thatfull insurance coverage to cover events in which we do not currently possess.
From time to time, new federal energy policy legislation is enacted by the U.S. Congress. For example, in December 2007, the U.S. Congress passed the Energy Independence and Security Act, which, among other provisions, mandates annually increasing levels for the use of renewable fuels such as ethanol, commencing in 2008 and escalating for 15 years, as well as increasing energy efficiency goals, including higher fuel economy standards for motor vehicles, among other steps. These statutory mandates may have the impact over time of offsetting projected increases in the demand for refined petroleum products in certain markets, particularly gasoline. In the near term, the new renewable fuel standard presents ethanol production and logistics challenges for both the ethanol and refining industries and may require additional capital expenditures or expenses by us to accommodate increased ethanol use. Other legislative changes may similarly alter the expected demand and supply projections for refined petroleum products in ways that cannot be predicted.
For additional information on regulations and related liabilities or potential liabilities affecting our business, see “Regulation” under Items 1 and 2, “Business and Properties,” and Item 3, “Legal Proceedings.”
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The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the refined products we produce.
On December 15, 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal CAA. In late September 2009, the EPA had proposed two sets of regulations in anticipation of finalizing its findings that would require a reduction in emissions of GHGs from motor vehicles and that could also lead to the imposition of GHG emission limitations in CAA permits for certain stationary sources. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States beginning in 2011 for emissions occurring in 2010. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the refined products that we produce.
Also, on June 26, 2009, the U.S. House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” (“ACESA”), also known as the “Waxman-Markey cap-and-trade legislation.” The purpose of ACESA is to control and reduce emissions of GHGs in the United States. ACESA would establish an economy-wide cap on emissions of GHGs in the United States and would require an overall reduction in GHG emissions of 17% (from 2005 levels) by 2020, and by over 80% by 2050. Under ACESA, most sources of GHG emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as necessary to meet ACESA’s overall emission reduction goals. As the number of GHG emission allowances permitted by ACESA declines each year, the cost or value of allowances would be expected to escalate significantly. The net effect of ACESA would be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and gas. The U.S. Senate has begun work on its own legislation for controlling and reducing emissions of GHGs in the United States. If the Senate adopts GHG legislation that is different from ACESA, the Senate legislation would need to be reconciled with ACESA and both chambers would be required to approve identical legislation before it could become law.
It is not possible at this time to predict whether climate change legislation will be enacted, but any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs andsuffer significant losses could have an adverse effect on demand for refined products we produce.
Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if any such effects were to occur, they could have ana material adverse effect on our assetsbusiness, financial condition and operationsresults of operations.
Insufficient ethanol, biodiesel, and other advanced biofuel supplies, or disruption in ethanol supply, may disrupt our ability to market ethanol blended fuels.meet RFS2 regulations mandated by the federal government or required in the fuels markets that Holly serves.
If we are unable to obtain or maintain sufficient quantities of ethanol to support our blending needs, our sale of ethanol blended gasoline (required in several of our markets) could be interrupted or suspended which could result in lower profits. Likewise, if we are unable to purchase renewable identification numbers (“RINs”), or if our supply of RINs is such that we have to pay a significantly higher price for RINs to meet our mandated blending volumes of biofuels per the RFS2 regulation, our profits would be significantly lower. If we are unable to pass the costs of compliance with RFS2 on to our customers, our profits would be significantly lower.
Competition in the refining and marketing industry is intense, and an increase in competition in the markets in which we sell our products could adversely affect our earnings and profitability.
We compete with a broad range of refining and marketing companies, including certain multinational oil companies. Because of their geographic diversity, larger and more complex refineries, integrated operations and greater
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resources, some of our competitors may be better able to withstand volatile market conditions, to obtain crude oil in times of shortage and to bear the economic risks inherent in all areas of the refining industry.
We are not engaged in petroleum exploration and production activities and do not produce any of the crude oil feedstocks used at our refineries. We do not have a retail business and therefore are dependent upon others for outlets for our refined products. Certain of our competitors, however, obtain a portion of their feedstocks from company-owned production and have retail outlets. Competitors that have their own production or extensive retail outlets, with brand-name recognition, are at times able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages. In addition, we compete with other industries that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial and individual consumers. If we are unable to compete effectively with these competitors, both within and outside of our industry, there could be material adverse effects on our business, financial condition and results of operations.
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In recent years there have been several refining and marketing consolidations or acquisitions between entities competing in our geographic market. These transactions could increase the future competitive pressures on us.
Portions of our operations in the areas we operate may be impacted by competitors’ plans for expansion projects and refinery improvements that could increase the production of refined products in our areas of operation and significantly affect our profitability.
In addition, we compete with other industries that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial and individual consumers. The more successful these alternatives become as a result of governmental regulations, technological advances, consumer demand, improved pricing or otherwise, the greater the impact on pricing and demand for our products and our profitability. There are presently significant governmental and consumer pressures to increase the use of alternative fuels in the United States.
We may be unsuccessful in integrating the operations of the assets we have recently acquired or of any future acquisitions with our operations, and in realizing all or any part of the anticipated benefits of any such acquisitions.
From time to time, we evaluate and acquire assets and businesses that we believe complement our existing assets and businesses. For example, in 2009, we completed the acquisition of two refineries in Tulsa, Oklahoma. We will face certain challenges as we continue to integrate the operations of the Tulsa facilities, purchased in 2009, into our business. In particular, the acquisition of the Tulsa facilities has significantly expanded our geographic scope, the types of business in which we are engaged, the number of our employees and the number of refineries we operate, thereby presenting us with significant challenges as we work to manage the substantial increases in scale resulting from the acquisition. We must integrate a large number of systems, both operational and administrative. Delays in this process could have a material adverse effect on our revenues, expenses, operating results and financial condition. In addition, events outside of our control, including changes in state and federal regulations and laws and/or delays or failure to obtain environmental permits needed for integrating projects, could adversely affect our ability to realize the anticipated benefits from the acquisition of the Tulsa facilities. We can give no assurance that our acquisition of the Tulsa facilities will perform in accordance with our expectations. We can give no assurance that our expectations with regards to integration and synergies will materialize. Our failure to successfully integrate and operate the Tulsa facilities and to realize the anticipated benefits of the acquisition, could adversely affect our operating, performing and financial results.
Acquisitions may require substantial capital or the incurrence of substantial indebtedness. Our capitalization and results of operations may change significantly as a result of the acquisitions we recently completed or as a result of future acquisitions. Acquisitions and business expansions involve numerous risks, including difficulties in the assimilation of the assets and operations of the acquired businesses, inefficiencies and difficulties that arise because of unfamiliarity with new assets and the businesses associated with them and new geographic areas and the diversion of management’s attention from other business concerns. Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition, including the assets and businesses we acquired in 2009. Also, following an acquisition, we may discover previously unknown liabilities associated with the acquired business or assets for which we have no recourse under applicable indemnification provisions.
We may not be ableOur proposed “merger of equals” business combination with Frontier is subject to retain existing customers or acquire new customers.
The renewal or replacement of existing contracts with our customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors outsideconditions beyond our control. Failure to complete the Merger within the expected timeframe or at all could adversely affect our stock price and our future business and financial results.
Our proposed “merger of equals” business combination with Frontier is subject to a number of conditions beyond our control that may prevent, delay or otherwise materially adversely affect the Merger’s completion, including competition from other refinersapproval of our stockholders and of Frontier’s stockholders and the demand for refined productsexpiration or termination of applicable waiting periods under U.S. antitrust laws and various approvals or consents that must be obtained from regulatory authorities or third parties. We cannot predict whether and when these conditions will be satisfied. Any delay in completing the markets that we serve. LossMerger could cause the combined company not to realize some or all of or reduction in amounts purchased by our major customers could have an adverse effect on usthe synergies expected to the extent that, because of market limitations or transportation constraints, we are not able to correspondingly increase sales to other purchasers.be achieved. We
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will also incur substantial transaction costs whether or not the merger is completed. Any failure to complete the merger could have a material adverse effect on our stock price and our future business and financial results.
The anticipated benefits of our Merger may not be realized fully or at all or may take longer to realize than expected.
The Merger involves the integration of two companies that have previously operated independently. After the Merger, the two companies will devote significant management attention and resources to integrating the two companies. Delays in this process could adversely affect the combined company’s business, financial results, financial condition and stock price. Even if we are able to integrate our business operations successfully, there can be no assurance that this integration will result in the realization of the full benefits of synergies, cost savings, innovation and operational efficiencies that we currently expect from this integration or that these benefits will be achieved within the anticipated time frame.
The new and revamped equipment in our facilities may not perform according to expectations which may cause unexpected maintenance and downtime and could have a negative effect on our future results of operations and financial condition.
We are completing major capital investment programs at both our Navajo and Woods Cross Refineries. At the Tulsa Refinery we have various projects planned to integrate the two facilities to fully utilize their capabilities. All three refineries also have various environmental compliance related projects.
The installation of new equipment and the revamp of key existing equipment involve significant risks and uncertainties, including the following:
| • | | Equipment may not perform at expected throughput levels, |
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| • | | Actual yields or product quality may differ from design, |
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| • | | Actual operating costs may be higher than expected, |
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| • | | Equipment may need to be redesigned, revamped, or replaced for the new units to perform as expected |
A material decrease in the supply of crude oil available to our refineries could significantly reduce our production levels.
In order toTo maintain or increase production levels at our refineries, we must continually contract for new crude oil supplies from third parties. A material decrease in crude oil production from the fields that supply our refineries, as a result of depressed commodity prices, lack of drilling activity, natural production declines or otherwise, could result in a decline in the volume of crude oil available to our refineries. In addition, any prolonged disruption of a significant pipeline that is used in supplying crude oil to our refineries or the potential operation of a new, converted or expanded crude oil pipeline that transports crude oil to other markets could result in a decline in the volume of crude oil available to our refineries. Such an event could result in an overall decline in volumes of refined products processed at our refineries and therefore a corresponding reduction in our cash flow. In addition, the future growth of our operations will depend in part upon whether we can contract for additional supplies of crude oil at a greater rate than the rate of natural decline in our currently connected supplies. If we are unable to secure additional crude oil supplies of sufficient quality or crude pipeline expansion to our refineries, we will be unable to take full advantage of current and future expansion of our refineries’ production capacities.
The disruption or proration of the refined product distribution systems we utilize could negatively impact our profitability.
We utilize various common carrier or other third party pipeline systems to deliver our products to market. The key systems utilized by Navajo, Woods Cross, and Tulsa are SFPP and Plains, Chevron, and Magellan, respectively. All three refineries also utilize systems owned by HEP. If these key pipelines or their associated tanks and terminals become inoperative or decrease the capacity available to us, we may not be able to sell our product or we may be required to hold our product in inventory or supply products to our customers through an alternative pipeline or by rail or additional tanker trucks from the refinery all of which could increase our costs and result in a decline in profitability.
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The potential operation of new or expanded refined product transportation pipelines could impact the supply of refined products to our existing markets.
Other refined product transportation pipelines currently supply our existing markets or could potentially supply our existing markets in the future.
The refined product transportation pipelines that also supply the markets supplied by the Navajo Refinery include Longhorn, Kinder Morgan, Plains, HEP, and NuStar Energy. The Longhorn Pipeline is a common carrier pipeline that supplies the El Paso market with refined products from refineries as distant as the Texas Gulf Coast. The Longhorn Pipeline is a converted crude oil pipeline with an approximate capacity of 72,000 BPD of refined products. Magellan purchased the Longhorn Pipeline out of bankruptcy in 2009. Flying J formerly owned the Longhorn Pipeline prior to its bankruptcy in 2008. In addition to supplying Arizona markets from El Paso, Kinder Morgan also supplies Arizona markets from the West Coast. The Plains pipeline currently supplies New Mexico markets from El Paso. In addition, NuStar Energy LP and HEP own pipelines into the El Paso and New Mexico markets.
The refined product transportation pipelines that also supply the markets supplied by the Woods Cross Refinery include Chevron, Pioneer, and Yellowstone Pipelines. The Chevron system transports products from Salt Lake City to Idaho and eastern Washington. The Pioneer Pipeline transports products from Wyoming and Montana refineries into Salt Lake City. The Yellowstone Pipeline transports products from Montana refineries into eastern Washington.
The refined product transportation pipelines that also supply the markets supplied by the Tulsa Refinery include Magellan, Explorer, and Kaneb Pipelines. The Explorer Pipeline transports refined products from Gulf Coast refineries to Tulsa where it interconnects with Magellan prior to proceeding to the Chicago area. The Kaneb Pipeline transports refined products from northern Texas, Oklahoma, and Kansas refineries to markets in Kansas, Nebraska, Iowa, North Dakota, and South Dakota. These markets are in close proximity to markets supplied by the Magellan system.
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The expansion of any of these pipelines, the conversion of existing pipelines into refined products, or the construction of a new pipeline into our markets could negatively impact the supply of refined products in our markets and our profitability.
We depend upon HEP for a substantial portion of the crude supply and distribution network that serve our refineries and we own a significant equity interest in HEP.
We currently own a 34%34% interest in HEP, including the 2% general partner interest. HEP operates a system of crude oil and petroleum product pipelines, distribution terminals and refinery tankage in Texas, New Mexico, Utah, Arizona, Idaho, Washington and Oklahoma. HEP generates revenues by charging tariffs for transporting petroleum products and crude oil through its pipelines, by leasing certain pipeline capacity to Alon, by charging fees for terminalling refined products and other hydrocarbons and storing and providing other services at its terminals. HEP serves our refineries in New Mexico, Utah and Oklahoma under several long-term pipeline and terminal, tankage and throughput agreements expiring in 2019 through 2024.2025. Furthermore, our financial statements include the consolidated results of HEP. HEP is subject to its own operating and regulatory risks, including, but not limited to:
| | • | | its reliance on its significant customers, including us, |
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| | • | | competition from other pipelines, |
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| | • | | environmental regulations affecting pipeline operations, |
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| | • | | operational hazards and risks, |
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| | • | | pipeline tariff regulations affecting the rates HEP can charge, |
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| | • | | limitations on additional borrowings and other restrictions due to HEP’s debt covenants, and |
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| | • | | other financial, operational and legal risks. |
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The occurrence of any of these risks could directly or indirectly affect HEP’s as well as our financial condition, results of operations and cash flows as HEP is a consolidated subsidiary.VIE. Additionally, these risks could affect HEP’s ability to continue operations which could affect their ability to serve our supply and distribution network needs.
For additional information about HEP, see “Holly Energy Partners, L.P.” under Items 1 and 2, “Business and Properties.”
Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.
Our operations are subject to operational hazards and unforeseen interruptions such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, power failures, mechanical failures and other events beyond our control. These events might result in a loss of equipment or life, injury, or extensive property damage, as well as an interruption in our operations and may affect our ability to meet marketing commitments. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies could increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position. If any refinery were to experience an interruption in operations, earnings from the refinery could be materially adversely affected (to the extent not recoverable through insurance) because of lost production and repair costs.
We maintain significant insurance coverage, but it does not cover all potential losses, costs or liabilities, and our business interruption insurance coverage generally does not apply unless a business interruption exceeds 45 days. We could suffer losses for uninsurable or uninsured risks or in amounts in excess of our existing insurance coverage. Our ability to obtain and maintain adequate insurance may be affected by conditions in the insurance market over which we have no control. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
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The energy industry is highly capital intensive, and the entire or partial loss of individual facilities can result in significant costs to both industry companies, such as us, and their insurance carriers. In recent years, several large energy industry claims have resulted in significant increases in the level of premium costs and deductible periods for participants in the energy industry. As a result of large energy industry claims, insurance companies that have historically participated in underwriting energy-related facilities may discontinue that practice, or demand significantly higher premiums or deductible periods to cover these facilities. If significant changes in the number or financial solvency of insurance underwriters for the energy industry occur, or if other adverse conditions over which we have no control prevail in the insurance market, we may be unable to obtain and maintain adequate insurance at reasonable cost. In addition, we cannot assure you that our insurers will renew our insurance coverage on acceptable terms, if at all, or that we will be able to arrange for adequate alternative coverage in the event of non-renewal. Further, our underwriters could have credit issues that affect their ability to pay claims. The unavailability of full insurance coverage to cover events in which we suffer significant losses could have a material adverse effect on our business, financial condition and results of operations.
If we lose any of our key personnel, our ability to manage our business and continue our growth could be negatively impacted.
Our future performance depends to a significant degree upon the continued contributions of our senior management team and key technical personnel. We do not currently maintain key man life insurance, non-compete agreements, or employment agreements with respect to any member of our senior management team. The loss or unavailability to us of any member of our senior management team or a key technical employee could significantly harm us. We face competition for these professionals from our competitors, our customers and other companies operating in our industry. To the extent that the services of members of our senior management team and key technical personnel would be unavailable to us for any reason, we may be required to hire other personnel to manage and operate our company. We may not be able to locate or employ such qualified personnel on acceptable terms, or at all.
Furthermore, our operations require skilled and experienced laborers with proficiency in multiple tasks. A shortage of trained workers due to retirements or otherwise could have an adverse impact on our labor productivity and costs and our ability to expand production in the event there is an increase in the demand for our products and services, which could adversely affect our operations.
As of December 31, 2009, approximately 21% of our employees were represented by labor unions under collective bargaining agreements with various expiration dates. Effective February 1, 2009, a new agreement was reached with the United Steelworkers which applies to approximately 7% of our employees, which agreement will now expire on January 31, 2012. As of December 31, 2009, approximately 14% of our employees were represented by labor unions under a collective bargaining agreement that expires in 2010. We may not be able to renegotiate our collective bargaining agreements when they expire on satisfactory terms or at all. A failure to do so may increase our costs. In addition, our existing labor agreements may not prevent a strike or work stoppage at any of our facilities in the future, and any work stoppage could negatively affect our results of operations and financial condition.
We are exposed to the credit risks, and certain other risks, of our key customers.customers and vendors.
We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. We derive a significant portion of our revenues from contracts with key customers.
If any of our key customers default on their obligations to us, our financial results could be adversely affected. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks. In addition, nonperformance by vendors who have committed to provide us with products or services could result in higher costs or interfere with our ability to successfully conduct our business.
Any substantial increase in the nonpayment and/or nonperformance by our customers or vendors could have a material adverse effect on our results of operations and cash flows.
Terrorist attacks, and the threat of terrorist attacks or domestic vandalism, have resulted in increased costs to our business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our results of operations.
The long-term impacts of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the threat of future terrorist attacks on the energy transportation industry in general, and on us in particular, are not known at this time. Increased security measures taken by us as a precaution against possible terrorist attacks or vandalism have resulted in increased costs to our business. Future terrorist attacks could lead to even stronger, more costly initiatives or regulatory requirements. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for refined products, and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. In addition, disruption or significant increases in energy prices could result in government-imposed price controls. Any one of, or a combination of, these occurrences could have a material adverse effect on our business, financial condition and results of operations.
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Changes in the insurance markets attributable to terrorist attacks could make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital including our ability to repay or refinance debt.
We may not be able to retain existing customers or acquire new customers.
The renewal or replacement of existing contracts with our customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors outside our control, including competition from other refiners and the demand for refined products in the markets that we serve. Loss of, or reduction in amounts purchased by our major customers could have an adverse effect on us to the extent that, because of market limitations or transportation constraints, we are not able to correspondingly increase sales to other purchasers.
Our petroleum business’ financial results are seasonal and generally lower in the first and fourth quarters of the year, which may cause volatility in the price of our common stock.
Demand for gasoline products is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and road construction work. As a result, our results of operations for the first and fourth calendar quarters are generally lower than for those for the second and third quarters. The effects of seasonal demand for gasoline are partially offset by seasonality in demand for diesel fuel, which in the Southwest region of the United States is generally higher in winter months as east-west trucking traffic moves south to avoid
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winter conditions on northern routes. However, unseasonably cool weather in the summer months and/or unseasonably warm weather in the winter months in the markets in which we sell our petroleum products could have the effect of reducing demand for gasoline and diesel fuel which could result in lower prices and reduce operating margins.
We may be unable to pay future dividends.
We will only be able to pay dividends from our available cash on hand, cash from operations or borrowings under our credit agreement. The declaration of future dividends on our common stock will be at the discretion of our board of directors and will depend upon many factors, including our results of operations, financial condition, earnings, capital requirements, restrictions in our debt agreements and legal requirements. We cannot assure you that any dividends will be paid or the frequency of such payments.
Ongoing maintenance of effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act could cause us to incur additional expenditures of time and financial resources.
We regularly document and test our internal control procedures in order to satisfy the requirements of Section 404 of the Sarbanes-Oxley Act, which requires annual management assessments of the effectiveness of our internal controls over financial reporting and a report by our independent registered public accounting firm on our controls over financial reporting. If, in the future, we fail to maintain the adequacy of our internal controls and, as such standards are modified, supplemented or amended from time to time, we may not be able to ensure that we can conclude on an ongoing basis that we have effective internal controls over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act. Failure to achieve and maintain an effective internal control environment could cause us to incur substantial expenditures of management time and financial resources to identify and correct any such failure.
Additionally, the failure to comply with Section 404 or the report by us of a “material weakness” may cause investors to lose confidence in our financial statements and our stock price may be adversely affected. A “material weakness” is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. If we fail to remedy any material weakness, our financial statements may be inaccurate, we may face restricted access to the capital markets, and our stock price may decline.
Product liability claims and litigation could adversely affect our business and results of operations.
Product liability is a significant commercial risk. Substantial damage awards have been made in certain jurisdictions against manufacturers and resellers based upon claims for injuries caused by the use of or exposure to various products. There can be no assurance that product liability claims against us would not have a material adverse effect on our business or results of operations. Failure of our products to meet required specifications could result in product liability claims from our shippers and customers arising from contaminated or off-specification commingled pipelines and storage tanks and/or defective quality fuels.
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If the market value of our inventory declines to an amount less than our LIFO basis, we would record a write-down of inventory and a non-cash charge to cost of sales, which would adversely affect our earnings.
The nature of our business requires us to maintain substantial quantities of crude oil, refined petroleum product and blendstock inventories. Because crude oil and refined petroleum products are commodities, we have no control over the changing market value of these inventories. Because certain of our refining inventory is valued at the lower of cost or market value under the last-in, first-out (“LIFO”) inventory valuation methodology, we would record a write-down of inventory and a non-cash charge to cost of sales if the market value of our inventory were to decline to an amount less than our LIFO basis. A material write-down could affect our operating income and profitability.
From time to time, our cash needs may exceed our internally generated cash flow, and our business could be materially and adversely affected if we are not able to obtain the necessary funds from financing activities.
We have significant short-term cash needs to satisfy working capital requirements such as crude oil purchases which fluctuate with the pricing and sourcing of crude oil.
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We generally purchase crude oil for our refineries with cash generated from our operations. If the price of crude oil increases significantly, we may not have sufficient cash flow or borrowing capacity, and may not be able to sufficiently increase borrowing capacity, under our existing credit facilities to purchase enough crude oil to operate our refineries at desired capacity. Our failure to operate our refineries at desired capacity could have a material adverse effect on our business, financial condition and results of operations. We also have significant long-term needs for cash, including those to support our expansion and upgrade plans, as well as for regulatory compliance. If credit markets tighten, it may become more difficult to obtain cash from third party sources. If we cannot generate cash flow or otherwise secure sufficient liquidity to support our short-term and long-term capital requirements, we may not be able to comply with regulatory deadlines or pursue our business strategies, in which case our operations may not perform as well as we currently expect and we could be subject to regulatory action.
Changes in our credit profile, or a significant increase in the price of crude oil, may affect our relationship with our suppliers, which could have a material adverse effect on our liquidity and limit our ability to purchase enough crude oil to operate our refineries at desired capacity.
An unfavorable credit profile, or a significant increase in the price of crude oil, could affect the way crude oil suppliers view our ability to make payments and induce them to shorten the payment terms of their invoices with us or require credit enhancement. Due to the large dollar amounts and volume of our crude oil and other feedstock purchases, any imposition by our suppliers of more burdensome payment terms or credit enhancement requirements on us may have a material adverse effect on our liquidity and our ability to make payments to our suppliers. This in turn could cause us to be unable to operate our refineries at desired capacity. A failure to operate our refineries at desired capacity could adversely affect our profitability and cash flow.
We may not be able to obtain funding on acceptable terms or at all because of volatility and uncertainty in the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.
Although the domestic capital markets have shown signs of improvement in recent months, global financial markets and economic conditions have been, and continue to be, disrupted and volatile due to a variety of factors, including uncertainty in the financial services sector, low consumer confidence, increased unemployment, geopolitical issues and the current weak economic conditions. In addition, the fixed-income markets have experienced periods of extreme volatility that have negatively impacted market liquidity conditions. As a result, the cost of raising money in the debt and equity capital markets has increased substantially at times while the availability of funds from those markets diminished significantly. In particular, as a result of concerns about the stability of financial markets generally and the solvency of lending counterparties specifically, the cost of obtaining money from the credit markets may increase as many lenders and institutional investors increase interest rates, enact tighter lending standards, refuse to refinance existing debt on similar terms or at all and reduce, or in some cases cease, to provide funding to borrowers. In addition, lending counterparties under existing revolving credit facilities and other debt instruments may be unwilling or unable to meet their funding obligations. Due to these factors, we cannot be certain that new debt or equity financing will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due. Moreover, without adequate funding, we may be unable to execute our growth strategy, complete future acquisitions, take advantage of other business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations.
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Our leverage may limit our ability to borrow additional funds, comply with the terms of our indebtedness or capitalize on business opportunities.
As of December 31, 2009, the principal amount of our total outstanding debt was $300 million.
Our leverage could have important consequences. We require substantial cash flow to meet our payment obligations with respect to our indebtedness. Our ability to make scheduled payments, to refinance our obligations with respect to our indebtedness or our ability to obtain additional financing in the future will depend on our financial and operating performance, which, in turn, is subject to prevailing economic conditions and to financial, business and other factors. We believe that we will have sufficient cash flow from operations and available borrowings under our Credit Agreement to service our indebtedness. However, a significant downturn in our business or other development adversely affecting our cash flow could materially impair our ability to service our indebtedness. If our cash flow and capital resources are insufficient to fund our debt service obligations, we may be forced to refinance all or a portion of our debt or sell assets. We cannot assure you that we would be able to refinance our existing indebtedness at maturity or otherwise or sell assets on terms that are commercially reasonable.
Our debt agreements contain operating and financial restrictions that might constrain our business and financing activities.
The operating and financial restrictions and covenants in our credit facilities and any future financing agreements could adversely affect our ability to finance future operations or capital needs or to engage, expand or pursue our business activities. For example, our revolving credit facility imposes usual and customary requirements for this type of credit facility, including: (i) maintenance of certain levels of interest coverage and leverage ratios; (ii) limitations on liens, investments, indebtedness and dividends; (iii) a prohibition on changes in control and (iv) restrictions on engaging in mergers, consolidations and sales of assets, entering into certain lease obligations, and making certain investments or capital expenditures. If we fail to satisfy the covenants set forth in the credit facility or another event of default occurs under the facility, the maturity of the loan could be accelerated or we could be prohibited from borrowing for our future working capital needs and issuing letters of credit. We might not have, or be able to obtain, sufficient funds to make these immediate payments. Should we desire to undertake a transaction that is prohibited by the covenants in our credit facilities, we will need to obtain consent under our credit facilities. Such refinancing may not be possible or may not be available on commercially acceptable terms. In addition, our obligations under our credit facilities are secured by inventory, receivables and pledged cash assets. If we are unable to repay our indebtedness under our credit facilities when due, the lenders could seek to foreclose on the assets or we may be required to contribute additional capital to our subsidiaries. Any of these outcomes could have a material adverse effect on our business, financial condition and results of operations.
Our business may suffer due to a change in the composition of our Board of Directors, or if any of our key senior executives or other key employees discontinues employment with us. Furthermore, a shortage of skilled labor or disruptions in our labor force may make it difficult for us to maintain labor productivity.
Our future performance depends to a significant degree upon the continued contributions of our senior management team and key technical personnel. We do not currently maintain key man life insurance, non-compete agreements, or employment agreements with respect to any member of our senior management team. The loss or unavailability to us of any member of our senior management team or a key technical employee could significantly harm us. We face competition for these professionals from our competitors, our customers and other companies operating in our industry. To the extent that the services of members of our senior management team and key technical personnel would be unavailable to us for any reason, we may be required to hire other personnel to manage and operate our company. We may not be able to locate or employ such qualified personnel on acceptable terms, or at all.
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Furthermore, our operations require skilled and experienced laborers with proficiency in multiple tasks. A shortage of trained workers due to retirements or otherwise could have an adverse impact on our labor productivity and costs and our ability to expand production in the event there is an increase in the demand for our products and services, which could adversely affect our operations.
As of December 31, 2010, approximately 21% of our employees were represented by labor unions under collective bargaining agreements with various expiration dates. Effective February 1, 2009, a new agreement was reached with the United Steelworkers which applies to approximately 7% of our employees, which agreement will now expire on January 31, 2012. As of December 31, 2010, approximately 14% of our employees were represented by labor unions under a collective bargaining agreement that expires in 2016. We may not be able to renegotiate our collective bargaining agreements when they expire on satisfactory terms or at all. A failure to do so may increase our costs. In addition, our existing labor agreements may not prevent a strike or work stoppage at any of our facilities in the future, and any work stoppage could negatively affect our results of operations and financial condition.
Uncertainty about the Merger and diversion of management could harm us or the combined company, whether or not the Merger is completed.
The announcement of the Merger could result in current and prospective employees experiencing uncertainty about their future with us or the combined company. These uncertainties may impair our ability to retain, recruit or motivate key personnel. Completion of the Merger will also require a significant amount of time and attention from our management. The diversion of management’s attention away from ongoing operations could adversely affect our business relationships. Even if the merger is consummated, integration of operations will require substantial time after consummation of the Merger, and the combined company may lose management personnel and other key employees and be unable to attract and retain such personnel and employees.
We may need to use current cash flow to fund our pension and postretirement health care obligations, which could have a significant adverse effect on our financial position.
We have benefit obligations in connection with our noncontributory defined benefit pension plans that provided retirement benefits for substantially all of our employees. However, effective January 1, 2007, the retirement plan was frozen to new employees not covered by collective bargaining agreements with labor unions. To the extent an employee not covered by a collective bargaining agreement 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. We expect to contribute between $10 millionzero to $20$10 million to the retirement plan in 2010.2011. Future adverse changes in the financial markets could result in significant charges to stockholders’ equity and additional significant increases in future pension expense and funding requirements.
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We also have benefit obligations in connection with our unfunded postretirement health care plans that provide health care benefits as part of the voluntary early retirement program offered to eligible employees. As part of the early retirement program, we allow qualified retiring employees to continue coverage at a reduced cost under our group medical plans until normal retirement age. Additionally, we maintain an unfunded postretirement medical plan whereby certain retirees between the ages of 62 and 65 can receive benefits paid by us. As of December 31, 2009,2010, the total accumulated postretirement benefit obligation under our postretirement medical plans was $6.7$7.9 million. Increased participation in this program and/or increasing medical costs may affect our ability to pay required health care benefits causing us to have to divert funds away from other areas of the business to pay their costs.
TheWe could be subject to damages based on claims brought against us by our customers or lose customers as a result of the failure of our products to meet certain quality specifications.
A significant portion of our operating responsibility on refined product pipelines is to insure the quality and purity of the products loaded at our loading racks. If our quality control measures were to fail, off specification product could be sent out to public gasoline stations. This type of incident could result in liability claims regarding damages
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caused by the off specification fuel or could impact our ability to retain existing customers or to acquire new and revamped equipment in our facilities may not perform according to expectationscustomers, any of which may cause unexpected maintenance and downtime and could have a negative effectmaterial adverse impact on our future results of operations and financial condition.
We are completing major capital investment programs at both our Navajo and Woods Cross Refineries. At the Tulsa Refinery we have various projects planned to integrate the two facilities to fully utilize their capabilities. All three refineries also have various environmental compliance related projects.
The installation of new equipment and the revamp of key existing equipment involve significant risks and uncertainties, including the following:
Equipment may not perform at expected throughput levels,
Actual yields or product quality may differ from design,
Actual operating costs may be higher than expected,
Equipment may need to be redesigned, revamped, or replaced for the new units to perform as expected
cash flows. | | |
Item 1B. | | Item 1B. Unresolved Staff Comments |
We do not have any unresolved staff comments.
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Item 3. | | Item 3. 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.
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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, 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 SFPP’s 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 byas 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 income tax issuecase was remanded to FERC and theconsolidated with other remaining issues relating tocases that together addressed SFPP’s obligations to shippers are being handled by the FERC in a single compliance proceeding coveringrates for the period from January 1992 through May 2006. We currently estimate that, as a result of the May 2007 Court of Appeals decision and prior rulings by the Court of Appeals and the FERC in these proceedings, a net amount will be due from SFPP to us for the period January 1992 through May 2006 in addition to the $15.3 millionIn 2003 we received in 2003an initial payment of $15.3 million from SFPP as reparations for the period from 1992 through July 2000. Because proceedings inOn April 16, 2010, a settlement among us, SFPP, and other shippers was filed with FERC for its approval. FERC approved the FERC followingsettlement on May 28, 2010. Pursuant to the Courtsettlement, we received an additional settlement payment of Appeals decision have not been completed and final action by$8.6 million. This settlement finally resolves the FERC could be subject to further court proceedings, it is not possible at this time to determine what will beamount of additional payments SFPP owes us for the net amount payable to us at the conclusion of these proceedings.period January 1992 through May 2006.
b.Other Settlements
We and other shippers have beenalso engaged in settlement discussions with SFPP on remaining issues relating to East Line service in the FERC proceedings.proceedings that address periods after May 2006. A partial settlement regarding the East Line’s 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 approximately $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 Line’s Phase II expansion rates covering the period from December 20082007 through November 2010. The FERC approved the settlement on January 29, 2009. The settlement reduced SFPP’s current rates and required SFPP to make additional payments to us of approximately $2.9 million, which waswere 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
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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. The hearing was held from June 29, 2010 to be heldAugust 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 2010.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 SFPP’s 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.
MTBE Litigation
Our Navajo Refining Company subsidiary was named as a defendant, along with approximately 40 other companies involved in oil refining and marketing and related businesses, in a lawsuit originally filed in May 2006 by the State of New Mexico in the U.S. District Court for the District of New Mexico and subsequently transferred to the U.S. District Court for the Southern District of New York under multidistrict procedures along with approximately 100 similar cases, in which Navajo was not named, brought by other governmental entities and private parties in other states. The lawsuit, in which Navajo is named, as amended in October 2006 through the filing of a second amended complaint, alleges that the defendants are liable for contaminating the waters of New Mexico through producing and/or supplying MTBE or gasoline or other products containing MTBE. The lawsuit asserts claims for defective design or product, failure to warn, negligence, public nuisance, statutory public nuisance, private nuisance, trespass, and civil conspiracy, and seeks compensatory damages unspecified in amount, injunctive relief, exemplary and punitive damages, costs, attorney’s fees allowed by law, and interest allowed by law. The second amended complaint also contains a claim, asserted against certain other defendants but not against Navajo, alleging violations of certain provisions of the Toxic Substances Control Act, which appears to be similar to a claim previously threatened in a mailing to Navajo and other defendants by law firms representing the plaintiffs. Most other defendants have been dismissed from this lawsuit as a result of settlements. Pursuant to an agreement dated December 30, 2009, Navajo has been released with respect to the claims asserted against it in this lawsuit, and the lawsuit against it has been dismissed with prejudice.
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NMED NOV
In October 2008, the New Mexico Environment Department (“NMED”) issued an Amended Notice of Violation and Proposed Penalties (“Amended NOV”) to Navajo Refining Company, amending an NOV issued in February 2007. The NOV is a preliminary enforcement document issued by NMED and usually is the predicate to formal administrative or judicial enforcement. The February 2007 NOV was issued following two hazardous waste compliance evaluation inspections at the Artesia, New Mexico refinery that were conducted in April and November 2006 and alleged violations of the New Mexico Hazardous Waste Management Regulations and Navajo’s Hazardous Waste Permit. NMED proposed a civil penalty of approximately $0.1 million for the February 2007 NOV. The Amended NOV includes additional alleged violations concerning post-closure care of a hazardous waste land treatment unit and the construction of a tank on the land treatment area. The Amended NOV also proposes an additional civil penalty of $0.3 million. Navajo has submitted responses to the February 2007 NOV and the Amended NOV, challenging certain alleged violations and proposed penalty amounts and is continuing negotiations with the NMED to resolve these matters expeditiously.
Woods Cross Construction Dispute 1
Our Holly Refining & Marketing Company — Woods Cross and Woods Cross Refining Company, LLC subsidiaries were named, along with other parties, as defendants in a lawsuit filed in December 2008 by Brahma Group, Inc. in the State District Court in Davis County, Utah, involving a construction dispute regarding the installation of improvements known as a crude desalter, crude unloader, and west tank farm at our Woods Cross, Utah refinery. This matter has been resolved through mutual agreement of the parties. All actions have been settled for an immaterial amount and dismissed with prejudice by the court.
Woods Cross Construction Dispute 2
Our Holly Refining & Marketing Company — Woods Cross and Woods Cross Refining Company, LLC subsidiaries were named, along with other parties, as defendants in a lawsuit filed on April 22, 2009 by Brahma Group, Inc. in the State District Court in Davis County, Utah, involving a construction dispute over the installation of an oil gas hydrocracker at the Woods Cross, Utah refinery. The lawsuit alleges that the defendants caused delays, additional work and increased costs in the installation of the oil gas hydrocracker for which the plaintiff was not paid. The claims made against our subsidiaries are for lien foreclosure, failure to obtain a payment bond, and implied contract. The lawsuit seeks compensatory damages in the approximate amount of $12.0 million, costs, attorney’s fees allowed by law, and interest allowed by law. A lien has also been filed in the county records against the refinery property in that amount. Our subsidiaries have tendered defense of the complaint to the general contractor, Benham Constructors. Our subsidiaries have answered the complaint and denied any liability. The plaintiff and the general contractor have agreed to arbitrate their dispute, and the claims against our subsidiaries have been stayed pending the outcome of that arbitration. At the date of this report, it is not possible to predict the likely course or outcome of this litigation.
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 $298,500$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 approximately $150,000$0.2 million to reimburse the State’s 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.
OSHA Inspection — Woods CrossNavajo Tank Fire
In June 2007,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 are set for trial in May 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”) announced a national emphasis program (“NEP”) for inspecting approximately 80 refineries within its jurisdiction. As a part of the NEP, OSHA encouraged the State Plan States such as Utah to initiate their own version of the NEP. Beginning on May 1, 2008, the Utah Labor Commission, Occupational Safety and Health Division (“UOSH”) beganregulations, commenced an inspection ofin relation to the refinery which is operated by Hollytank 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 Marketing Company — Woods Cross and is located in Woods Cross, Utah. The inspection ended on September 18 and on October 23, 2008, UOSH issued one citation alleging 33 violations1 serious violation of various construction safety standards includingstandards. OHSB proposed penalties in the Process Safety Management Standard and proposing a penaltyamount of $91,750. We$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 Mexico’s Occupational Health and Safety Review Commission (“OSHRC”) on December 20, 2010. Navajo will challenge the Adjudicative Division, Utah Labor Commission, in Salt Lake City, Utah. On February 18, 2009,citations before the initial status conference for this matter was heldOSHRC, and a scheduling order was issued. Ourfiled its answer was filed and served on March 4, 2009 and discovery endedto the complaint on January 6, 2010.2011. The parties have agreed to a discovery schedule and jointly requested a hearing date has been set for July 6, 2010. We intend to vigorously defend this citation and believe that we have strong defenses on the merits.commence no sooner than September 5, 2011.
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OSHA InspectionInspections — Tulsa Refinery east facility
In June 2007, OSHA announced a NEPnational emphasis program (“NEP”) for inspecting approximately 80 refineries within its jurisdiction. As part of the NEP, OSHA conducted an inspection of Sinclair Tulsa Refining Company’s (“
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(“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 Standard (“PSM”) standard and the General Duty Clause. OSHA proposed penalties totaling $240,750.$0.2 million. Sinclair filed a notice of contest, challenging the citations. Because the proposed penalties exceed $100,000, the matter was referred for mandatory settlement before the Occupational Safety and Health Review Commission. The settlement conference is scheduled to take place March 16 — 17, 2010 in Dallas, Texas.
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 Occupational Safety and Health Review CommissionOSHRC 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 is in the initial stages of evaluatinghas evaluated the feasibility and range of options to make suchvarious 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 OSHA’s approval of the safety improvement plan. The settlement agreement between HRM-Tulsa and OSHA was filed with the OSHRC on August 11, 2010. On August 23, 2010, the OSHRC 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. A pretrial conference took place on November 3, 2010, at which Judge Augustine established March 11, 2011 as the deadline for close of discovery and scheduled the hearing to take place from April 11 — 15, 2011.
OSHA began the NEP inspection of our Tulsa Refinery west facility on September 14, 2010. The inspection is ongoing.
Discharge Permit Appeal — Tulsa Refinery west facilityWest Facility
Our subsidiary, HRM-TulsaHRM Tulsa is party to parallel Oklahoma administrative and state district court proceedings involving a challenge originally filed by Sunoco, Inc. (R&M), to the terms of the Oklahoma Department of Environmental Quality (“ODEQ”) permit that governs the discharge of industrial wastewater from what is now our Tulsa Refinery west facility. After our acquisition of the Tulsa Refinery west facility, we were substituted for Sunoco in both proceedings. On February 1, 2010, we entered intoPursuant to a settlement agreement with the Oklahoma Department of Environmental Quality. The agreement provided, among other things, for the amendment of the permit to require that thebetween HRM Tulsa Refinery west facility make certain modifications in its system for handling storm flows. These modifications are required to be complete within three years of the issuance of the revised permit. Both the administrative and the state district courtODEQ, both proceedings have been stayed to allow ODEQ to issue a revised permit this settlement agreementthat modifies the existing permit’s requirements for toxicity testing and for managing storm flows. The parties are now in discussions regarding the appropriate changes in the permit language to be effectuated.accomplish these modifications. Once the agreed-upon changesrevisions are made and become effective, both proceedings will be dismissed. Preliminary engineering is underwayAny changes to develop a final scope and capital estimate, and any process modification isrefinery processes that result from the permit revisions will be subject to regulatory review and approval. Accordingly, it is not possible to estimate the costs of compliance with the new permit provisionprovisions at this time.
Unclaimed Property Audit
A multi-state audit of our unclaimed property compliance and reporting is being conducted by Kelmar Associates, LLC on behalf of twelveeleven states. We expectare currently in the third year of this ongoing audit process to take several years to be resolved due tothat covers the lengthy period covered by the audit (19811981 — 2004).2004. It is not yet possible to accurately estimate the amount, if any, that is owed to each of the states since only preliminary investigation has occurred to date.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.
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Item 4. | | Submission of Matters to a Vote of Security HoldersItem 4. (Removed and Reserved)
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No matter was submitted to a vote of security holders during the fourth quarter of 2009.
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PART II
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| Item 5. | | Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Our common stock is traded on the New York Stock Exchange under the trading symbol “HOC.” The following table sets forth the range of the daily high and low sales prices per share of common stock, dividends declared per share and the trading volume of common stock for the periods indicated:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Trading | | | Trading |
| Years Ended December 31, | | High | | Low | | Dividends | | Volume | | | High | | Low | | Dividends | | Volume |
2010 | | |
| Fourth quarter | | | $ | 41.38 | | $ | 28.19 | | $ | 0.15 | | 36,902,900 | |
| Third quarter | | | $ | 29.86 | | $ | 24.35 | | $ | 0.15 | | 37,493,600 | |
| Second quarter | | | $ | 30.57 | | $ | 23.32 | | $ | 0.15 | | 63,314,200 | |
| First quarter | | | $ | 30.86 | | $ | 25.13 | | $ | 0.15 | | 47,712,400 | |
| | | |
2009 | | |
| Fourth quarter | | $ | 33.53 | | $ | 23.57 | | $ | 0.15 | | 52,039,700 | | | $ | 33.53 | | $ | 23.57 | | $ | 0.15 | | 52,039,700 | |
| Third quarter | | $ | 26.22 | | $ | 16.71 | | $ | 0.15 | | 50,535,600 | | | $ | 26.22 | | $ | 16.71 | | $ | 0.15 | | 50,535,600 | |
| Second quarter | | $ | 31.63 | | $ | 17.23 | | $ | 0.15 | | 73,542,100 | | | $ | 31.63 | | $ | 17.23 | | $ | 0.15 | | 73,542,100 | |
| First quarter | | $ | 27.42 | | $ | 18.15 | | $ | 0.15 | | 85,489,800 | | | $ | 27.42 | | $ | 18.15 | | $ | 0.15 | | 85,489,800 | |
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2008 | | |
| Fourth quarter | | $ | 28.83 | | $ | 10.84 | | $ | 0.15 | | 81,694,000 | | |
| Third quarter | | $ | 37.47 | | $ | 25.88 | | $ | 0.15 | | 88,195,700 | | |
| Second quarter | | $ | 49.62 | | $ | 36.13 | | $ | 0.15 | | 79,585,500 | | |
| First quarter | | $ | 56.81 | | $ | 38.84 | | $ | 0.15 | | 79,892,000 | | |
As of February 8, 2010,2011, we had approximately 23,20020,900 stockholders, including beneficial owners holding shares in street name.
We intend to consider the declaration of a dividend on a quarterly basis, although there is no assurance as to future dividends since they are dependent upon future earnings, capital requirements, our financial condition and other factors. Our credit agreement limitsand senior notes limit the payment of dividends. See Note 12 in the “Notes to Consolidated Financial Statements” under Item 8, “Financial Statements and Supplementary Data.”
Under our common stock repurchase program, repurchases are made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors. There were no common stock repurchases during the fourth quarter of 2009.2010.
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Item 6. | | Item 6. Selected Financial Data |
The following table shows our selected financial information as of the dates or for the periods indicated. This table should be read in conjunction with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes thereto included elsewhere in this Annual Report on Form 10-K.
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| | | Years Ended December 31, | | | Years Ended December 31, | |
| | | 2009(1)(4) | | 2008(1)(4) | | 2007(1)(4) | | 2006(1)(3)(4) | | 2005(1)(2)(3)(4) | | | 2010 | | 2009 | | 2008 | | 2007 | | 2006 | |
| | | (In thousands, except per share data) | | | (In thousands, except per share data) | |
FINANCIAL DATA | | |
For the period | | |
| Sales and other revenues | | $ | 4,834,268 | | $ | 5,860,357 | | $ | 4,791,742 | | $ | 4,023,217 | | $ | 3,046,313 | | | $ | 8,322,929 | | $ | 4,834,268 | | $ | 5,860,357 | | $ | 4,791,742 | | $ | 4,023,217 | |
| Income from continuing operations before income taxes | | 43,803 | | 187,746 | | 499,444 | | 383,501 | | 270,373 | | | 192,363 | | 43,803 | | 187,746 | | 499,444 | | 383,501 | |
| Income tax provision | | 7,460 | | 64,028 | | 165,316 | | 136,603 | | 99,626 | | | 59,312 | | 7,460 | | 64,028 | | 165,316 | | 136,603 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Income from continuing operations | | 36,343 | | 123,718 | | 334,128 | | 246,898 | | 170,747 | | | 133,051 | | 36,343 | | 123,718 | | 334,128 | | 246,898 | |
Income from discontinued operations, net of taxes | | 16,926 | | 2,918 | | — | | 19,668 | | 2,963 | | | — | | 16,926 | | 2,918 | | — | | 19,668 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Net income before cumulative effect of change in accounting principle | | 53,269 | | 126,636 | | 334,128 | | 266,566 | | 173,710 | | |
| Cumulative effect of accounting change (net of income tax expense of $426) | | — | | — | | — | | — | | 669 | | |
| | | | | | | | | | | | | |
Net income(5) | | 53,269 | | 126,636 | | 334,128 | | 266,566 | | 174,379 | | |
Less net income attributable to noncontrolling interest(5) | | 33,736 | | 6,078 | | — | | — | | 6,721 | | |
| Net income | | | 133,051 | | 53,269 | | 126,636 | | 334,128 | | 266,566 | |
| Less net income attributable to noncontrolling interest | | | 29,087 | | 33,736 | | 6,078 | | — | | — | |
| | | | | | | | | | | | | | | | | | | | | | | |
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Net income attributable to Holly Corporation Stockholders(5) | | $ | 19,533 | | $ | 120,558 | | $ | 334,128 | | $ | 266,566 | | $ | 167,658 | | |
| Net income attributable to Holly Corporation Stockholders | | | $ | 103,964 | | $ | 19,533 | | $ | 120,558 | | $ | 334,128 | | $ | 266,566 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| Earnings per share attributable to Holly Corporation stockholders — basic | | $ | 0.39 | | $ | 2.40 | | $ | 6.09 | | $ | 4.68 | | $ | 2.72 | | | $ | 1.95 | | $ | 0.39 | | $ | 2.40 | | $ | 6.09 | | $ | 4.68 | |
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| Earnings per share attributable to Holly Corporation stockholders — diluted | | $ | 0.39 | | $ | 2.38 | | $ | 5.98 | | $ | 4.58 | | $ | 2.65 | | | $ | 1.94 | | $ | 0.39 | | $ | 2.38 | | $ | 5.98 | | $ | 4.58 | |
| | | |
| Cash dividends declared per common share | | $ | 0.60 | | $ | 0.60 | | $ | 0.46 | | $ | 0.29 | | $ | 0.19 | | | $ | 0.60 | | $ | 0.60 | | $ | 0.60 | | $ | 0.46 | | $ | 0.29 | |
| | | |
| Average number of common shares outstanding: | | |
| Basic | | 50,418 | | 50,202 | | 54,852 | | 56,976 | | 61,728 | | | 53,218 | | 50,418 | | 50,202 | | 54,852 | | 56,976 | |
| Diluted | | 50,595 | | 50,549 | | 55,850 | | 58,210 | | 63,244 | | | 53,609 | | 50,603 | | 50,549 | | 55,850 | | 58,210 | |
| | | |
| Net cash provided by operating activities | | $ | 214,058 | | $ | 155,490 155,490 | | $ | 422,737 | | $ | 245,183 | | $ | 251,234 | | | $ | 283,255 | | $ | 211,545 | | $ | 155,490 | | $ | 422,737 | | $ | 245,183 | |
| Net cash provided by (used for) investing activities | | $ | (537,116 | ) | | $ | (57,777 | ) | | $ | (293,057 | ) | | $ | 35,805 | | $ | (320,135 | ) | | $ | (213,232 | ) | | $ | (534,603 | ) | | $ | (57,777 | ) | | $ | (293,057 | ) | | $ | 35,805 | |
| Net cash provided by (used for) financing activities | | $ | 406,849 | | $ | (151,277 | ) | | $ | (189,428 | ) | | $ | (175,935 | ) | | $ | 50,505 | | | $ | 34,482 | | $ | 406,849 | | $ | (151,277 | ) | | $ | (189,428 | ) | | $ | (175,935 | ) |
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At end of period | | |
| Cash, cash equivalents and investments in marketable securities | | $ | 125,819 | | $ | 94,447 | | $ | 329,784 | | $ | 255,953 | | $ | 254,842 | | | $ | 230,444 | | $ | 125,819 | | $ | 94,447 | | $ | 329,784 | | $ | 255,953 | |
Working capital(6) | | $ | 257,899 | | $ | 68,465 | | $ | 216,541 | | $ | 240,181 | | $ | 210,103 | | |
| Working capital | | | $ | 313,580 | | $ | 257,899 | | $ | 68,465 | | $ | 216,541 | | $ | 240,181 | |
| Total assets | | $ | 3,145,939 | | $ | 1,874,225 | | $ | 1,663,945 | | $ | 1,237,869 | | $ | 1,142,900 | | | $ | 3,701,475 | | $ | 3,145,939 | | $ | 1,874,225 | | $ | 1,663,945 | | $ | 1,237,869 | |
| Total debt, including short-term | | $ | 667,649 | | $ | 370,914 | | $ | — | | $ | — | | $ | — | | |
Total equity(5) | | $ | 1,207,871 | | $ | 936,332 | | $ | 593,794 | | $ | 466,094 | | $ | 377,351 | | |
Total debt, including short-term(3) | | | $ | 810,561 | | $ | 707,458 | | $ | 370,914 | | $ | — | | $ | — | |
| Total equity | | | $ | 1,288,139 | | $ | 1,207,781 | | $ | 936,332 | | $ | 602,127 | | $ | 466,094 | |
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| (1) | | We reconsolidated HEP effective March 1, 2008 and include the consolidated results of HEP in our financial statements. For the period from July 1, 2005 through February 29, 2008, we accounted for our investment in HEP under the equity method of accounting whereby we recorded our pro-rata share of earnings in HEP. Contributions to and distributions from HEP were recorded as adjustments to our investment balance. Prior to July 1, 2005, HEP was a consolidated entity. See “Company Overview” under Items 1 and 2, “Business and Properties” for information regarding our reconsolidation of HEP effective March 1, 2008. |
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| (2) | | The average number of shares of common stock and per share amounts have been adjusted to reflect the two-for-one stock split effective June 1, 2006. |
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(3) | | On March 31, 2006, we sold our Montana refinery. Results of operations of the Montana refinery that were previously reported in operations are presented in discontinued operations. |
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(4) | | On December 1, 2009, HEP sold its 70% interest in Rio Grande. Accordingly, resultsResults of operations of Rio Grande that were previously reported in operations are presented in discontinued operations. For the year ended December 31, 2006, our discontinued operations were attributable to our Montana refinery that was sold in March 2006. |
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(5)(3) | | Accounting standards became effective January 1, 2009 that change the classificationIncludes total HEP debt of noncontrolling interests, also referred to as minority interests, in the Consolidated Financial Statements. As a result, all previous references to “minority interest” within these financial statements have been replaced “noncontrolling interest.” Also, net income attributable to the noncontrolling interest in our HEP subsidiary$482.3 million, $379.2 million and $370.9 million, respectively, which is now presented as an adjustment to net income to arrive at “Net income attributablenon-recourse to Holly Corporation stockholders” in our Consolidated Statements of Income. Prior to our adoption of these standards, this amount was presented as “Minority interest in earnings of HEP,” a non-operating expense item before “Income before income taxes.” Additionally, equity attributable to noncontrolling interests is now presented as a separate component of total equity in the Consolidated Financial Statements. We have adopted these standards on a retrospective basis. While this presentation differs from previous requirements under GAAP, it did not affect our net income and equity attributable to Holly Corporation stockholders. |
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(6) | | At December 31, 2008, HEP classified $29 million in credit agreement borrowings as short-term debt.Corporation. |
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Item 7. | | Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations |
This Item 7 contains “forward-looking” statements. See “Forward-Looking Statements” at the beginning of this Annual Report on Form 10-K. 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 with certain exceptions.person. For periods prior toafter our reconsolidation of HEP effective March 1, 2008, the words “we,” “our,” “ours” and “us” excludegenerally include HEP and its subsidiaries as consolidated subsidiaries of Holly Corporation.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 operating three refineries in Artesia and Lovington, New Mexico (operated as one refinery), Woods Cross, Utah and Tulsa, Oklahoma. As of December 31, 2009,2010, our refineries had a combined crude capacity of 256,000 BPSD. Our profitability depends largely on the spread between market prices for refined petroleum products and crude oil prices. At December 31, 2009,2010, we also owned a 34% interest in HEP, a consolidated subsidiary,VIE, which owns and operates pipeline and terminalling assets.
Our principal source of revenue is from the sale of high value light products such as gasoline, diesel fuel, jet fuel specialty lubricant products, and specialty and modified asphalt in markets in the Southwestern,Southwest, Rocky Mountain and Mid-Continent regions of the United States. Our salesStates and northern Mexico. We also produce specialty lubricant products that are marketed throughout North America and are distributed in Central and South America. Sales and other revenues from continuing operations and net income attributable to Holly Corporation stockholders for the year ended December 31, 2009 were $8,322.9 million and $104 million, $4,834.3 million and $19.5 million, respectively. Our sales and other revenues and net income attributable to Holly Corporation stockholders for the year ended December 31, 2008 were $5,860.4 million and $120.6 million for the years ended December 31, 2010, 2009 and 2008, respectively. Our principal expenses are costs of products sold and operating expenses. Our total operating costs and expenses for the year ended December 31, 2009 were $8,059.9 million, $4,754 million a decrease fromand $5,664.7 million for the yearyears ended December 31, 2008.2010, 2009 and 2008, respectively.
On June 1, 2009, we acquired the Tulsa Refinery west facility, an 85,000 BPSD refinery located in Tulsa, Oklahoma from Sunoco for $157.8 million in cash, including crude oil, refined product and other inventories valued at $92.8 million. The refinery produces fuel products including gasoline, diesel fuel and jet fuel and serves markets in the Mid-Continent region of the United States and also produces specialty lubricant products that are marketed throughout North America and are distributed in Central and South America. On October 20, 2009, we sold to Plains a portion of the crude oil petroleum storage tanks and certain refining-related crude oil receiving pipeline facilities, that were acquired as part of the refinery assets for $40 million.
On December 1, 2009, we acquired the Tulsa Refinery east facility, a 75,000 BPSD refinery from Sinclair also located in Tulsa, Oklahoma for $183.3 million, including crude oil, refined product and other inventories valued at $46.4 million. The total purchase price consisted of $109.3 million in cash and 2,789,155 shares of our common stock having a value of $74 million. Additionally, we will reimburse Sinclair approximately $8 million upon their satisfactory completion of certain environmental projects at the refinery. The refinery also produces gasoline, diesel fuel and jet fuel products and also serves markets in the Mid-Continent region of the United States. We are in the process of integrating the operations of both Tulsa Refinery facilities. Upon completion, the Tulsa Refinery will have an integrated crude processing rate of 125,000 BPSD.
Seperately,Separately, HEP, also a party to the December 1, 2009 transaction with Sinclair, acquired certain logistics and storage assets located at ourthe Tulsa Refinery east facility. See “Holly Energy Partners, L.P. — 2009 Acquisitions” under Items 1 and 2, “Business and Properties” for additional information on this transaction as well as HEP’s 2010 and other 2009 asset acquisitions from us.
Also on December 1, 2009, HEP sold its 70% interest in Rio Grande to a subsidiary of Enterprise Products Partners LP for $35 million. Accordingly, the resultsResults of operations of Rio Grande and the $14.5 million gain on the sale are presented in discontinued operations.
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On February 29, 2008, we sold the Crude Pipelinescertain crude pipelines and Tankage Assetstankage assets to HEP for $180 million. The assets consisted of crude oil trunk lines that deliver crude oil to our refinery in southeast New Mexico, gathering and connection pipelines located in west Texas and New Mexico, on-site crude tankage located within both of our refinerythe Navajo and Woods Cross Refinery complexes, a jet fuel products pipeline and leased terminal between Artesia and Roswell, New Mexico and crude oil and product pipelines that support our refinery in Woods Cross, Utah. HEP is a VIE as defined under GAAP. Under GAAP, HEP’s purchase of the Crude Pipelines and Tankage Assetsthese assets qualified as a reconsideration event whereby we reassessed our beneficial interest in HEP. Following this transaction, we determined that our beneficial interest
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in HEP exceeded 50%. Accordingly,Therefore, we reconsolidated HEP effective March 1, 2008. Therefore, intercompanyIntercompany transactions with HEP are eliminated in our consolidated financial statements.
Recent Developments
On February 21, 2011, we entered into a merger agreement providing for a “merger of equals” business combination of us and Frontier. Subject to the terms and conditions of the merger agreement which has been approved unanimously by both our and Frontier’s board of directors, Frontier shareholders will receive 0.4811 shares of Holly common stock for each share of Frontier common stock if the Merger is completed. See “Recent Developments” in Company Overview section under Items 1 and 2, “Business and Properties” for additional information on the Merger.
RESULTS OF OPERATIONS
Financial Data
| | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | | | | | | | | | | | |
| | | 2009 | | 2008 | | 2007 | | | Years Ended December 31, | |
| | | (In thousands, except per share data) | | | 2010 | | 2009 | | 2008 | |
| | | | (In thousands, except per share data) | |
| Sales and other revenues | | $ | 4,834,268 | | $ | 5,860,357 | | $ | 4,791,742 | | | $ | 8,322,929 | | $ | 4,834,268 | | $ | 5,860,357 | |
| Operating costs and expenses: | | |
| Cost of products sold (exclusive of depreciation and amortization) | | 4,238,008 | | 5,280,699 | | 4,003,488 | | | 7,367,149 | | 4,238,008 | | 5,280,699 | |
| Operating expenses (exclusive of depreciation and amortization) | | 356,855 | | 265,705 | | 209,281 | | | 504,414 | | 356,855 | | 265,705 | |
| General and administrative expenses (exclusive of depreciation and amortization) | | 60,343 | | 55,278 | | 69,185 | | | 70,839 | | 60,343 | | 55,278 | |
| Depreciation and amortization | | 98,751 | | 62,995 | | 43,456 | | | 117,529 | | 98,751 | | 62,995 | |
| | | | | | | | | | | | | | | |
| Total operating costs and expenses | | 4,753,957 | | 5,664,677 | | 4,325,410 | | | 8,059,931 | | 4,753,957 | | 5,664,677 | |
| | | | | | | | | | | | | | | |
| | | |
| Income from operations | | 80,311 | | 195,680 | | 466,332 | | | 262,998 | | 80,311 | | 195,680 | |
| Other income (expense): | | |
| Equity in earnings of SLC Pipeline | | 1,919 | | — | | — | | | 2,393 | | 1,919 | | — | |
| Interest income | | 5,045 | | 10,797 | | 15,089 | | | 1,168 | | 5,045 | | 10,797 | |
| Interest expense | | | (40,346 | ) | | | (23,955 | ) | | | (1,086 | ) | | | (74,196 | ) | | | (40,346 | ) | | | (23,955 | ) |
| Acquisition costs — Tulsa Refineries | | | (3,126 | ) | | — | | — | | |
| Acquisition costs — Tulsa refineries | | | — | | | (3,126 | ) | | — | |
| Impairment of equity securities | | — | | | (3,724 | ) | | — | | | — | | — | | | (3,724 | ) |
| Gain on sale of Holly Petroleum, Inc. | | — | | 5,958 | | — | | | — | | — | | 5,958 | |
| Equity in earnings of HEP | | — | | 2,990 | | 19,109 | | | — | | — | | 2,990 | |
| | | | | | | | | | | | | | | |
| | | | (36,508 | ) | | | (7,934 | ) | | 33,112 | | | | (70,635 | ) | | | (36,508 | ) | | | (7,934 | ) |
| | | | | | | | | | | | | | | |
| Income from continuing operations before income taxes | | 43,803 | | 187,746 | | 499,444 | | | 192,363 | | 43,803 | | 187,746 | |
| Income tax provision | | 7,460 | | 64,028 | | 165,316 | | | 59,312 | | 7,460 | | 64,028 | |
| | | | | | | | | | | | | | | |
| Income from continuing operations | | 36,343 | | 123,718 | | 334,128 | | | 133,051 | | 36,343 | | 123,718 | |
Income from discontinued operations, net of taxes(1) | | 16,926 | | 2,918 | | — | | | — | | 16,926 | | 2,918 | |
| | | | | | | | | | | | | | | |
Net income(2) | | 53,269 | | 126,636 | | 334,128 | | |
Less noncontrolling interest in net income(2) | | 33,736 | | 6,078 | | — | | |
| Net income | | | 133,051 | | 53,269 | | 126,636 | |
| Less net income attributable to noncontrolling interest | | | 29,087 | | 33,736 | | 6,078 | |
| | | | | | | | | | | | | | | |
Net income attributable to Holly Corporation stockholders(2) | | $ | 19,533 | | $ | 120,558 | | $ | 334,128 | | |
| Net income attributable to Holly Corporation stockholders | | | $ | 103,964 | | $ | 19,533 | | $ | 120,558 | |
| | | | | | | | | | | | | | | |
| | | |
| Earnings attributable to Holly Corporation stockholders: | | |
| Income from continuing operations | | $ | 15,209 | | $ | 119,206 | | $ | 334,128 | | | $ | 103,964 | | $ | 15,209 | | $ | 119,206 | |
| Income from discontinued operations | | 4,324 | | 1,352 | | — | | | — | | 4,324 | | 1,352 | |
| | | | | | | | | | | | | | | |
| Net income | | $ | 19,533 | | $ | 120,558 | | $ | 334,128 | | | $ | 103,964 | | $ | 19,533 | | $ | 120,558 | |
| | | | | | | | | | | | | | | |
| | | |
| Earnings per share attributable to Holly Corporation stockholders — basic: | | |
| Continuing operations | | $ | 0.30 | | $ | 2.37 | | $ | 6.09 | | |
| Discontinued operations | | 0.09 | | 0.03 | | — | | |
| Income from continuing operations | | | $ | 1.95 | | $ | 0.30 | | $ | 2.37 | |
| Income from discontinued operations | | | — | | 0.09 | | 0.03 | |
| | | | | | | | | | | | | | | |
| Net income | | $ | 0.39 | | $ | 2.40 | | $ | 6.09 | | | $ | 1.95 | | $ | 0.39 | | $ | 2.40 | |
| | | | | | | | | | | | | | | |
| | | |
| Earnings per share attributable to Holly Corporation stockholders — diluted: | | |
| Continuing operations | | $ | 0.30 | | $ | 2.36 | | $ | 5.98 | | |
| Discontinued operations | | 0.09 | | 0.02 | | — | | |
| Income from continuing operations | | | $ | 1.94 | | $ | 0.30 | | $ | 2.36 | |
| Income from discontinued operations | | | — | | 0.09 | | 0.02 | |
| | | | | | | | | | | | | | | |
| Net income | | $ | 0.39 | | $ | 2.38 | | $ | 5.98 | | | $ | 1.94 | | $ | 0.39 | | $ | 2.38 | |
| | | | | | | | | | | | | | | |
| | | |
| Cash dividends declared per common share | | $ | 0.60 | | $ | 0.60 | | $ | 0.46 | | | $ | 0.60 | | $ | 0.60 | | $ | 0.60 | |
| | | | | | | | | | | | | | | |
| | | |
| Average number of common shares outstanding: | | |
| Basic | | 50,418 | | 50,202 | | 54,852 | | | 53,218 | | 50,418 | | 50,202 | |
| Diluted | | 50,603 | | 50,549 | | 55,850 | | | 53,609 | | 50,603 | | 50,549 | |
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Balance Sheet Data
| | | | | | | | | | |
| | | Years Ended December 31, | | | | | | | | | |
| | | 2009 | | 2008 | | | December 31, |
| | | (In thousands) | | | 2010 | | 2009 |
| | | | (In thousands) |
| Cash, cash equivalents and investments in marketable securities | | $ | 125,819 | | $ | 94,447 | | | $ | 230,444 | | $ | 125,819 | |
Working capital(3) | | $ | 257,899 | | $ | 68,465 | | |
| Working capital | | | $ | 313,580 | | $ | 257,899 | |
| Total assets | | $ | 3,145,939 | | $ | 1,874,225 | | | $ | 3,701,475 | | $ | 3,145,939 | |
| Long-term debt — Holly Corporation | | $ | 328,260 | | $ | — | | | $ | 328,290 | | $ | 328,260 | |
| Long-term debt — Holly Energy Partners | | $ | 379,198 | | $ | 341,914 | | | $ | 482,271 | | $ | 379,198 | |
Total equity(2) | | $ | 1,207,871 | | $ | 936,332 | | |
| Total equity | | | $ | 1,288,139 | | $ | 1,207,781 | |
| | |
| (1) | | On December 1, 2009, HEP sold its 70% interest in Rio Grande. Accordingly, resultsResults of operations of Rio Grande are presented in discontinued operations. |
|
(2) | | Accounting standards became effective January 1, 2009 that change the classification of noncontrolling interests, also referred to as minority interests, in the Consolidated Financial Statements. As a result, all previous references to “minority interest” within these financial statements have been replaced with “noncontrolling interest.” Also, net income attributable to the noncontrolling interest in our HEP subsidiary is now presented as an adjustment to net income to arrive at “Net income attributable to Holly Corporation stockholders” in our Consolidated Statements of Income. Prior to our adoption of these standards, this amount was presented as “Minority interest in earnings of HEP,” a non-operating expense item before “Income before income taxes.” Additionally, equity attributable to noncontrolling interests is now presented as a separate component of total equity in the Consolidated Financial Statements. We have adopted these standards on a retrospective basis. While this presentation differs from previous requirements under GAAP, it did not affect our net income and equity attributable to Holly Corporation stockholders. |
|
(3) | | At December 31, 2008, HEP classified $29 million in credit agreement borrowings as short-term debt. |
Other Financial Data
| | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | | | | | | | | | | | |
| | | 2009 | | 2008 | | 2007 | | | Years Ended December 31, |
| | | (In thousands) | | | 2010 | | 2009 | | 2008 |
| | | | (In thousands) | |
| Net cash provided by operating activities | | $ | 211,545 | | $ | 155,490 | | $ | 422,737 | | | $ | 283,255 | | $ | 211,545 | | $ | 155,490 | |
| Net cash used for investing activities | | $ | (534,603 | ) | | $ | (57,777 | ) | | $ | (293,057 | ) | | $ | (213,232 | ) | | $ | (534,603 | ) | | $ | (57,777 | ) |
| Net cash provided by (used for) financing activities | | $ | 406,849 | | $ | (151,277 | ) | | $ | (189,428 | ) | | $ | 34,482 | | $ | 406,849 | | $ | (151,277 | ) |
| Capital expenditures | | $ | 302,551 | | $ | 418,059 | | $ | 161,258 | | | $ | 213,232 | | $ | 302,551 | | $ | 418,059 | |
EBITDA from continuing operations(1) | | $ | 156,721 | | $ | 259,387 | | $ | 528,897 | | | $ | 353,833 | | $ | 156,721 | | $ | 259,387 | |
| | |
| (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 7A of Part II of this Form 10-K. |
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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 Eliminations.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | Years Ended December 31, | |
| | | 2009 | | 2008 | | 2007 | | | 2010 | | 2009 | | 2008 | |
| | | (In thousands) | | | (In thousands) | |
| Sales and other revenues | | |
Refining(1) | | $ | 4,786,937 | | $ | 5,837,449 | | $ | 4,790,164 | | | $ | 8,287,000 | | $ | 4,789,821 | | $ | 5,837,449 | |
HEP(2) | | 146,561 | | 94,439 | | — | | | 182,114 | | 146,561 | | 94,439 | |
| Corporate and other | | 2,248 | | 2,641 | | 1,578 | | | 415 | | | (636 | ) | | 2,641 | |
| Eliminations | | | (101,478 | ) | | | (74,172 | ) | | — | | | | (146,600 | ) | | | (101,478 | ) | | | (74,172 | ) |
| | | | | | | | | | | | | | | |
| Consolidated | | $ | 4,834,268 | | $ | 5,860,357 | | $ | 4,791,742 | | | $ | 8,322,929 | | $ | 4,834,268 | | $ | 5,860,357 | |
| | | | | | | | | | | | | | | |
| | | |
| Operating income (loss) | | |
Refining(1) | | $ | 68,397 | | $ | 210,252 | | $ | 537,118 | | | $ | 242,466 | | $ | 71,281 | | $ | 210,252 | |
HEP(2) | | 70,373 | | 37,082 | | — | | | 92,386 | | 70,373 | | 37,082 | |
| Corporate and other | | | (57,355 | ) | | | (51,654 | ) | | | (70,786 | ) | | | (69,654 | ) | | | (60,239 | ) | | | (51,654 | ) |
| Eliminations | | | (1,104 | ) | | — | | — | | | | (2,200 | ) | | | (1,104 | ) | | — | |
| | | | | | | | | | | | | | | |
| Consolidated | | $ | 80,311 | | $ | 195,680 | | $ | 466,332 | | | $ | 262,998 | | $ | 80,311 | | $ | 195,680 | |
| | | | | | | | | | | | | | | |
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| | |
| (1) | | The Refining segment includes the operations of our Navajo, Woods Cross and Tulsa Refineries and Holly Asphalt. The Refining segmentAsphalt 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 produced by the Refining segment 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 effective March 1, 2008 (date of reconsolidation). HEP 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 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 and from HEP’s interest the SLC Pipeline.operations. |
Refining Operating Data
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 7A of Part II of this Form 10-K.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | Years Ended December 31, | |
| | | 2009 | | 2008 | | 2007 | | | 2010 | | 2009 | | 2008 | |
Consolidated | | |
Crude charge (BPD)(1) | | 142,430 | | 100,680 | | 103,490 | | | 221,440 | | 142,430 | | 100,680 | |
Refinery production (BPD)(2) | | 151,420 | | 110,850 | | 113,270 | | |
Refinery throughput (BPD)(2) | | | 234,910 | | 154,940 | | 114,130 | |
Refinery production (BPD)(3) | | | 225,980 | | 151,420 | | 110,850 | |
| Sales of produced refined products (BPD) | | 151,580 | | 111,950 | | 115,050 | | | 228,140 | | 151,580 | | 111,950 | |
Sales of refined products (BPD)(3) | | 155,820 | | 120,750 | | 126,800 | | |
Sales of refined products (BPD)(4) | | | 232,100 | | 155,820 | | 120,750 | |
| | | |
Refinery utilization(4) | | | 78.9 | % | | | 89.7 | % | | | 94.1 | % | |
Refinery utilization(5) | | | | 86.5 | % | | | 78.9 | % | | | 89.7 | % |
| | | |
Average per produced barrel(5) | | |
Average per produced barrel(6) | | |
| Net sales | | $ | 74.06 | | $ | 108.83 | | $ | 89.77 | | | $ | 91.06 | | $ | 74.06 | | $ | 108.83 | |
Cost of products(6) | | 66.85 | | 97.87 | | 73.03 | | |
Cost of products(7) | | | 82.27 | | 66.85 | | 97.87 | |
| | | | | | | | | | | | | | | |
| Refinery gross margin | | 7.21 | | 10.96 | | 16.74 | | | 8.79 | | 7.21 | | 10.96 | |
Refinery operating expenses(7) | | 5.24 | | 5.14 | | 4.43 | | |
Refinery operating expenses(8) | | | 5.08 | | 5.24 | | 5.14 | |
| | | | | | | | | | | | | | | |
| Net operating margin | | $ | 1.97 | | $ | 5.82 | | $ | 12.31 | | | $ | 3.71 | | $ | 1.97 | | $ | 5.82 | |
| | | | | | | | | | | | | | | |
| | | |
| Refinery operating expenses per throughput barrel | | | $ | 4.94 | | $ | 5.12 | | $ | 5.05 | |
| | |
| (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. |
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| | |
(3)(4) | | Includes refined products purchased for resale. |
| |
(4)(5) | | Represents crude charge divided by total crude capacity (BPSD). Our consolidated crude capacity was increased from 109,000111,000 BPSD to 111,000 BPSD in mid-year 2007 (our 2007 Navajo Refinery expansion) and by an additional 5,000116,000 BPSD in the fourth quarter of 2008 (our 2008 Woods Cross Refinery expansion). During 2009, we increased our consolidated crude capacity by 15,000 BPSD in the first quarter ofeffective April 1, 2009 (our 2009 Navajo Refinery expansion), by 85,000 BPSD in the second quarter ofeffective June 1, 2009 (our June 2009 Tulsa Refinery west facility acquisition) and by 40,000 BPSD in the fourth quarter ofeffective December 1, 2009 (our December 2009 Tulsa Refinery east facility acquisition), increasing our consolidated crude capacity to 256,000 BPSD. |
| |
(5)(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 7A of Part II of this Form 10-K. |
| |
(6)(7) | | Transportation costs billed from HEP are included in cost of products. |
| |
(7)(8) | | Represents operating expenses of the refineries, exclusive of depreciation and amortization. |
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Results of Operations — Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
Summary
Net income attributable to Holly Corporation stockholders for the year ended December 31, 2010 was $104 million ($1.95 per basic and $1.94 per diluted share) an $84.4 million increase compared to $19.5 million ($0.39 per basic and diluted share) for the year ended December 31, 2009. Net income increased due principally to increased sales volumes of produced refined products combined with higher refinery gross margins during 2010. Overall refinery gross margins for the year ended December 31, 2010 were $8.79 per produced barrel compared to $7.21 for the year ended December 31, 2009.
Overall production levels for the year ended December 31, 2010 increased by 49% over 2009 due to production from our Tulsa Refinery facilities acquired in June and December 2009 combined with production increases at our Navajo and Woods Cross Refineries. Additionally, 2009 levels reflect lower production during the first quarter of 2009 due to scheduled downtime during a planned major maintenance turnaround at our Navajo Refinery.
Sales and Other Revenues
Sales and other revenues from continuing operations increased 72% from $4,834.3 million for the year ended December 31, 2009 to $8,322.9 million for the year ended December 31, 2010, due principally to the effects of a 51% increase in year-over-year volumes of produced refined products sold combined with increased sales prices of produced refined products. The average sales price we received per produced barrel sold increased 23% from $74.06 for the year ended December 31, 2009 to $91.06 for the year ended December 31, 2010. Sales and other revenues for the years ended December 31, 2010 and 2009, include $35.7 million and $45.2 million, respectively, in HEP revenues attributable to pipeline and transportation services provided to unaffiliated parties.
Cost of Products Sold
Cost of products sold increased 74% from $4,238 million for the year ended December 31, 2009 to $7,367.1 million for the year ended December 31, 2010, due principally to higher crude oil costs combined with a 51% increase in volumes of produced refined products sold. The average price we paid per barrel of crude oil and feedstocks used in production and the transportation costs of moving the finished products to the market place increased 23% from $66.85 for the year ended December 31, 2009 to $82.27 for the year ended December 31, 2010.
Gross Refinery Margins
Gross refining margin per produced barrel increased 22% from $7.21 for the year ended December 31, 2009 to $8.79 for the year ended December 31, 2010, due to an increase in the average sales price we received per produced barrel sold, partially offset by an increase in the average price we paid per produced barrel of crude oil and feedstocks. Gross refining margin does not include the effects of depreciation or amortization. See “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K for a reconciliation to the income statement of prices of refined products sold and costs of products purchased.
Operating Expenses
Operating expenses, exclusive of depreciation and amortization increased 41% from $356.9 million for the year ended December 31, 2009 to $504.4 million for the year ended December 31, 2010, due principally to costs attributable to the operations of our Tulsa Refinery facilities acquired in June and December 2009 and higher refinery utility costs. For the years ended December 2010 and 2009, operating expenses include $52.4 million and $43.5 million, respectively, in costs attributable to HEP operations.
General and Administrative Expenses
General and administrative expenses increased 17% from $60.3 million for the year ended December 31, 2009 to $70.8 million for the year ended December 31, 2010, due principally to costs associated with the support and integration of our Tulsa Refinery operations and increased payroll costs. For the years ended December 31, 2010 and 2009, general and administrative expenses include $5.4 million and $5.3 million, respectively, in costs attributable to HEP operations.
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Depreciation and Amortization Expenses
Depreciation and amortization increased 19% from $98.8 million for the year ended December 31, 2009 to $117.5 million for the year ended December 31, 2010. The increase was due principally to depreciation and amortization attributable to our Tulsa Refinery facilities and capitalized refinery improvement projects in 2009 and 2010. For the years ended December 31, 2010 and 2009, depreciation and amortization expenses include $29.1 million and $26.5 million, respectively, in costs attributable to HEP operations.
Interest Income
Interest income for the year ended December 31, 2010 was $1.2 million compared to $5 million for the year ended December 31, 2009. Interest income was higher for the year ended December 31, 2009 due to interest received on income tax refunds and investments in higher yield marketable debt securities.
Interest Expense
Interest expense was $74.2 million for the year ended December 31, 2010 compared to $40.3 million for the year ended December 31, 2009. The increase was due principally to interest incurred on our $300 million 9.875% senior notes issued in 2009 and HEP’s 8.25% senior notes issued in March 2010. For the years ended December 31, 2010 and 2009, interest expense included $36.3 million and $23.8 million, respectively, in costs attributable to HEP operations.
Income Taxes
Income taxes increased from $7.5 million for the year ended December 31, 2009 to $59.3 million for the year ended December 31, 2010 due to significantly higher pre-tax earnings for the year ended December 31, 2010 compared to 2009. Our effective tax rate, before consideration of earnings attributable to noncontrolling interests was 30.8% for the year ended December 31, 2010 compared to 17% for the year ended December 31, 2009. Our effective tax rate for GAAP disclosure purposes reflects the inclusion of non-taxable earnings attributable to noncontrolling interest holders in the denominator of our effective tax rate computation. Our actual tax rate for income tax purposes did not increase.
Discontinued Operations
On December 1, 2009, HEP sold its 70% interest in Rio Grande resulting in a $14.5 million gain. Rio Grande operations generated net earnings of $4.4 million for the year ended December 31, 2009 before taking into account HEP’s noncontrolling interest in the discontinued operations.
Results of Operations — Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
Summary
Income from continuing operationsNet income attributable to Holly Corporation stockholders for the year ended December 31, 2009 was $15.2$19.5 million ($0.300.39 per basic and diluted share) a $104$101 million decrease compared to $119.2$120.6 million ($2.372.40 per basic and $2.36$2.38 per diluted share) for the year ended December 31, 2008. Income from continuing operationsNet income decreased due principally to an overall decrease in refined gross margins in the second half of 2009. Overall refinery gross margins for the year ended December 31, 2009 were $7.21 per produced barrel compared to $10.96 for the year ended December 31, 2008.
Overall production levels for the year ended December 31, 2009 increased by 37% over 2008 due to production attributable to the operations offrom our recently acquired Tulsa Refinery facilities acquired in June and December 2009 and production gains resulting from our recent Navajo and Woods Cross Refinery capacity expansions. Also impacting production levels was scheduled downtime for major maintenance turnarounds at the Navajo Refinery in the first quarter of 2009 and the Woods Cross Refinery in the third quarter of 2008. During the first quarter of 2009, we timed our Navajo Refinery turnaround to coincide with the completion of its 15,000 BPSD capacity expansion, increasing refining capacity to 100,000 BPSD.
Sales and Other Revenues
Sales and other revenues from continuing operations decreased 18% from $5,860.4 million for the year ended December 31, 2008 to $4,834.3 million for the year ended December 31, 2009, due principally to significantly lower refined product sales prices, partially offset by the effects of a 29% increase in volumes of refined products sold. The volume increase was primarily due to volumes attributable to our Tulsa Refinery operations. The average sales price we received per produced barrel sold decreased 32% from $108.83 for the year ended
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December 31, 2008 to $74.06 for the year ended December 31, 2009. Additionally, direct sales of excess crude oil also decreased in the current year.2009 compared to 2008. Sales and other revenues for the years ended December 31, 2009 and 2008, include $45.5$45.2 million and $19.3 million, respectively, in HEP revenues attributable to pipeline and transportation services provided to unaffiliated parties.
Cost of Products Sold
Cost of products sold decreased 20% from $5,280.7 million in 2008 to $4,238 million in 2009, due principally to the effects of significantly lower crude oil costs, partially offset by the effects of a 29% increase in volumes of refined products sold. The average price we paid per barrel of crude oil and feedstocks used in production and the transportation costs of moving the finished products to the market place decreased 32% from $97.87 infor the year ended December 31, 2008 to $66.85 infor the year ended December 31, 2009.
Gross Refinery Margins
Gross refining margin per produced barrel decreased 34% from $10.96 infor the year ended December 31, 2008 to $7.21 infor the year ended December 31, 2009, due to a decrease in the average sales price we received per produced barrel sold, partially offset by the effects of a decrease in the average price we paid per produced barrel of crude oil and feedstocks. Gross refining margin does not include the effects of depreciation or amortization. See “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K for a reconciliation to the income statement of prices of refined products sold and costs of products purchased.
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Operating Expenses
Operating expenses, exclusive of depreciation and amortization increased 34% from $265.7 million infor the year ended December 31, 2008 to $356.9 million infor the year ended December 31, 2009, due principally to costs attributable to the operations of our Tulsa Refinery commencingfacilities acquired in June 1,and December 2009 and the inclusion of HEP operating expense for a full twelve-month period in 2009 compared to ten months in 2008 due to our reconsolidation of HEP effective March 1, 2008. Additionally, there were certain increased costs at our existing facilities following the recently completed expansions, which were partially offset by lower utility costs. For the years ended December 2009 and 2008, operating expenses included $43.5 million and $33.4 million, respectively, in costs attributable to HEP operations.
General and Administrative Expenses
General and administrative expenses increased 9% from $55.3 million infor the year ended December 31, 2008 to $60.3 million infor the year ended December 31, 2009, due principally to costs associated with the support and integration of our Tulsa Refinery operations, increased payroll costs and increased professional fees and services. Additionally, general and administrative expenses for the years ended December 31, 2009 and 2008 include $5.3 million and $3.7 million, respectively, in costs attributable to HEP operations.
Depreciation and Amortization Expenses
Depreciation and amortization increased 57% from $63 million infor the year ended December 31, 2008 to $98.8 million infor the year ended December 31, 2009. The increase was due principally to depreciation and amortization attributable to our Tulsa Refinery andfacilities, capitalized refinery improvement projects in 2008 and 2009 and the inclusion of HEP depreciation expense for a full twelve-month period during 2009 compared to ten months in 2008. For the yearyears ended December 31, 2009 and 2008, depreciation and amortization expenses included $26.5 million and $18.4 million, respectively, in costs attributable to HEP operations.
Equity in Earnings of SLC Pipeline
HEP has a 25% joint venture interest in the SLC Pipeline that commenced pipeline operations effective March 2009. HEP’s equity in earnings of the SLC the SLC Pipeline was $1.9 million for the year ended December 31, 2009.
Interest Income
Interest income for the year ended December 31, 2009 was $5 million compared to $10.8 million for the year ended December 31, 2008,2008. The decrease was due principally to the effects of a decrease in cash balances and investments in marketable debt securities.securities that was partially offset by interest on income tax refunds received in 2009.
Interest Expense
Interest expense was $40.3 million for the year ended December 31, 2009 compared to $24 million for the year ended December 31, 2008. The increase was due principally to interest attributable to increased long-term debt, including ourthe Holly 9.875% senior notes due 2017 (the “Holly Senior Notes”),Notes issued in 2009, and the inclusion of HEP interest expense for a full twelve-monthtwelve-
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month period during 2009 compared to ten months in 2008. For the yearyears ended December 31, 2009 and 2008, interest expense included $23.8 million and $21.5 million, respectively, in costs attributable to HEP operations. Additionally for the years ended December 31, 2009 and 2008, fair value adjustments attributable to HEP’s interest rate swaps resulted in non-cash interest expense of $.2 million and $2.3 million, respectively.
Acquisition Costs — Tulsa Refineries
During the year ended December 31, 2009, we incurred $3.1 million in acquisition costs related to our June 1, 2009 Tulsa Refinery west facility and our December 1, 2009 Tulsa Refinery east facility acquisitions.
Impairment of Equity Securities
For the year ended December 31, 2008, we recorded an impairment loss of $3.7 million that related to our 1,000,000 shares of Connacher common stock that we received in connection with our sale of the Montana refinery in 2006. This loss represents an other-than-temporary decline in the fair value of these equity securities during the year ended December 31, 2008.
Gain on Sale of HPI
We sold substantially all of the oil and gas properties of Holly Petroleum, Inc. (“HPI”), a subsidiary that previously conducted a small-scale oil and gas exploration and production program, in 2008 for $6 million, resulting in a gain of $6 million.
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Equity in Earnings of HEP
Effective March 1, 2008, we reconsolidated HEP and no longer account for our investment in HEP under the equity method of accounting. Our equity in earnings of HEP for the year ended December 31, 2008 was $3 million representing our pro-rata share of earnings in HEP from January 1 through February 29, 2008.
Income Taxes
Income taxes decreased 88% from $64 million infor the year ended December 31, 2008 to $7.5 million infor the year ended December 31, 2009 due to significantly lower pre-tax earnings infor the year ended December 31, 2009 compared to 2008. Our effective tax rate, before consideration of earnings attributable to noncontrolling interests was 17% compared to 34.1% for the year ended December 31, 2009 compared to 34.1% for 2008. Our effective tax rate calculation was affected by howfor GAAP disclosure purposes reflects the inclusion of non-taxable earnings attributable to noncontrolling interest is classified onholders in the income statement.denominator of our effective tax rate computation. Our actual effective tax rate for income tax purposes did not decline.
Discontinued Operations
On December 1, 2009, HEP sold its 70% interest in Rio Grande resulting in a $14.5 million gain. Rio Grande operations generated net earnings of $4.4 million for the year ended December 31, 2009 compared to $2.9 million for the year ended December 31, 2008. This is presented before taking effect ofinto account HEP’s noncontrolling interest in the discontinued operations.
Noncontrolling Interest in Net Income
Noncontrolling interest holders’ share in earnings of HEP was $33.7 million for the year ended December 31, 2009 compared to $6.1 million in 2008. This increase was due principally to higher HEP earnings in 2009 compared to 2008 including HEP’s gain on the sale of Rio Grande, our decreased ownership in HEP and the inclusion of HEP consolidated results for a full twelve-month period in 2009 compared to ten months in 2008 due to our reconsolidation of HEP effective March 1, 2008.
Results of Operations — Year Ended December 31, 2008 Compared to Year Ended December 31, 2007
Summary
Income from continuing operations attributable to Holly Corporation stockholders for the year ended December 31, 2008 was $119.2 million ($2.37 per basic and $2.36 per diluted share), a $214.9 decrease compared to $334.1 million ($6.09 per basic and $5.98 per diluted share) for the year ended December 31, 2007. Income from continuing operations decreased due principally to reduced refined product margins during the first half of 2008. Overall refinery gross margins for the year ended December 31, 2008 were $10.96 per produced barrel compared to $16.74 for the year ended December 31, 2007.
Sales and Other Revenues
Sales and other revenues from continuing operations increased 22% from $4,791.7 million for the year ended December 31, 2007 to $5,860.4 million for the year ended December 31, 2008, due principally to higher refined product sales prices, partially offset by a 5% decrease in volumes of refined products sold. The average sales price we received per produced barrel sold increased 21% from $89.77 for the year ended December 31, 2007 to $108.83 for the year ended December 31, 2008. The decrease in volumes of refined products sold was principally due to the effects of downtime at our refineries during the second quarter of 2008 and a scheduled major maintenance turnaround at our Woods Cross Refinery during the third quarter of 2008. Additionally, sales and other revenues for the year ended December 31, 2008 include $19.3 million in HEP revenues attributable to pipeline and transportation services provided to unaffiliated parties due to our reconsolidation of HEP effective March 1, 2008. Sales and other revenues for 2007 include $23 million in sulfur credit sales.
Cost of Products Sold
Cost of products sold increased 32% from $4,003.5 million in 2007 to $5,280.7 million in 2008, due principally to significantly higher crude oil costs in the first half of 2008. The average price we paid per barrel of crude oil and feedstocks used in production and the transportation costs of moving the finished products to the market place increased 34% from $73.03 in 2007 to $97.87 in 2008. This increase was partially offset by the effects of a 5% decrease in year-over-year volumes of refined products sold.
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Gross Refinery Margins
Gross refining margin per produced barrel decreased 35% from $16.74 in 2007 to $10.96 in 2008 due to an increase in the average price we paid per produced barrel of crude oil and feedstocks, partially offset by the effects of an increase in the average sales price we received per produced barrel sold. Gross refining margin does not include the effects of depreciation or amortization. See “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K for a reconciliation to the income statements of prices of refined products sold and costs of products purchased.
Operating Expenses
Operating expenses, exclusive of depreciation and amortization increased 27% from $209.3 million in 2007 to $265.7 million in 2008, due principally to the inclusion of $33.4 million in operating costs attributable to HEP as a result of our reconsolidation effective March 1, 2008. Additionally, higher refinery utility and payroll costs along with increased maintenance costs associated with unplanned downtime contributed to this increase.
General and Administrative Expenses
General and administrative expenses decreased 20% from $69.2 million in 2007 to $55.3 million in 2008, due principally to a decrease in equity-based compensation expense which is to some extent affected by our stock price. Additionally, general and administrative expenses for 2008 include $3.7 million in expenses related to HEP operations following our reconsolidation of HEP effective March 1, 2008.
Depreciation and Amortization Expenses
Depreciation and amortization increased 45% from $43.5 million in 2007 to $63 million in 2008, due principally to the inclusion of $18.4 million in depreciation and amortization related to HEP operations following our reconsolidation of HEP effective March 1, 2008 and depreciation attributable to capitalized refinery improvement projects in 2008 and 2007.
Equity in Earnings of HEP
Effective March 1, 2008, we reconsolidated HEP and no longer account for our investment in HEP under the equity method of accounting. Our equity in earnings of HEP was $3 million and $19.1 million for the years ended December 31, 2008 and 2007, respectively.
Impairment of Equity Securities
For the year ended December 31, 2008, we recorded an impairment loss of $3.7 million that relates to our 1,000,000 shares of Connacher common stock that we received in connection with our sale of the Montana refinery in 2006. This loss represents an other-than-temporary decline in the fair value of these equity securities during 2008.
Gain on Sale of HPI
We sold substantially all of the oil and gas properties of HPI, a subsidiary that previously conducted a small-scale oil and gas exploration and production program, in 2008 for $6 million, resulting in a gain of $6 million.
Interest Income
Interest income for the year ended December 31, 2008 was $10.8 million compared to $15.1 million for the year ended December 31, 2007, due principally to the effects of a lower interest rate environment combined with a decrease in investments in marketable debt securities.
Interest Expense
Interest expense was $24 million for the year ended December 31, 2008 compared to $1.1 million for the year ended December 31, 2007. The increase in interest expense was due principally to the inclusion of $21.5 million in interest expense related to HEP operations following our reconsolidation of HEP effective March 1, 2008.
Income Taxes
Income taxes decreased 61% from $165.3 million in 2007 to $64 million in 2008 due to lower pre-tax earnings in 2008 compared to 2007. Our effective tax rate, before consideration of earnings attributable to noncontrolling interests was 34.1% compared to 33.1% for the years ended December 31, 2008 and 2007, respectively. We realized a lower effective tax rate during 2007, due principally to a higher utilization of ULSD tax credits in 2007 that were fully utilized in 2008.
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Discontinued Operations
Rio Grande operations generated net earnings of $2.9 million for the year ended December 31, 2008.
Noncontrolling Interest in Net Income
Noncontrolling interest holders’ share in earnings of HEP was $6.1 million for the year ended December 31, 2008, representing their pro-rata share of HEP earnings for the period from March 1, 2009 (date of HEP reconsolidation) through December 31, 2008.
LIQUIDITY AND CAPITAL RESOURCES
Holly Credit Agreement
We have a $370$400 million senior secured credit agreement expiring in March 2013. In April 2009, we entered into a second amended and restated $300 million senior secured revolving credit agreement that amended and restated our previous credit agreement in its entirety2013 (the “Holly Credit Agreement”) with Bank of America, N.A. as administrative agent and one of a syndicate of lenders (the “Hollylenders. The Holly Credit Agreement”). Additionally, we upsized the credit agreement by $50 million in November 2009 and by an additional $20 million in December 2009 pursuant to the accordion feature. The credit agreementAgreement 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 December 31, 2009.2010. At December 31, 2009,2010, we had no outstanding borrowings and outstanding letters of credit totaling $56.3 million.$71 million under the Holly Credit Agreement. At that level of usage, the unused commitment was $329 million. We entered into an amendment to the Holly Credit Agreement on May 6, 2010 that changed certain financial covenants and provided other enhancements to the agreement.
If any particular lender under the Holly Credit Agreement was $313.7 million at December 31, 2009.
Refinery gross margins were substantially reduced in the 2009 fourth quarter, which resulted in a fourth quarter loss. We expect to be in compliance with the Holly Credit Agreement covenant requirements as long as refinery margins show marked improvement over 2009 fourth quarter levels to be more in line with historical norms. If a situation were to arise in which margins stayed depressed for a prolonged period of time, we could potentially need to renegotiate certain covenants in the Credit Agreement.
There are currently a total of fourteen lenders under the Holly Credit Agreement with individual commitments ranging from $15 million to $47.5 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 is reviewed 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.
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HEP Credit Agreement
At December 31, 2010, HEP hashad a $300 million senior secured revolving credit agreement expiring in August 2011 (the “HEP Credit Agreement”) with an outstanding balance of $159 million. On February 14, 2011, the HEP Credit Agreement was amended, slightly reducing the size from $300 million to $275 million (the “HEP Amended Credit Agreement”). The HEP Amended Credit Agreement expires in February 2016; provided that the HEP Amended Credit Agreement will expire on September 1, 2014 in the event that, on or prior to such date, the 6.25% HEP Senior Notes have not been repurchased, refinanced, extended or repaid. The HEP Amended Credit Agreement is available to fund capital expenditures, investments, acquisitions distribution payments and working capital and / or otherfor general partnership purposes. At December 31, 2009, HEP had outstanding borrowings totaling $206 million under the HEP Credit Agreement, with unused borrowing capacity of $94 million.
HEP’s obligations under the HEP Amended Credit Agreement are collateralized by substantially all of HEP’s assets. HEP assets that are included(presented parenthetically in our Consolidated Balance Sheets at December 31, 2009 consist of $2.5 million in cash and cash equivalents, $6.9 million in trade accounts receivable and other current assets, $458.5 million in properties, plants and equipment, net and $125.2 million in intangible and other assets.Sheets). Indebtedness under the HEP Amended Credit Agreement is recourse to HEP Logistics Holdings, L.P., its general partner, and guaranteed by HEP’s 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. Navajo Pipeline Co., L.P., Navajo Refining Company, L.L.C.HEP’s creditors have no other recourse to our assets. Furthermore, our creditors have no recourse to the assets of HEP and Woods Cross Refining Company, L.L.C., threeits consolidated subsidiaries. During the first quarter of 2010, our subsidiaries, have agreedprevious agreements to indemnify HEP’s controlling partner to the extent it makes any payment in satisfaction of debt service due on up to a $171 million aggregate principal amount of borrowings under the HEP Credit Agreement.Agreement were terminated.
There are currently a total of thirteen lenders under the HEP Credit Agreement with individual commitments ranging from $15 million to $40 million. If any particular lender could not honor its commitment under the HEP Amended 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 Amended Credit Agreement. HEP has not experienced, nor do theydoes it 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.
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Holly Senior Notes Due 2017
In June 2009, we issued $200 million in aggregate principal amount of Holly9.875% senior notes maturing June 15, 2017 (the “Holly 9.875% Senior Notes.Notes”). A portion of the $188$187.9 million in net proceeds received was used for post-closing payments for inventories of crude oil and refined products acquired from Sunoco following the closing of the Tulsa Refinery west facility purchase on June 1, 2009. In October 2009, we issued an additional $100 million aggregate principal amount as an add-on offering to the Holly 9.875% Senior Notes that was used to fund the cash portion of our acquisition of Sinclair’s 75,000 BPSD refinery also located inthe Tulsa Oklahoma.Refinery east facility.
The $300 million aggregate principal amount of Holly Senior Notes mature on June 15, 2017 and bear interest at 9.875%. The Holly Senior Notes 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 Moody’s and Standard & Poor’s 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
TheIn March 2010, HEP issued $150 million in aggregate principal amount of 8.25% senior notes maturing March 15, 2018 (the HEP 8.25% Senior Notes). A portion of the $147.5 million in net proceeds received was used to fund HEP’s $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 principle amount of 6.25% senior notes maturing March 1, 2015 (the “HEP 6.25% Senior Notes”) that are registered with the SECSEC. The HEP 6.25% Senior Notes and bear interest at 6.25% (theHEP 8.25% Senior Notes (collectively, the “HEP Senior Notes”). The HEP Senior Notes are unsecured and impose certain restrictive covenants, including limitations on HEP’s 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 Moody’s and Standard & Poor’s 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.
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Indebtedness under the HEP Senior Notes is recourse to HEP Logistics Holdings, L.P., its general partner, and guaranteed by HEP’s wholly-owned subsidiaries. AnyHowever, 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. Navajo Pipeline Co., L.P., oneHEP’s creditors have no other recourse to our assets. Furthermore, our creditors have no recourse to the assets of HEP and its consolidated subsidiaries. During the first quarter of 2010, our subsidiaries, has agreedprevious agreement to indemnify HEP’s controlling partner to the extent it makes any payment in satisfaction of debt service due on up to $35 million of the principal amount of the HEP 6.25% Senior Notes.Notes was terminated.
Holly Financing Obligation
On October 20, 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 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 ourthese assets on our books and establishedrecorded a liability representing the $40 million in proceeds received. Lease payments under the agreement are applied as a reduction to principal with the remaining portion as interest expense.
HEP Equity Offerings
In November 2009, HEP closed on a public offering ofissued 2,185,000 of its common units including 285,000 common units issued pursuant to the underwriters’ exercise of their over-allotment option.priced at $35.78 per unit. Aggregate net proceeds of $74.9 million were used to fund the cash portion of HEP’s December 1, 2009 asset acquisitions, to repay outstanding borrowings under the HEP Credit Agreement and for general partnership purposes.
Additionally in May 2009, HEP closed a public offering ofissued 2,192,400 of its common units including 192,400 common units issued pursuant to the underwriters’ exercise of their over-allotment option.priced at $27.80 per unit. Net proceeds of $58.4 million were used to repay outstanding borrowings under the HEP Credit Agreement and for general partnership purposes.
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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 andincluding 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, 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 December 31, 2009,2010, we had cash and cash equivalents of $124.6$229.1 million and short-term investments in marketable securities of $1.2$1.3 million.
Cash and cash equivalents increased by $83.8$104.5 million during 2009.the year ended December 31, 2010. Net cash provided by operating activities and financing activities of $211.5$283.3 million and $406.8$34.5 million, respectively, exceeded cash used for investing activities of $534.6213.2 million. Working capital increased by $189.4$55.7 million during 2009.2010.
Cash Flows — Operating Activities
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
Net cash flows provided by operating activities were $283.3 million for the year ended December 31, 2010 compared to $211.5 million for the year ended December 31, 2009, an increase of $71.8 million. Net income for the year ended December 31, 2010 was $133.1 million, an increase of $79.8 million from $53.3 million for the year
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ended December 31, 2009. Non-cash adjustments consisting of depreciation and amortization, deferred income taxes, equity-based compensation expense, gain on sale of assets and interest rate swap adjustments resulted in an increase to operating cash flows of $154.3 million for the year ended December 31, 2010 compared to $130.4 million for the year ended December 31, 2009. Additionally, SLC Pipeline earnings, net of distributions, increased operating cash flows by $0.5 million for the year ended December 31, 2010 compared to a $0.4 million decrease for the year ended December 31, 2009. Changes in working capital items increased cash flows by $24.7 million in 2010 compared to $44 million in 2009. For the year ended December 31, 2010, inventories increased by $96.9 million compared to $17.9 million for 2009. Also for 2010, accounts receivable increased by $228.5 million compared to $474.2 million for 2009 and accounts payable increased by $342.2 million compared to $583.6 million for 2009. Additionally, turnaround expenditures were $35 million and $33.5 million for the years ended December 31, 2010 and 2009, respectively.
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
Net cash flows provided by operating activities were $211.5 million for the year ended December 31, 2009 compared to $155.5 million for the year ended December 31, 2008, an increase of $56 million. Net income for 2009 was $53.3 million, a decrease of $73.3 million from $126.6 million for 2008. Non-cash adjustments consisting of depreciation and amortization, interest rate swap adjustments, deferred income taxes, equity-based compensation, gain on the sale of assets and impairment of equity securities resulted in an increase to operating cash flows of $130.4 million for the year ended December 31, 2009 compared to $104.2 million for the year ended December 31, 2008. Additionally, SLC Pipeline earnings in excess of distributions decreased operating cash flows by $0.4 million in 2009 while distributions in excess of equity in earnings of HEP increased 2008 operating cash flows by $3.1 million. Changes in working capital items increased cash flows by $44 million in 2009 compared to a decrease of $37 million in 2008. For the year ended December 31, 2009, inventories decreasedincreased by $17.9 million compared to an increasea decrease of $15 million for 2008. Also for 2009, accounts receivable increased by $474.2 million compared to a decrease of $332 million for 2008 and accounts payable increased by $583.6 million compared to a decrease of $393.2 million for 2008. Additionally, for 2009, turnaround expenditures were $33.5 million compared to $34.8 million for 2008.
Year Ended December 31, 2008 Compared to Year Ended December 31, 2007
Net cash flows provided by operating activities were $155.5 million for the year ended December 31, 2008 compared to $422.7 million for the year ended December 31, 2007, a decrease of $267.2 million. Net income for 2008 was $126.6 million, a decrease of $207.5 million from $334.1 million for 2007. Additionally, the non-cash items of depreciation and amortization, deferred taxes, equity-based compensation, gain on the sale of HPI and non-cash interest resulting from changes in the fair value of two of HEP’s interest rate swaps, resulted in an increase to operating cash flows of $104.2 million for the year ended December 31, 2008 compared to $76.5 million for the year ended December 31, 2007. Distributions in excess of equity in earnings of HEP decreased to $3.1 million for the year ended December 31, 2008 compared to $3.7 million for the year ended December 31, 2007. Changes in working capital items decreased cash flows by $37 million in 2008 compared to an increase of $15 million in 2007. For the year ended December 31, 2008, inventories decreased by $15 million compared to an increase of $11 million for 2007. Also for 2008, accounts receivable decreased by $332 million compared to an increase of $216.3 million for 2007 and accounts payable decreased by $393.2 million compared to an increase of $264.2 million for 2007. Additionally, for 2008, turnaround expenditures were $34.8 million compared to $2.7 million for 2007.
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Cash Flows — Investing Activities and Planned Capital Expenditures
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
Net cash flows used for investing activities were $213.2 million for the year ended December 31, 2010 compared to $534.6 million for the year ended December 31, 2009, a decrease of $321.4 million. Cash expenditures for properties, plant and equipment for 2010 decreased to $213.2 million compared to $302.6 million for 2009. These include HEP capital expenditures of $25.1 million and $33 million for the years ended December 31, 2010 and 2009, respectively. Capital expenditures were significantly lower in 2010 due to a higher level of capital project initiatives in 2009 including refinery expansion projects. During the year ended December 31, 2009, we paid cash consideration of $267.1 million in connection with the Tulsa Refinery west and east facility acquisitions, invested $175.9 million in marketable securities and received proceeds of $230.3 million from the sale or maturity of marketable securities. Additionally, HEP acquired logistics and storage assets from an affiliate of Sinclair for $25.7 million and made a $25.5 million joint venture contribution to the SLC Pipeline. In December 2009, HEP sold its 70% interest in Rio Grande for $35 million. The cash proceeds received are presented net of Rio Grande’s December 1, 2009 cash balance of $3.1 million.
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
Net cash flows used for investing activities were $534.6 million for 2009 compared to $57.8 million for 2008, an increase of $476.8 million. Cash expenditures for property,properties, plant and equipment for 2009 totaled $302.6 million compared to $418.1 million for 2008. These include HEP capital expenditures of $33 million and $34.3 million for the years ended December 31, 2009 and 2008, respectively. During the year ended December 31, 2009, we paid cash consideration of $267.1 million in connection with our Tulsa Refinery west and east facility acquisitions. Additionally, HEP paid cash consideration of $25.7 million upon its acquisition of logistics and storage assets from an affiliate of Sinclair and made a $25.5 million joint venture contribution to the SLC Pipeline. In December 2009, HEP sold its 70% interest in Rio Grande for $35 million. The cash proceeds received are presented net of Rio
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Grande’s December 1, 2009 cash balance of $3.1 million. Also in 2009, we invested $175.9 million in marketable securities and received proceeds of $230.3 million from sales and maturities of marketable securities. For the year ended December 31, 2008, we invested $769.1 million in marketable securities and received proceeds of $945.5 million from sales and maturities of marketable securities. Additionally in 2008, we received $171$6 million in proceeds from our sale of the Crude PipelinesHPI and Tankage Assets$171 million from our sale of certain crude pipelines and tankage assets to HEP on February 29, 2008 andHEP. We have presented HEP’s March 1, 2008 cash balance of $7.3 million as ana cash inflow as a result of our reconsolidation of HEP effective March 1, 2008.
Year Ended December 31, 2008 Compared to Year Ended December 31, 2007
Net cash flows used for investing activities were $57.8 million for 2008 compared to $293.1 million for 2007, a decrease of $235.3 million. Cash expenditures for property, plant and equipment for 2008 totaled $418.1 million compared to $161.3 million for 2007. Capital expenditures for the year ended December 31, 2008 include $34.3 million attributable to HEP. Also in 2008, we invested $769.1 million in marketable securities and received proceeds of $945.5 million from sales and maturities of marketable securities. Additionally for the year ended December 31, 2008, we received $171 million in proceeds from our sale of the Crude Pipelines and Tankage Assets to HEP on February 29, 2008. We are also presenting HEP’s March 1, 2008 cash balance of $7.3 million as an inflow as a result of our reconsolidation of HEP effective March 1, 2008. For the year ended December 31, 2007, we invested $641.1 million in marketable securities and received proceeds of $509.3 million from sales and maturities 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 year’s capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years. Our total approved capital budget for 20102011 is $159.6$142.4 million. Additionally, capital costs of $38.8$11.7 million have been approved for refinery turnarounds and tank work. We expect to spend approximately $200$185 million in capital costs in 2010,2011, including capital projects approved in prior years. Our capital spending for 20102011 is comprised of $58.5$24 million for projects at the Navajo Refinery, $12.6$13 million for projects at the Woods Cross Refinery, $63.2$70 million for projects at the Tulsa Refinery, $60$69 million for our portion of the UNEV pipelinePipeline project, $2.1$3 million for asphalt plant projects and $3.6$6 million for marketing-related and miscellaneous projects. The following summarizes our key capital projects.
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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. We have also signed a 10-year agreement with a third party for the use ofCurrently, we are using an additionalexisting third-party line for the transfer of gasoline blend stocks which is currently in service.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, we are planning to expandexpanding the diesel hydrotreater unit at the east facility to permit the processing of all high sulfur diesel produced to ULSD, eliminating the need to construct a new diesel hydrotreater at our west facility as previously planned.ULSD. This expansion is expected to cost approximately $20 million and will use the reactor that we acquired as part of the Tulsa Refinery west facility acquisition. We are currently planning to complete the integration projects byin the endsecond quarter of the 2010.2011.
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 approximately $15$28.5 million. Our Tulsa Refinery is required to meet MSAT2 1.3% benzene levels in gasoline beginning in July 2012 and we expect complete this project well before then. 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. We estimatehave previously estimated a cost of $20 million to meet these requirements but our investmentBoard of Directors have approved a larger project for $44 million which would meet these requirements as well as increase our ability to comply withrun additional lower priced sour crude types at the requirements will be approximately $20 million. The consent decree also requires shutdown, replacement, or installation of low NOx burners in three low pressure boilers by the end of 2013. WeTulsa Refinery east facility. Also, we are still evaluating the best solution to thisthe low pressure boiler issue.
We believe that In addition to the synergy of the Tulsa Refinery westconsent decree requirements, flare gas recovery and east facilities operated as a single integrated facility will result in savings of approximately $110 million of expected capital expenditures relatedcoker blowdown modifications are required to ULSD compliance. Also as a result of the integrated facility, we expect to be able to reduce capital expenditures for the forthcoming benzene in gasoline requirements from approximately $30 million for the Tulsa Refinery west facility alone to approximately $15 million for the integrated complex. Even if we are able to realize the operating synergies of the integrated facility, our Tulsa Refinery will still require sulfur recovery investment, but we estimate combining the two refineries will reduce our net near-term capital expenditure requirements by approximately $125 million, excluding the cost to construct the pipelines that will integrate the west and east facilities.
Phase I of our Navajo Refinery major capital projects was mechanically completed in March 2009 increasing refinery capacity to 100,000 BPSD effective April 1, 2009. Phase I required the installation of acomply with new 15,000 BPSD mild hydrocracker, 28 MMSCFSD hydrogen plant and the expansion of our Lovington crude and vacuum unitsflare regulations at aan estimated cost of approximately $190$10 million.
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We are nearing completion of phase II of the major capital projects at the Navajo Refinery. These improvements will provide the capability to process up to 40,000 BPSD of heavy type crudes. Phase II involves the installation of a new 18,000 BPSD solvent deasphalter and the revamp of our Artesia crude and vacuum units. The solvent deasphalter unit was complete in the fourth quarter of 2009 and is in operation. The crude / vacuum unit revamp is expected to be to be completed in the first quarter of 2010. We expect the phase II project to cost approximately $100 million.
We are also proceeding with a project to add asphalt tankage at the Navajo Refinery and at the Holly Asphalt facility in Artesia, New Mexico to enhance asphalt economics by storing asphalt during the winter months when asphalt prices are generally lower. These asphalt tank additions and an approved upgrade of our rail loading facilities at the Artesia refinery are estimated to cost $21 million and are expected to be completed about the same time as the phase II projects.
The Navajo Refinery currently plans to comply with the new MSAT2 regulations by the fractionation of raw naphtha with existing equipment to achieve benzene in gasoline levels below 1.3%. The Navajo Refinery will purchase or use credits fromgenerated at the Woods Cross and Tulsa Refineries in orderRefinery to reduce benzene downcontent 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 20122011 to comply with the MSAT2 regulationregulations because we have lost ourno longer qualify for the small refiner’s exemption and as a large refinerexemption. Also, we have 30 months to comply.
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At the Woods Cross Refinery, we increased the refinery’s capacity from 26,000 BPSD to 31,000 BPSD while increasing its ability to process lower cost crude. The project involvedwill be installing a new 15,000 BPSD mild hydrocracker, sulfur recovery facilities, black wax desalting equipmentstorm water surge tank and black wax unloading systems. The totalupgrade several other processes at the refinery’s Artesia waste water treatment plant. These projects are expected to cost of this project was approximately $122$17 million. The projects were mechanically complete in the fourth quarter of 2008.
Our Woods Cross refineryRefinery 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 Woods Crossthe refinery involves revamping its naphtha fractionation unit and installing a new reformate splitter and a benzene saturation unit at an estimated cost of $18$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 20122011 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. The current total cost of the pipeline project including terminals is expected to be $275approximately $325 million, with our share of the cost totaling $206$244 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 second 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.
We currently anticipate that all regulatory approvals required to commence the construction of the UNEV Pipeline will be received by the end of the second quarter of 2010. Once such approvals are received, construction of the pipeline will take approximately nine months. Under this schedule, the pipeline would become operational during the first quarter of 2011.
In August 2005, the Energy Policy Act of 2005 (“2005 Act”) was signed into law. Among other things, the 2005 Act created tax incentives for refiners by providing for an immediate deduction of 50% of certain refinery capacity expansion costs when the expansion assets are placed in service. We believe that our 2009 Navajo Refinery capacity expansion project will qualify for this deduction.
Regulatory compliance items such as the ULSD and LSG requirements mentioned above, 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 HEP’s 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, HEP’s planned capital expenditures for a given year consist of expenditures approved for capital projects included in theirits current year’syear capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years. The 20102011 HEP capital budget is comprised of $4.8$5.8 million for maintenance capital expenditures and $6$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 $28 million with completion in the second quarter 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.
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Cash Flows — Financing Activities
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
Net cash flows provided by financing activities were $34.5 million for the year ended December 31, 2010 compared to $406.8 million for the year ended December 31, 2009, a decrease of $372.3 million. During 2010, we received and repaid $310 million in advances under the Holly Credit Agreement, paid $1 million under our financing obligation to Plains, purchased $1.4 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 $31.9 million in dividends, received a $23.5 million contribution from our UNEV Pipeline joint venture partner and recognized $1.1 million excess tax expense on our equity based compensation. Also during this period, HEP received $147.5 million in net proceeds upon the issuance of the HEP 8.25% Senior Notes, received $66 million and repaid $113 million under the HEP Credit Agreement, paid distributions of $48.5 million to noncontrolling interests and purchased $2.7 million in HEP common units in the open market for recipients of its restricted unit grants. Additionally, $3.1 million in deferred financing costs were incurred in connection with the issuance of the HEP 8.25% Senior Notes in March 2010 and an amendment to the Holly Credit Agreement. During 2009, we received $287.9 million in net proceeds upon the issuance of the Holly 9.875% Senior Notes, received and repaid $94 million in advances under the Holly Credit Agreement, received $40 million under a financing transaction with Plains, paid $30.1 million in dividends, purchased $1.2 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 $15.2 million contribution from our UNEV Pipeline joint venture partner and recognized $1.2 million in excess taxes on our equity based compensation. Also during this period, HEP received proceeds of $133 million upon the issuance of additional common units, received $239 million and repaid $233 million in advances under the HEP Credit Agreement and paid distributions of $33.2 million to noncontrolling interests. Additionally, we paid $8.8 million in deferred financing costs during the year ended December 31, 2009 that relate to the Holly Senior Notes issued in June 2009.
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
Net cash flows provided by financing activities were $406.8 million for the year ended December 31, 2009 compared to net cash flows used for financing activities of $151.3 million for the year ended December 31, 2008, an increase of $558.1 million. During 2009, we received $287.9 million in net proceeds upon the issuance of the Holly 9.875% Senior Notes, received and repaid $94 million in advances under the Holly Credit Agreement, received $40 million under a financing transaction with Plains, paid $30.1 million in dividends, purchased $1.2 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 $15.2 million contribution from our UNEV Pipeline joint venture partner and recognized $1.2 million in excess taxes on our equity based compensation. Also during this period, HEP received proceeds of $133 million upon the issuance of additional common units, received $239 million and repaid $233 million in advances under the HEP Credit Agreement and paid distributions of $33.2 million to noncontrolling interest holders. Additionally, we paid $8.8 million in deferred financing costs during the year ended December 31, 2009 that relate to the Holly Senior Notes issued in June 2009. For the period from March 1, 2008 through December 31, 2008, HEP had net short-term borrowings of $29 million under the HEP Credit Agreement and purchased $0.8 million in HEP common units in the open market for restricted unit grants. Additionally in 2008, we paid an aggregate of $0.9 million in deferred financing costs related to the amendment and restatement of the Holly Credit Agreement and the HEP Credit Agreement. Under our common stock repurchase program, we purchased treasury stock of $151.1 million in 2008. We also paid $29.1 million in dividends, received a $17 million contribution from our UNEV Pipeline joint venture partner, received $1 million for common stock issued upon exercise of stock options and recognized $5.7 million in excess tax benefits on our equity based compensation during 2008. Also during this period, HEP paid $22.1 million in distributions to its noncontrolling interest holders.
Year Ended December 31, 2008 Compared to Year Ended December 31, 2007
Net cash flows used for financing activities were $151.3 million for 2008 compared to $189.4 million for 2007, a decrease of $38.1 million. For the period from March 1, 2008 through December 31, 2008, HEP had net short-term borrowings of $29 million under the HEP Credit Agreement and purchased $0.8 million in HEP common units in the open market for restricted unit grants. Additionally in 2008, we paid an aggregate of $0.9 million in deferred financing costs related to the amendment and restatement of the Holly Credit Agreement and the HEP Credit Agreement. Under our common stock repurchase program, we purchased treasury stock of $151.1 million in 2008. We also paid $29.1 million in dividends, received a $17 million contribution from our UNEV Pipeline joint venture partner, received $1 million for common stock issued upon exercise of stock options and recognized $5.7 million in excess tax benefits on our equity based compensation during 2008. Also during this period, HEP paid $22.1 million in distributions to its noncontrolling interest holders. During 2007, we purchased treasury stock of $207.2 million under our stock repurchase program, paid $23.2 million in dividends, received $2.3 million for common stock issued upon exercise of stock options and recognized $30.4 million in excess tax benefits on our equity based compensation. During 2007, we also received an $8.3 million contribution from our UNEV Pipeline joint venture partner.
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Contractual Obligations and Commitments
The following table presents our long-term contractual obligations as of December 31, 20092010 in total and by period due beginning in 2010.2011. The table below does not include our contractual obligations to HEP under our long-term transportation agreements as these related-party transactions are eliminated in the Consolidated Financial Statements. A description of these agreements is provided under “Holly Energy Partners, L.P.” under Items 1 and 2, “Business
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“Business and Properties.” Also, the table below does not reflect renewal options on our operating leases that are likely to be exercised.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Payments Due by Period | | | Payments Due by Period | |
| | | Less than | | Over | | | Less than | | Over | |
| Contractual Obligations and Commitments | | Total | | 1 Year | | 1-3 Years | | 3-5 Years | | 5 Years | | | Total | | 1 Year | | 1-3 Years | | 3-5 Years | | 5 Years | |
| | | (In thousands) | | | (In thousands) | |
Holly Corporation(1)(2) | | |
Long-term debt — principal(3) | | $ | 339,809 | | $ | 1,029 | | $ | 2,469 | | $ | 3,143 | | $ | 333,168 | | | $ | 338,781 | | $ | 1,160 | | $ | 2,786 | | $ | 3,547 | | $ | 331,288 | |
Long-term debt — interest(4) | | 267,398 | | 34,397 | | 68,381 | | 67,707 | | 96,913 | | | 233,001 | | 34,265 | | 68,064 | | 67,304 | | 63,368 | |
Transportation agreements(5) | | | 344,921 | | 35,191 | | 70,380 | | 70,380 | | 168,970 | |
Hydrogen supply agreement(5)(6) | | | 81,851 | | 6,548 | | 13,096 | | 13,096 | | 49,111 | |
| Operating leases | | 40,116 | | 10,448 | | 14,130 | | 6,827 | | 8,711 | | | 41,504 | | 9,831 | | 13,177 | | 8,638 | | 9,858 | |
Hydrogen supply agreement(5)(6) | | 82,866 | | 6,138 | | 12,276 | | 12,276 | | 52,176 | | |
Other service agreements(6) | | 131,293 | | 12,672 | | 25,121 | | 25,121 | | 68,379 | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | 861,482 | | 64,684 | | 122,377 | | 115,074 | | 559,347 | | | 1,040,058 | | 86,995 | | 167,503 | | 162,965 | | 622,595 | |
| | | |
Holly Energy Partners | | |
Long-term debt — principal(7) | | 391,000 | | — | | 206,000 | | — | | 185,000 | | | 494,000 | | — | | — | | 185,000 | | 309,000 | |
Long-term debt — interest(8) | | 71,415 | | 15,643 | | 26,866 | | 23,125 | | 5,781 | | | 161,228 | | 27,134 | | 54,269 | | 48,488 | | 31,337 | |
| Pipeline operating and right of way leases | | 47,646 | | 6,264 | | 12,516 | | 12,451 | | 16,415 | | | 42,424 | | 6,545 | | 12,954 | | 12,839 | | 10,086 | |
| Other agreements | | 7,626 | | 837 | | 1,149 | | 960 | | 4,680 | | | 9,814 | | 1,135 | | 2,120 | | 2,120 | | 4,439 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | 707,466 | | 34,814 | | 69,343 | | 248,447 | | 354,862 | |
| | | 517,687 | | 22,744 | | 246,531 | | 36,536 | | 211,876 | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | |
| Total | | $ | 1,379,169 | | $ | 87,428 | | $ | 368,908 | | $ | 151,610 | | $ | 771,223 | | | $ | 1,747,524 | | $ | 121,809 | | $ | 236,846 | | $ | 411,412 | | $ | 977,457 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | |
| (1) | | Amounts shown do not include obligations under a 10-year crude oil transportation agreement. Our obligations under the agreement are subject to certain conditions including completion of construction projects by the transportation company. We expect the shipping commitment to begin in the first quarter of 2011 upon the expected completion date of the projects. |
|
(2) | | We may be required to make cash outlays related to our unrecognized tax benefits. However, due to the uncertainty of the timing of future cash flows associated with our unrecognized tax benefits, we are unable to make reasonably reliable estimates of the period of cash settlement, if any, with the respective taxing authorities. Accordingly, unrecognized tax benefits of $2 million as of December 31, 20092010 have been excluded from the contractual obligations table above. For further information related to unrecognized tax benefits, see Note 1314 to the Consolidated Financial Statements. |
|
| (2) | | Amounts shown do not include commitments to deliver barrels of crude oil held for other parties at our refineries. We periodically hold crude oil owned by third parties in the storage tanks at our refineries, which may be run through production. We will be obligated to deliver these stored barrels of crude oil upon the other party’s request. |
| |
| (3) | | Our long-term debt consists of the $300 million principal balance on the Holly 9.875% Senior Notes and a long-term financing obligation having a principal balance of $39.8$38.8 million at December 31, 2009.2010. |
| |
| (4) | | Interest payments consist of interest on the 9.875% Holly Senior Notes and on our long-term financing obligation. |
| |
| (5) | | Consists of contractual obligations under agreements with third parties for the transportation of crude oil, natural gas and feedstocks to our refineries under contracts expiring between 2016 and 2024. |
|
| (6) | | We have entered into a long-term supply agreement to secure a hydrogen supply source for our Woods Cross hydrotreater unit. The contract commits us to purchase a minimum of 5 million standard cubic feet of hydrogen per day at market prices through 2023. The contract also requires the payment of a base facility charge for use of the supplier’s facility over the supply term. We have estimated the future payments in the table above using current market rates. Therefore, actual amounts expended for this obligation in the future could vary significantly from the amounts presented above. |
| |
(6) | | Includes: $131.2 million for transportation of natural gas and feedstocks to our refineries under contracts expiring between 2016 and 2024; and various service contracts with expiration dates through 2011. |
|
| (7) | | HEP’s long-term debt consists of the $150 million and the $185 million principal balancebalances on the 8.25% and 6.25% HEP Senior Notes and $206$159 million of outstanding principal under the HEP Credit Agreement. The HEP Credit Agreement was amended on February 14, 2011. The HEP Amended Credit Agreement expires in 2016. |
| |
| (8) | | Interest payments consist of interest on the 6.25% and 8.25% HEP Senior Notes and interest on long-term debt under the HEP Credit Agreement. Interest under the credit agreement debt is based on an effective interest rate of 1.98%5.49% at December 31, 2009.2010. |
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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 GAAP. 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. We consider the following policies to be the most critical to understanding the judgments that are involved and the uncertainties that could impact our results of operations, financial condition and cash flows. For additional information, see Note 1 to the Consolidated Financial Statements “Description of Business and Summary of Significant Accounting Policies.”
Inventory Valuation
Our crude oil and refined product inventories are stated at the lower of cost or market. Cost is determined using the LIFO inventory valuation methodology and market is determined using current estimated selling prices. Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. In periods of rapidly declining prices, LIFO inventories may have to be written down to market due to the higher costs assigned to LIFO layers in prior periods. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years when inventory volumes decline and result in charging cost of sales with LIFO inventory costs generated in prior periods. As of December 31, 2009,2010, many of our LIFO inventory layers were valued at historical costs that were established in years when price levels were generally lower; therefore, our results of operation are less sensitive to current market price reductions. As of December 31, 2009,2010, the excess of current cost over the LIFO inventory value of our crude oil and refined product inventories was $207$284 million. An actual valuation of inventory under the LIFO method can be made only at the end of each year based on the inventory levels at that time. Accordingly, interim LIFO calculations are based on management’s estimates of expected year-end inventory levels and are subject to the final year-end LIFO inventory valuation.
Deferred Maintenance Costs
Our refinery units require regular major maintenance and repairs that are commonly referred to as “turnarounds.” Catalysts used in certain refinery processes also require routine “change-outs.” The required frequency of the maintenance varies by unit and by catalyst, but generally is every two to five years. In order to minimize downtime during turnarounds, we utilize contract labor as well as our maintenance personnel on a continuous 24 hour basis. Whenever possible, turnarounds are scheduled so that some units continue to operate while others are down for maintenance. We record the costs of turnarounds as deferred charges and amortize the deferred costs over the expected periods of benefit.
Long-lived Assets
We calculate depreciation and amortization based on estimated useful lives and salvage values of our assets. When assets are placed into service, we make estimates with respect to their useful lives that we believe are reasonable. However, factors such as competition, regulation or environmental matters could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization. We evaluate long-lived assets for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset’s carrying value exceeds its fair value. Estimates of future discounted cash flows and fair values of assets require subjective assumptions with regard to future operating results and actual results could differ from those estimates. No impairments of long-lived assets were recorded during the years ended December 31, 2010, 2009 2008 and 2007.2008.
Variable Interest Entity
HEP is a VIE whichas defined under GAAPGAAP. A VIE is defined as a legal entity whose equity owners do not have sufficient equity at risk or a controlling interest in the entity, or have voting rights that are not proportionate to their economic interest. Under GAAP,As the general partner of HEP, we have the sole ability to direct the activities of HEP that most significantly impact HEP’s acquisition of the Crude Pipelineseconomic performance. Additionally, since our obligation to absorb losses and Tankage Assets in 2008 qualified as a reconsideration event wherebyreceive benefits from HEP are significant to HEP, we reassessed our beneficial interest in HEPare HEP’s primary beneficiary and determined that HEP continued to qualify as a VIE, and furthermore, determined that our beneficial interest in HEP exceeded 50%. Accordingly,therefore we consolidate HEP.
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We reconsolidated HEP effective March 1, 2008, following its acquisition of our crude pipeline and no longer accounttankage assets (see Note 3 to the Consolidated Financial Statements). Prior to March 1, 2008, we accounted for our investment in HEP underusing the equity method of accounting. As a result,accounting whereby we recorded our consolidated financial statements include the resultspro-rata share of earnings in HEP.
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Additionally, HEP’s 2009 asset acquisitions Contributions to and thedistributions from HEP May and November 2009 equity offerings qualifiedwere recorded as reconsideration events. Following each of these transactions, we reassessedadjustments to our beneficial interest in HEP and determined that HEP continued to qualify as a VIE and that our beneficial interest exceeds 50%.investment balance.
Contingencies
We are subject to proceedings, lawsuits and other claims related to environmental, labor, product and other matters. We are required to assess the likelihood of any adverse judgments or outcomes to these matters as well as potential ranges of probable losses. A determination of the amount of reserves required, if any, for these contingencies is made after careful analysis of each individual issue. The required reserves may change in the future due to new developments in each matter or changes in approach such as a change in settlement strategy in dealing with these matters.
New Accounting Pronouncements
In June 2009, new accounting standards were issued that replace the previous quantitative-based risk and rewards calculation provided under GAAP with a qualitative approach in determining whether an entity is the primary beneficiary of a VIE. Additionally, these standards require an entity to assess on an ongoing basis whether it is the primary beneficiary of a VIE and enhances disclosure requirements with respect to an entity’s involvement in a VIE. These standards are effective January 1, 2010 and will not have a material impact on our financial condition, results of operations and cash flows.
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.
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; and |
|
| • | | prices of refined products. |
As of December 31, 2010, we have outstanding commodity price swap contracts serving as economic hedges to protect the value of a temporary crude oil inventory build of 120,000 barrels against price volatility. These contracts are measured quarterly at fair value with offsetting adjustments (gains / losses) recorded directly to cost of products sold.
We also have outstanding price swap contracts that fix our purchase price on forecasted natural gas purchases aggregating of 1,500,000 MMBTUs to be ratably purchased between January and March 2011 at a weighted-average cost of $4.20 per MMBTU. These price swap contracts have been designated as cash flow hedges and mature in March 2011.
Under hedge accounting, a cash flow hedge is adjusted quarterly to fair value with offsetting fair value adjustments to other comprehensive income. These fair value adjustments (gains / losses) are later reclassified into earnings as the hedging instrument matures. Also on a quarterly basis, hedge effectiveness is measured by comparing the change in fair value of the swap contracts against the expected future cash inflows/outflows on the respective transaction being hedged. Any ineffectiveness is reclassified from accumulated other comprehensive income into earnings.
Interest Rate Risk Management
HEP uses interest rate swaps (derivative instruments) to manage its exposure to interest rate risk.
As of December 31, 2009, HEP has three interest rate swap contracts.
2010, HEP has an interest rate swap to hedgecontract that hedges its exposure to the cash flow risk caused by the effects of changes in the London Interbank BorrowedOffered Rate (“LIBOR”) changes on the $171a $155 million HEP Credit
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Agreement advance that was used to finance HEP’s purchase of the Crude Pipelines and Tankage Assets from us.advance. This interest rate swap effectively converts the $171$155 million of LIBOR based debt to fixed rate debt having an interest rate of 3.74% plus an applicable margin currentlyof 1.75%, which equaled an effective interest rate of 5.49% as of December 31, 2009.2010. 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 designated thisCredit 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 asagreement having a cash flow hedge. Based onnotional amount of $16 million for $1.1 million. Upon payment, HEP reduced its assessment of effectiveness using the change in variable cash flows method, HEP determined that this interest rate swap is effective in offsetting the variability in interest payments on the $171liability and reclassified a $1.1 million variable rate debt resulting from changes in LIBOR. Under hedge accounting, HEP adjusts the cash flow hedge on a quarterly basis to its fair value with the offsetting fair value adjustment to accumulated other comprehensive income. Also on a quarterly basis, HEP measures hedge effectiveness by comparing the present value of the cumulative change in the expected future interest to be paid or received on the variable leg of the swap against the expected future interest payments on the $171 million variable rate debt. Any ineffectiveness is reclassifiedcharge from accumulated other comprehensive incomeloss to interest expense. As of December 31, 2009, HEP had no ineffectiveness on its cash flow hedge.
HEP also has an interest rate swap contract that effectively converts interest expense, associated with $60 million of the HEP Senior Notes from fixed to variable rate debt (“Variable Rate Swap”). Under this swap contract, interest on the $60 million notional amount is computed using the three-month LIBOR plus a spread of 1.1575%, which equaled an effective interest rate of 1.41% as of December 31, 2009. The maturity date of this swap contract is March 1, 2015, matching the maturity of the HEP Senior Notes.
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In October 2008, HEP entered into an additional interest rate swap contract, effective December 1, 2008, that effectively unwinds the effects of the Variable Rate Swap discussed above, converting $60 million of its hedged long-term debt back to fixed rate debt (“Fixed Rate Swap”). Under the Fixed Rate Swap, interest on a notional amount of $60 million is computed at a fixed rate of 3.59% versus three-month LIBOR which when added to the 1.1575% spread on the Variable Rate Swap results in an effective fixed interest rate of 4.75%. The maturity date of this swap contract is December 1, 2013.
Prior to the execution of HEP’s Fixed Rate Swap, the Variable Rate Swap was designated as a fair value hedge of $60 million in outstanding principal under the HEP Senior Notes. HEP dedesignated this hedge in October 2008. At that time, the carrying balance of the HEP Senior Notes included a $2.2 million premium due torepresenting the application of hedge accounting until the dedesignation date. This premium is being amortized as a reductionprior to interest expense over the remaining termsettlement.
The following table presents balance sheet locations and related fair values of the Variable Rate Swap.outstanding derivative instruments.
HEP’s interest rate swaps not having a “hedge” designation are measured quarterly at fair value either as an asset or a liability in the consolidated balance sheets with the offsetting fair value adjustment to interest expense. For the years ended December 31, 2009 and 2008, HEP recognized an increase of $0.2 million and $2.3 million, respectively, in interest expense as a result of fair value adjustments to its interest rate swaps.| | | | | | | | | | | | | |
| | | Balance Sheet | | | | | | Location of | | Offsetting | |
| Derivative Instruments | | Location | | Fair Value | | | Offsetting Balance | | Amount | |
| | | (Dollars in thousands) | |
December 31, 2010 | | | | | | | | | | | | |
Derivatives 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 | | $ | 497 | |
| | | | | | | | | | | |
December 31, 2009 | | | | | | | | | | | | |
Derivative designated as cash flow hedging instrument: | | | | | | | | | | | | |
| Variable-to-fixed interest rate swap contract ($171 million LIBOR based debt interest payments) | | Other long-term liabilities | | $ | 9,141 | | | Accumulated other comprehensive loss | | $ | 9,141 | |
| | | | | | | | | | | |
Derivatives not designated as hedging instruments: | | | | | | | | | | | | |
| Fixed-to-variable interest rate swap contract ($60 million of HEP 6.25% Senior Notes) | | Other assets | | $ | 2,294 | | | Long-term debt | | $ | 1,791 | (1) |
| | | | | | | | | Equity | | | 503 | (2) |
| | | | | | | | | | | |
| | | | | $ | 2,294 | | | | | $ | 2,294 | |
| | | | | | | | | | | |
| Variable-to-fixed interest rate swap contract ($60 million of HEP 6.25% Senior Notes) | | Other long-term liabilities | | $ | 2,555 | | | Equity | | $ | 2,555 | (2) |
| | | | | | | | | | | |
HEP records interest expense equal to the variable rate payments under the swaps. Receipts under the swap agreements are recorded as a reduction of interest expense.Additional information on HEP’s interest rate swaps as of December 31, 2009 is as follows:
| | | | | | | | | | | | | |
| | | Balance Sheet | | | | | | Location of Offsetting | | | |
| Interest Rate Swaps | | Location | | Fair Value | | | Balance | | Offsetting Amount | |
| | | | | (In thousands) | | | |
Asset | | | | | | | | | | | | |
| Fixed-to-variable interest rate swap — | | Other assets | | $ | 2,294 | | | Long-term debt — HEP | | $ | (1,791 | )(1) |
| $60 million of 6.25% HEP Senior Notes | | | | | | | | Equity | | | (1,942 | )(2) |
| | | | | | | | | Interest expense | | | 1,439 | (3) |
| | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | $ | 2,294 | | | | | $ | (2,294 | ) |
| | | | | | | | | | | |
Liability | | | | | | | | | | | | |
Cash flow hedge — $171 million
LIBOR based debt | | Other long-term liabilities | | $ | (9,141 | ) | | Accumulated other comprehensive loss | | $ | 9,141 | |
| | | | | | | | | | | | | |
| Variable-to-fixed interest rate swap — | | Other long-term liabilities | | | | | | Equity | | | 4,166 | (2) |
| $60 million | | | | | (2,555 | ) | | Interest expense | | | (1,611 | ) |
| | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | $ | (11,696 | ) | | | | $ | 11,696 | |
| | | | | | | | | | | |
| | |
| (1) | | Represents unamortized balance of a deferred hedge premium attributable to HEP’s fair value hedge that was dedesignated hedge premium.in 2008 that is being amortized as a reduction to interest expense over the remaining term of the HEP 6.25% Senior Notes. |
| |
| (2) | | Represents prior year charges to interest expense. |
|
(3) | | Net of amortization of premium attributable to dedesignated hedge. |
On January 29,For the year ended December 31, 2010, we recognized a $1.3 million charge to cost of products sold and a $0.4 million charge to operating expenses that are attributable to losses resulting from fair value changes to our commodity price swap contracts.
For the years ended December 31, 2010, 2009 and 2008, HEP received notice fromrecognized $1.5 million, $0.2 million and $2.3 million, respectively, in charges to interest expense as a result of fair value changes to its interest rate swap contracts.
There was no ineffectiveness on the counterparty that it is exercising its option to cancelcash flow hedges during the Variable Rate Swap on March 1, 2010, pursuant to the terms of the swap contract. HEP will receive a cancellation premium of $1.9 million.periods covered in these consolidated financial statements.
HEP reviews publiclyPublicly available information is reviewed on itsthe counterparties in order to review and monitor their financial stability and assess their ongoing ability to honor their commitments under the interest rate swap contracts. These counterparties
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consist of large financial institutions. HEP hasWe have not experienced, nor does itdo we expect to experience, any difficulty in the counterparties honoring their respective 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.
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At December 31, 2009,2010, outstanding principal under the Holly 9.875% Senior Notes, HEP 6.25% Senior Notes and HEP 8.25% Senior Notes werewas $300 million, and $185 million and $150 million, respectively. By means of HEP’s interest rate swap contracts, HEP has effectively converted the 6.25%For these fixed rate on $60 million of the HEP Senior Notes to a fixed rate of 4.75%. For the fixed rate Holly and HEP Senior Notes,notes, changes in interest rates wouldwill generally affect fair value of the debt, but not our earnings or cash flows. At December 31, 2009,2010, the estimated fair valuevalues of the Holly 9.875% Senior Notes, HEP 6.25% Senior Notes and the HEP 8.25% Senior Notes were $318$327 million, $183.2 million and $177.6$156.8 million, respectively. We estimate that a hypothetical 10% change in the yield-to-maturity rates applicable to the seniorthese notes would result in an approximatea fair value change of $9.9 million to the Holly Senior Notesnotes of approximately $13 million, $4.3 million and a $5.5$6.3 million, change to the HEP Senior Notes.respectively.
For the variable rate HEP Credit Agreement, changes in interest rates would affect cash flows, but not the fair value. At December 31, 2009,2010, borrowings outstanding under the HEP Credit Agreement were $206$159 million. By means of its cash flow hedge, HEP has effectively converted the variable rate on $171$155 million of outstanding principal to a fixed rate of 5.49%. For the unhedged $35$4 million portion, a hypothetical 10% change in interest rates applicable to the HEP Credit Agreement would not materially affect cash flows.
At December 31, 2009,2010, 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 7A. | | Item 7A. Quantitative and Qualitative Disclosures About Market Risk |
See “Risk Management” under “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles
Reconciliations of 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 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, with the exception of EBITDA from discontinued operations.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 from continuing operations.
| | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | | | | | | | | | | | |
| | | 2009 | | 2008 | | 2007 | | | Years Ended December 31, | |
| | | (In thousands) | | | 2010 | | 2009 | | 2008 | |
| | | | (In thousands) | |
| Income from continuing operations | | $ | 36,343 | | $ | 123,718 | | $ | 334,128 | | | $ | 133,051 | | $ | 36,343 | | $ | 123,718 | |
| Subtract noncontrolling interest in income from continuing operations | | | (21,134 | ) | | | (4,512 | ) | | — | | | | (29,087 | ) | | | (21,134 | ) | | | (4,512 | ) |
| Add income tax provision | | 7,460 | | 64,028 | | 165,316 | | | 59,312 | | 7,460 | | 64,028 | |
| Add interest expense | | 40,346 | | 23,955 | | 1,086 | | | 74,196 | | 40,346 | | 23,955 | |
| Subtract interest income | | | (5,045 | ) | | | (10,797 | ) | | | (15,089 | ) | | | (1,168 | ) | | | (5,045 | ) | | | (10,797 | ) |
| Add depreciation and amortization | | 98,751 | | 62,995 | | 43,456 | | | 117,529 | | 98,751 | | 62,995 | |
| | | | | | | | | | | | | | | |
| EBITDA from continuing operations | | $ | 156,721 | | $ | 259,387 | | $ | 528,897 | | | $ | 353,833 | | $ | 156,721 | | $ | 259,387 | |
| | | | | | | | | | | | | | | |
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 an 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.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | Years Ended December 31, | |
| | | 2009 | | 2008 | | 2007 | | | 2010 | | 2009 | | 2008 | |
| Average per produced barrel: | | |
| | | |
Navajo Refinery | | |
| Net sales | | $ | 73.15 | | $ | 108.52 | | $ | 89.68 | | | $ | 90.37 | | $ | 73.15 | | $ | 108.52 | |
| Less cost of products | | 65.95 | | 98.97 | | 74.10 | | | 83.12 | | 65.95 | | 98.97 | |
| | | | | | | | | | | | | | | |
| Refinery gross margin | | $ | 7.20 | | $ | 9.55 | | $ | 15.58 | | | $ | 7.25 | | $ | 7.20 | | $ | 9.55 | |
| | | | | | | | | | | | | | | |
| | | |
Woods Cross Refinery | | |
| Net sales | | $ | 70.25 | | $ | 110.07 | | $ | 90.09 | | | $ | 94.26 | | $ | 70.25 | | $ | 110.07 | |
| Less cost of products | | 58.98 | | 93.47 | | 69.40 | | | 75.54 | | 58.98 | | 93.47 | |
| | | | | | | | | | | | | | | |
| Refinery gross margin | | $ | 11.27 | | $ | 16.60 | | $ | 20.69 | | | $ | 18.72 | | $ | 11.27 | | $ | 16.60 | |
| | | | | | | | | | | | | | | |
| | | |
Tulsa Refinery | | |
| Net sales | | $ | 78.89 | | $ | — | | $ | — | | | $ | 90.84 | | $ | 78.89 | | $ | — | |
| Less cost of products | | 74.56 | | — | | — | | | 83.29 | | 74.56 | | — | |
| | | | | | | | | | | | | | | |
| Refinery gross margin | | $ | 4.33 | | $ | — | | $ | — | | | $ | 7.55 | | $ | 4.33 | | $ | — | |
| | | | | | | | | | | | | | | |
| | | |
Consolidated | | |
| Net sales | | $ | 74.06 | | $ | 108.83 | | $ | 89.77 | | | $ | 91.06 | | $ | 74.06 | | $ | 108.83 | |
| Less cost of products | | 66.85 | | 97.87 | | 73.03 | | | 82.27 | | 66.85 | | 97.87 | |
| | | | | | | | | | | | | | | |
| Refinery gross margin | | $ | 7.21 | | $ | 10.96 | | $ | 16.74 | | | $ | 8.79 | | $ | 7.21 | | $ | 10.96 | |
| | | | | | | | | | | | | | | |
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.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | Years Ended December 31, | |
| | | 2009 | | 2008 | | 2007 | | | 2010 | | 2009 | | 2008 | |
| Average per produced barrel: | | |
| | | |
Navajo Refinery | | |
| Refinery gross margin | | $ | 7.20 | | $ | 9.55 | | $ | 15.58 | | | $ | 7.25 | | $ | 7.20 | | $ | 9.55 | |
| Less refinery operating expenses | | 4.81 | | 4.58 | | 4.30 | | | 4.95 | | 4.81 | | 4.58 | |
| | | | | | | | | | | | | | | |
| Net operating margin | | $ | 2.39 | | $ | 4.97 | | $ | 11.28 | | | $ | 2.30 | | $ | 2.39 | | $ | 4.97 | |
| | | | | | | | | | | | | | | |
| | | |
Woods Cross Refinery | | |
| Refinery gross margin | | $ | 11.27 | | $ | 16.60 | | $ | 20.69 | | | $ | 18.72 | | $ | 11.27 | | $ | 16.60 | |
| Less refinery operating expenses | | 6.60 | | 7.42 | | 4.86 | | | 6.09 | | 6.60 | | 7.42 | |
| | | | | | | | | | | | | | | |
| Net operating margin | | $ | 4.67 | | $ | 9.18 | | $ | 15.83 | | | $ | 12.63 | | $ | 4.67 | | $ | 9.18 | |
| | | | | | | | | | | | | | | |
| | | |
Tulsa Refinery | | |
| Refinery gross margin | | $ | 4.33 | | $ | — | | $ | — | | | $ | 7.55 | | $ | 4.33 | | $ | — | |
| Less refinery operating expenses | | 5.25 | | — | | — | | | 4.94 | | 5.25 | | — | |
| | | | | | | | | | | | | | | |
| Net operating margin | | $ | (0.92 | ) | | $ | — | | $ | — | | | $ | 2.61 | | $ | (0.92 | ) | | $ | — | |
| | | | | | | | | | | | | | | |
| | | |
Consolidated | | |
| Refinery gross margin | | $ | 7.21 | | $ | 10.96 | | $ | 16.74 | | | $ | 8.79 | | $ | 7.21 | | $ | 10.96 | |
| Less refinery operating expenses | | 5.24 | | 5.14 | | 4.43 | | | 5.08 | | 5.24 | | 5.14 | |
| | | | | | | | | | | | | | | |
| Net operating margin | | $ | 1.97 | | $ | 5.82 | | $ | 12.31 | | | $ | 3.71 | | $ | 1.97 | | $ | 5.82 | |
| | | | | | | | | | | | | | | |
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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
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | Years Ended December 31, | |
| | | 2009 | | 2008 | | 2007 | | | 2010 | | 2009 | | 2008 | |
| | | (Dollars in thousands, except per barrel amounts) | | | (Dollars in thousands, except per barrel amounts) | |
Navajo Refinery | | |
| Average sales price per produced barrel sold | | $ | 73.15 | | $ | 108.52 | | $ | 89.68 | | | $ | 90.37 | | $ | 73.15 | | $ | 108.52 | |
| Times sales of produced refined products sold (BPD) | | 87,140 | | 89,580 | | 88,920 | | | 92,550 | | 87,140 | | 89,580 | |
| Times number of days in period | | 365 | | 366 | | 365 | | | 365 | | 365 | | 366 | |
| | | | | | | | | | | | | | | |
| Refined product sales from produced products sold | | $ | 2,326,616 | | $ | 3,557,967 | | $ | 2,910,636 | | | $ | 3,052,766 | | $ | 2,326,616 | | $ | 3,557,967 | |
| | | | | | | | | | | | | | | |
| | | |
Woods Cross Refinery | | |
| Average sales price per produced barrel sold | | $ | 70.25 | | $ | 110.07 | | $ | 90.09 | | | $ | 94.26 | | $ | 70.25 | | $ | 110.07 | |
| Times sales of produced refined products sold (BPD) | | 26,870 | | 22,370 | | 26,130 | | | 27,810 | | 26,870 | | 22,370 | |
| Times number of days in period | | 365 | | 366 | | 365 | | | 365 | | 365 | | 366 | |
| | | | | | | | | | | | | | | |
| Refined product sales from produced products sold | | $ | 688,980 | | $ | 901,189 | | $ | 859,229 | | | $ | 956,800 | | $ | 688,980 | | $ | 901,189 | |
| | | | | | | | | | | | | | | |
| | | |
Tulsa Refinery | | |
| Average sales price per produced barrel sold | | $ | 78.89 | | $ | — | | $ | — | | | $ | 90.84 | | $ | 78.89 | | $ | — | |
| Times sales of produced refined products sold (BPD) | | 37,570 | | — | | — | | | 107,780 | | 37,570 | | — | |
| Times number of days in period | | 365 | | — | | — | | | 365 | | 365 | | — | |
| | | | | | | | | | | | | | | |
| Refined product sales from produced products sold | | $ | 1,081,823 | | $ | — | | $ | — | | | $ | 3,573,618 | | $ | 1,081,823 | | $ | — | |
| | | | | | | | | | | | | | | |
| | | |
Sum of refined product sales from produced products sold from our three refineries(4)(1) | | $ | 4,097,419 | | $ | 4,459,156 | | $ | 3,769,865 | | | $ | 7,583,184 | | $ | 4,097,419 | | $ | 4,459,156 | |
Add refined product sales from purchased products and rounding(1)(2) | | 106,969 | | 384,073 | | 383,396 | | | 130,348 | | 106,969 | | 384,073 | |
| | | | | | | | | | | | | | | |
| Total refined products sales | | 4,204,388 | | 4,843,229 | | 4,153,261 | | | 7,713,532 | | 4,204,388 | | 4,843,229 | |
Add direct sales of excess crude oil(2)(3) | | 453,958 | | 860,642 | | 491,150 | | | 459,743 | | 453,958 | | 860,642 | |
Add other refining segment revenue(3)(4) | | 128,591 | | 133,578 | | 145,753 | | | 113,725 | | 131,475 | | 133,578 | |
| | | | | | | | | | | | | | | |
| Total refining segment revenue | | 4,786,937 | | 5,837,449 | | 4,790,164 | | | 8,287,000 | | 4,789,821 | | 5,837,449 | |
| Add HEP segment sales and other revenues | | 146,561 | | 94,439 | | — | | | 182,114 | | 146,561 | | 94,439 | |
| Add corporate and other revenues | | 2,248 | | 2,641 | | 1,578 | | | 415 | | | (636 | ) | | 2,641 | |
| Subtract consolidations and eliminations | | | (101,478 | ) | | | (74,172 | ) | | — | | | | (146,600 | ) | | | (101,478 | ) | | | (74,172 | ) |
| | | | | | | | | | | | | | | |
| Sales and other revenues | | $ | 4,834,268 | | $ | 5,860,357 | | $ | 4,791,742 | | | $ | 8,322,929 | | $ | 4,834,268 | | $ | 5,860,357 | |
| | | | | | | | | | | | | | | |
| | |
| (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. |
| |
(2)(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. |
| |
(3)(4) | | Other refining segment revenue includes revenues associated with Holly Asphalt and revenue derived from feedstock and sulfur credit sales. |
|
(4) | | 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.
|
| | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | | | | | | | | | | | |
| | | 2009 | | 2008 | | 2007 | | | Years Ended December 31, | |
| | | (Dollars in thousands, except per barrel amounts) | | | 2010 | | 2009 | | 2008 | |
| | | | (Dollars in thousands, except per barrel amounts) | |
| Average sales price per produced barrel sold | | $ | 74.06 | | $ | 108.83 | | $ | 89.77 | | | $ | 91.06 | | $ | 74.06 | | $ | 108.83 | |
| Times sales of produced refined products sold (BPD) | | 151,580 | | 111,950 | | 115,050 | | | 228,140 | | 151,580 | | 111,950 | |
| Times number of days in period | | 365 | | 366 | | 365 | | | 365 | | 365 | | 366 | |
| | | | | | | | | | | | | | | |
| Refined product sales from produced products sold | | $ | 4,097,419 | | $ | 4,459,156 | | $ | 3,769,865 | | | $ | 7,583,184 | | $ | 4,097,419 | | $ | 4,459,156 | |
| | | | | | | | | | | | | | | |
-67-
Reconciliation of average cost of products per produced barrel sold to total cost of products sold
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | Years Ended December 31, | |
| | | 2009 | | 2008 | | 2007 | | | 2010 | | 2009 | | 2008 | |
| | | (Dollars in thousands, except per barrel amounts) | | | (Dollars in thousands, except per barrel amounts) | |
Navajo Refinery | | |
| Average cost of products per produced barrel sold | | $ | 65.95 | | $ | 98.97 | | $ | 74.10 | | | $ | 83.12 | | $ | 65.95 | | $ | 98.97 | |
| Times sales of produced refined products sold (BPD) | | 87,140 | | 89,580 | | 88,920 | | | 92,550 | | 87,140 | | 89,580 | |
| Times number of days in period | | 365 | | 366 | | 365 | | | 365 | | 365 | | 366 | |
| | | | | | | | | | | | | | | |
| Cost of products for produced products sold | | $ | 2,097,612 | | $ | 3,244,858 | | $ | 2,404,975 | | | $ | 2,807,856 | | $ | 2,097,612 | | $ | 3,244,858 | |
| | | | | | | | | | | | | | | |
| | | |
Woods Cross Refinery | | |
| Average cost of products per produced barrel sold | | $ | 58.98 | | $ | 93.47 | | $ | 69.40 | | | $ | 75.54 | | $ | 58.98 | | $ | 93.47 | |
| Times sales of produced refined products sold (BPD) | | 26,870 | | 22,370 | | 26,130 | | | 27,810 | | 26,870 | | 22,370 | |
| Times number of days in period | | 365 | | 366 | | 365 | | | 365 | | 365 | | 366 | |
| | | | | | | | | | | | | | | |
| Cost of products for produced products sold | | $ | 578,449 | | $ | 765,278 | | $ | 661,899 | | | $ | 766,780 | | $ | 578,449 | | $ | 765,278 | |
| | | | | | | | | | | | | | | |
| | | |
Tulsa Refinery | | |
| Average cost of products per produced barrel sold | | $ | 74.56 | | $ | — | | $ | — | | | $ | 83.29 | | $ | 74.56 | | $ | — | |
| Times sales of produced refined products sold (BPD) | | 37,570 | | — | | — | | | 107,780 | | 37,570 | | — | |
| Times number of days in period | | 365 | | — | | — | | | 365 | | 365 | | — | |
| | | | | | | | | | | | | | | |
| Cost of products for produced products sold | | $ | 1,022,445 | | $ | — | | $ | — | | | $ | 3,276,604 | | $ | 1,022,445 | | $ | — | |
| | | | | | | | | | | | | | | |
| | | |
Sum of cost of products for produced products sold from our three refineries(4)(1) | | $ | 3,698,506 | | $ | 4,010,136 | | $ | 3,066,874 | | | $ | 6,851,240 | | $ | 3,698,506 | | $ | 4,010,136 | |
Add refined product costs from purchased products sold and rounding(1)(2) | | 114,650 | | 389,944 | | 374,432 | | | 131,141 | | 114,650 | | 389,944 | |
| | | | | | | | | | | | | | | |
| Total refined cost of products sold | | 3,813,156 | | 4,400,080 | | 3,441,306 | | | 6,982,381 | | 3,813,156 | | 4,400,080 | |
Add crude oil cost of direct sales of excess crude oil(2)(3) | | 449,488 | | 853,360 | | 492,222 | | | 454,566 | | 449,488 | | 853,360 | |
Add other refining segment cost of products sold(3)(4) | | 75,229 | | 101,144 | | 69,960 | | | 73,410 | | 75,229 | | 101,144 | |
| | | | | | | | | | | | | | | |
| Total refining segment cost of products sold | | 4,337,873 | | 5,354,584 | | 4,003,488 | | | 7,510,357 | | 4,337,873 | | 5,354,584 | |
| Subtract consolidations and eliminations | | | (99,865 | ) | | | (73,885 | ) | | — | | | | (143,208 | ) | | | (99,865 | ) | | | (73,885 | ) |
| | | | | | | | | | | | | | | |
| Cost of products sold (exclusive of depreciation and amortization) | | $ | 4,238,008 | | $ | 5,280,699 | | $ | 4,003,488 | | | $ | 7,367,149 | | $ | 4,238,008 | | $ | 5,280,699 | |
| | | | | | | | | | | | | | | |
| | |
| (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. |
| |
(2)(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. |
| |
(3)(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. |
|
(4) | | 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.
|
| | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | | | | | | | | | | | |
| | | 2009 | | 2008 | | 2007 | | | Years Ended December 31, | |
| | | (Dollars in thousands, except per barrel amounts) | | | 2010 | | 2009 | | 2008 | |
| | | | (Dollars in thousands, except per barrel amounts) | |
| Average cost of products per produced barrel sold | | $ | 66.85 | | $ | 97.87 | | $ | 73.03 | | | $ | 82.27 | | $ | 66.85 | | $ | 97.87 | |
| Times sales of produced refined products sold (BPD) | | 151,580 | | 111,950 | | 115,050 | | | 228,140 | | 151,580 | | 111,950 | |
| Times number of days in period | | 365 | | 366 | | 365 | | | 365 | | 365 | | 366 | |
| | | | | | | | | | | | | | | |
| Cost of products for produced products sold | | $ | 3,698,506 | | $ | 4,010,136 | | $ | 3,066,874 | | | $ | 6,851,240 | | $ | 3,698,506 | | $ | 4,010,136 | |
| | | | | | | | | | | | | | | |
-68-
Reconciliation of average refinery operating expenses per produced barrel sold to total operating expenses
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | Years Ended December 31, | |
| | | 2009 | | 2008 | | 2007 | | | 2010 | | 2009 | | 2008 | |
| | | (Dollars in thousands, except per barrel amounts) | | | (Dollars in thousands, except per barrel amounts) | |
Navajo Refinery | | |
| Average refinery operating expenses per produced barrel sold | | $ | 4.81 | | $ | 4.58 | | $ | 4.30 | | | $ | 4.95 | | $ | 4.81 | | $ | 4.58 | |
| Times sales of produced refined products sold (BPD) | | 87,140 | | 89,580 | | 88,920 | | | 92,550 | | 87,140 | | 89,580 | |
| Times number of days in period | | 365 | | 366 | | 365 | | | 365 | | 365 | | 366 | |
| | | | | | | | | | | | | | | |
| Refinery operating expenses for produced products sold | | $ | 152,987 | | $ | 150,161 | | $ | 139,560 | | | $ | 167,215 | | $ | 152,987 | | $ | 150,161 | |
| | | | | | | | | | | | | | | |
| | | |
Woods Cross Refinery | | |
| Average refinery operating expenses per produced barrel sold | | $ | 6.60 | | $ | 7.42 | | $ | 4.86 | | | $ | 6.09 | | $ | 6.60 | | $ | 7.42 | |
| Times sales of produced refined products sold (BPD) | | 26,870 | | 22,370 | | 26,130 | | | 27,810 | | 26,870 | | 22,370 | |
| Times number of days in period | | 365 | | 366 | | 365 | | | 365 | | 365 | | 366 | |
| | | | | | | | | | | | | | | |
| Refinery operating expenses for produced products sold | | $ | 64,730 | | $ | 60,751 | | $ | 46,352 | | | $ | 61,817 | | $ | 64,730 | | $ | 60,751 | |
| | | | | | | | | | | | | | | |
| | | |
Tulsa Refinery | | |
| Average refinery operating expenses per produced barrel sold | | $ | 5.25 | | $ | — | | $ | — | | | $ | 4.94 | | $ | 5.25 | | $ | — | |
| Times sales of produced refined products sold (BPD) | | 37,570 | | — | | — | | | 107,780 | | 37,570 | | — | |
| Times number of days in period | | 365 | | — | | — | | | 365 | | 365 | | — | |
| | | | | | | | | | | | | | | |
| Refinery operating expenses for produced products sold | | $ | 71,994 | | $ | — | | $ | — | | | $ | 194,338 | | $ | 71,994 | | $ | — | |
| | | | | | | | | | | | | | | |
| | | |
Sum of refinery operating expenses per produced products sold from our three refineries(2)(1) | | $ | 289,711 | | $ | 210,912 | | $ | 185,912 | | | $ | 423,370 | | $ | 289,711 | | $ | 210,912 | |
Add other refining segment operating expenses and rounding(1)(2) | | 23,609 | | 21,599 | | 23,357 | | | 26,220 | | 23,609 | | 21,599 | |
| | | | | | | | | | | | | | | |
| Total refining segment operating expenses | | 313,320 | | 232,511 | | 209,269 | | | 449,590 | | 313,320 | | 232,511 | |
| Add HEP segment operating expenses | | 44,003 | | 33,353 | | — | | | 52,947 | | 44,003 | | 33,353 | |
| Add corporate and other costs | | | (468 | ) | | | (159 | ) | | 12 | | | 2,387 | | 41 | | 128 | |
| Subtract consolidations and eliminations | | | | (510 | ) | | | (509 | ) | | | (287 | ) |
| | | | | | | | | | | | | | | |
| Operating expenses (exclusive of depreciation and amortization) | | $ | 356,855 | | $ | 265,705 | | $ | 209,281 | | | $ | 504,414 | | $ | 356,855 | | $ | 265,705 | |
| | | | | | | | | | | | | | | |
| | |
| (1) | | Other refining segment operating expenses include the marketing costs associated with our refining segment and the operating expenses of Holly Asphalt.
|
|
(2) | | The above calculations of refinery operating expenses per 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. |
| | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | | | | | | | | | | | |
| | | 2009 | | 2008 | | 2007 | | | Years Ended December 31, | |
| | | (Dollars in thousands, except per barrel amounts) | | | 2010 | | 2009 | | 2008 | |
| | | | (Dollars in thousands, except per barrel amounts) | |
| Average refinery operating expenses per produced barrel sold | | $ | 5.24 | | $ | 5.14 | | $ | 4.43 | | | $ | 5.08 | | $ | 5.24 | | $ | 5.14 | |
| Times sales of produced refined products sold (BPD) | | 151,580 | | 111,950 | | 115,050 | | | 228,140 | | 151,580 | | 111,950 | |
| Times number of days in period | | 365 | | 366 | | 365 | | | 365 | | 365 | | 366 | |
| | | | | | | | | | | | | | | |
| Refinery operating expenses for produced products sold | | $ | 289,711 | | $ | 210,912 | | $ | 185,912 | | | $ | 423,370 | | $ | 289,711 | | $ | 210,912 | |
| | | | | | | | | | | | | | | |
Reconciliation of net operating margin per barrel to refinery gross margin per barrel to total sales and other revenues
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | Years Ended December 31, | |
| | | 2009 | | 2008 | | 2007 | | | 2010 | | 2009 | | 2008 | |
| | | (Dollars in thousands, except per barrel amounts) | | | (Dollars in thousands, except per barrel amounts) | |
Navajo Refinery | | |
| Net operating margin per barrel | | $ | 2.39 | | $ | 4.97 | | $ | 11.28 | | | $ | 2.30 | | $ | 2.39 | | $ | 4.97 | |
| Add average refinery operating expenses per produced barrel | | 4.81 | | 4.58 | | 4.30 | | | 4.95 | | 4.81 | | 4.58 | |
| | | | | | | | | | | | | | | |
| Refinery gross margin per barrel | | 7.20 | | 9.55 | | 15.58 | | | 7.25 | | 7.20 | | 9.55 | |
| Add average cost of products per produced barrel sold | | 65.95 | | 98.97 | | 74.10 | | | 83.12 | | 65.95 | | 98.97 | |
| | | | | | | | | | | | | | | |
| Average sales price per produced barrel sold | | $ | 73.15 | | $ | 108.52 | | $ | 89.68 | | | $ | 90.37 | | $ | 73.15 | | $ | 108.52 | |
| Times sales of produced refined products sold (BPD) | | 87,140 | | 89,580 | | 88,920 | | | 92,550 | | 87,140 | | 89,580 | |
| Times number of days in period | | 365 | | 366 | | 365 | | | 365 | | 365 | | 366 | |
| | | | | | | | | | | | | | | |
| Refined product sales from produced products sold | | $ | 2,326,616 | | $ | 3,557,967 | | $ | 2,910,636 | | | $ | 3,052,766 | | $ | 2,326,616 | | $ | 3,557,967 | |
| | | | | | | | | | | | | | | |
-69-
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | Years Ended December 31, | |
| | | 2009 | | 2008 | | 2007 | | | 2010 | | 2009 | | 2008 | |
| | | (Dollars in thousands, except per barrel amounts) | | | (Dollars in thousands, except per barrel amounts) | |
Woods Cross Refinery | | |
| Net operating margin per barrel | | $ | 4.67 | | $ | 9.18 | | $ | 15.83 | | | $ | 12.63 | | $ | 4.67 | | $ | 9.18 | |
| Add average refinery operating expenses per produced barrel | | 6.60 | | 7.42 | | 4.86 | | | 6.09 | | 6.60 | | 7.42 | |
| | | | | | | | | | | | | | | |
| Refinery gross margin per barrel | | 11.27 | | 16.60 | | 20.69 | | | 18.72 | | 11.27 | | 16.60 | |
| Add average cost of products per produced barrel sold | | 58.98 | | 93.47 | | 69.40 | | | 75.54 | | 58.98 | | 93.47 | |
| | | | | | | | | | | | | | | |
| Average sales price per produced barrel sold | | $ | 70.25 | | $ | 110.07 | | $ | 90.09 | | | $ | 94.26 | | $ | 70.25 | | $ | 110.07 | |
| Times sales of produced refined products sold (BPD) | | 26,870 | | 22,370 | | 26,130 | | | 27,810 | | 26,870 | | 22,370 | |
| Times number of days in period | | 365 | | 366 | | 365 | | | 365 | | 365 | | 366 | |
| | | | | | | | | | | | | | | |
| Refined product sales from produced products sold | | $ | 688,980 | | $ | 901,189 | | $ | 859,229 | | | $ | 956,800 | | $ | 688,980 | | $ | 901,189 | |
| | | | | | | | | | | | | | | |
| | | |
Tulsa Refinery | | |
| Net operating margin per barrel | | $ | (0.92 | ) | | $ | — | | $ | — | | | $ | 2.61 | | $ | (0.92 | ) | | $ | — | |
| Add average refinery operating expenses per produced barrel | | 5.25 | | — | | — | | | 4.94 | | 5.25 | | — | |
| | | | | | | | | | | | | | | |
| Refinery gross margin per barrel | | 4.33 | | — | | — | | | 7.55 | | 4.33 | | — | |
| Add average cost of products per produced barrel sold | | 74.56 | | — | | — | | | 83.29 | | 74.56 | | — | |
| | | | | | | | | | | | | | | |
| Average sales price per produced barrel sold | | $ | 78.89 | | $ | — | | $ | — | | | $ | 90.84 | | $ | 78.89 | | $ | — | |
| Times sales of produced refined products sold (BPD) | | 37,570 | | — | | — | | | 107,780 | | 37,570 | | — | |
| Times number of days in period | | 365 | | — | | — | | | 365 | | 365 | | — | |
| | | | | | | | | | | | | | | |
| Refined product sales from produced products sold | | $ | 1,081,823 | | $ | — | | $ | — | | | $ | 3,573,618 | | $ | 1,081,823 | | $ | — | |
| | | | | | | | | | | | | | | |
| | | |
Sum of refined product sales from produced products sold from our three refineries(4)(1) | | $ | 4,097,419 | | $ | 4,459,156 | | $ | 3,769,865 | | | $ | 7,583,184 | | $ | 4,097,419 | | $ | 4,459,156 | |
Add refined product sales from purchased products and rounding(1)(2) | | 106,969 | | 384,073 | | 383,396 | | | 130,348 | | 106,969 | | 384,073 | |
| | | | | | | | | | | | | | | |
| Total refined product sales | | 4,204,388 | | 4,843,229 | | 4,153,261 | | | 7,713,532 | | 4,204,388 | | 4,843,229 | |
Add direct sales of excess crude oil(2)(3) | | 453,958 | | 860,642 | | 491,150 | | | 459,743 | | 453,958 | | 860,642 | |
Add other refining segment revenue(3)(4) | | 128,591 | | 133,578 | | 145,753 | | | 113,725 | | 131,475 | | 133,578 | |
| | | | | | | | | | | | | | | |
| Total refining segment revenue | | 4,786,937 | | 5,837,449 | | 4,790,164 | | | 8,287,000 | | 4,789,821 | | 5,837,449 | |
| Add HEP segment sales and other revenues | | 146,561 | | 94,439 | | — | | | 182,114 | | 146,561 | | 94,439 | |
| Add corporate and other revenues | | 2,248 | | 2,641 | | 1,578 | | | 415 | | | (636 | ) | | 2,641 | |
| Subtract consolidations and eliminations | | | (101,478 | ) | | | (74,172 | ) | | — | | | | (146,600 | ) | | | (101,478 | ) | | | (74,172 | ) |
| | | | | | | | | | | | | | | |
| Sales and other revenues | | $ | 4,834,268 | | $ | 5,860,357 | | $ | 4,791,742 | | | $ | 8,322,929 | | $ | 4,834,268 | | $ | 5,860,357 | |
| | | | | | | | | | | | | | | |
| | |
| (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. |
| |
(2)(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. |
| |
(3)(4) | | Other refining segment revenue includes the revenues associated with Holly Asphalt and revenue derived from feedstock and sulfur credit sales. |
|
(4) | | 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.
|
| | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | | | | | | | | | | | |
| | | 2009 | | 2008 | | 2007 | | | Years Ended December 31, | |
| | | (Dollars in thousands, except per barrel amounts) | | | 2010 | | 2009 | | 2008 | |
| | | | (Dollars in thousands, except per barrel amounts) | |
| Net operating margin per barrel | | $ | 1.97 | | $ | 5.82 | | $ | 12.31 | | | $ | 3.71 | | $ | 1.97 | | $ | 5.82 | |
| Add average refinery operating expenses per produced barrel | | 5.24 | | 5.14 | | 4.43 | | | 5.08 | | 5.24 | | 5.14 | |
| | | | | | | | | | | | | | | |
| Refinery gross margin per barrel | | 7.21 | | 10.96 | | 16.74 | | | 8.79 | | 7.21 | | 10.96 | |
| Add average cost of products per produced barrel sold | | 66.85 | | 97.87 | | 73.03 | | | 82.27 | | 66.85 | | 97.87 | |
| | | | | | | | | | | | | | | |
| Average sales price per produced barrel sold | | $ | 74.06 | | $ | 108.83 | | $ | 89.77 | | | $ | 91.06 | | $ | 74.06 | | $ | 108.83 | |
| Times sales of produced refined products sold (BPD) | | 151,580 | | 111,950 | | 115,050 | | | 228,140 | | 151,580 | | 111,950 | |
| Times number of days in period | | 365 | | 366 | | 365 | | | 365 | | 365 | | 366 | |
| | | | | | | | | | | | | | | |
| Refined product sales from produced products sold | | $ | 4,097,419 | | $ | 4,459,156 | | $ | 3,769,865 | | | $ | 7,583,184 | | $ | 4,097,419 | | $ | 4,459,156 | |
| | | | | | | | | | | | | | | |
-70-
| | |
Item 8. | | Item 8. Financial Statements and Supplementary Data |
MANAGEMENT’S REPORT ON ITS ASSESSMENT OF THE COMPANY’S INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of Holly Corporation (the “Company”) is responsible for establishing and maintaining adequate internal control over financial reporting.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Management assessed the Company’s internal control over financial reporting as of December 31, 20092010 using the criteria for effective control over financial reporting established in “Internal Control –— Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believesconcludes that, as of December 31, 2009,2010, the Company maintained effective internal control over financial reporting.
The Company acquired two refinery facilities located in Tulsa, Oklahoma during 2009, one from an affiliate of Sunoco, Inc. on June 1, 2009 and another from an affiliate of Sinclair Oil Company on December 1, 2009. Management has excluded the operations of these facilities from its assessment of the effectiveness of our internal control over financial reporting as of December 31, 2009. These facilities represent 23%, 2% and 22% of our total assets, net assets and revenues, respectively, as of December 31, 2009. We plan to fully integrate the operations of these facilities into our assessment of the effectiveness of internal control over financial reporting in 2010.
The Company’s independent registered public accounting firm has issued an attestation report on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2009.2010. That report appears on page 72.
-71-
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors
and Stockholders of Holly Corporation
We have audited Holly Corporation’s (the “Company”) internal control over financial reporting as of December 31, 2009,2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Holly Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying management’s report. Our responsibility is to express an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
As indicated in the accompanying, Management’s Report on its Assessment of the Company’s Internal Control Over Financial Reporting, management’s assessment of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of the two refinery facilities located in Tulsa, Oklahoma, one acquired from an affiliate of Sunoco, Inc. and another from an affiliate of Sinclair Oil Company which are included in the December 31, 2009 consolidated financial statements of Holly Corporation and represent 23%, 2% and 22% of total assets, net assets and revenues, respectively, as of and for the year ended December 31, 2009. Our audit of internal control over financial reporting of Holly Corporation also did not include an evaluation of the internal control over financial reporting of the two acquired refinery facilities.
In our opinion, Holly Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009,2010, based on the COSO criteria.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Holly Corporation as of December 31, 20092010 and 2008,2009, and the related consolidated statements of income, cash flows, stockholders’ equity and comprehensive income for each of the three years in the period ended December 31, 20092010 and our report dated February 26, 201025, 2011 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Dallas, Texas
February 26, 201025, 2011
-72-
Index to Consolidated Financial Statements
| | | | | |
| | | Page | |
| | | Reference |
| | | 74 | |
| | | | | |
| | | 75 | |
| | | | | |
| | | 76 | |
| | | | | |
| | | 77 | |
| | | | |
| | | 7877 | |
| | | | | |
| | | 7978 | |
| | | | | |
| | | 8079 | |
| | | | | |
| | | 81 | |
| | | 80 | |
-74--73-
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors
and Stockholders of Holly Corporation
We have audited the accompanying consolidated balance sheets of Holly Corporation as of December 31, 20092010 and 2008,2009, and the related consolidated statements of income, cash flows, equity and comprehensive income for each of the three years in the period ended December 31, 2009.2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Holly Corporation at December 31, 20092010 and 2008,2009, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2009,2010, in conformity with U.S. generally accepted accounting principles.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Holly Corporation’s internal control over financial reporting as of December 31, 2009,2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 26, 201025, 2011 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Dallas, Texas
February 26, 201025, 2011
-75--74-
HOLLY CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
| | | | | | | | | |
| | | December 31, | | | December 31, | |
| | | 2009 | | | 2008 | |
| | | | | | | | | |
ASSETS | | | | | | | | |
Current assets: | | | | | | | | |
| Cash and cash equivalents | | $ | 124,596 | | | $ | 39,244 | |
| Marketable securities | | | 1,223 | | | | 49,194 | |
| | | | | | | | | |
| Accounts receivable: | | | | | | | | |
| Product and transportation | | | 292,310 | | | | 127,192 | |
| Crude oil resales | | | 470,145 | | | | 161,427 | |
| | | | | | | |
| | | | 762,455 | | | | 288,619 | |
| | | | | | | | | |
| Inventories: | | | | | | | | |
| Crude oil and refined products | | | 259,582 | | | | 107,811 | |
| Materials and supplies | | | 43,931 | | | | 17,924 | |
| | | | | | | |
| | | | 303,513 | | | | 125,735 | |
| | | | | | | | | |
| Income taxes receivable | | | 38,072 | | | | 6,350 | |
| Prepayments and other | | | 50,957 | | | | 18,775 | |
| Current assets of discontinued operations | | | 2,195 | | | | 2,706 | |
| | | | | | | |
Total current assets | | | 1,283,011 | | | | 530,623 | |
| | | | | | | | | |
| Properties, plants and equipment, at cost | | | 2,001,855 | | | | 1,462,963 | |
| Less accumulated depreciation | | | (371,885 | ) | | | (290,039 | ) |
| | | | | | | |
| | | | 1,629,970 | | | | 1,172,924 | |
| | | | | | | | | |
| Marketable securities (long-term) | | | — | | | | 6,009 | |
| | | | | | | | | |
| Other assets: | | | | | | | | |
| Turnaround costs | | | 53,463 | | | | 34,309 | |
| Goodwill | | | 81,602 | | | | 27,542 | |
| Intangibles and other | | | 97,893 | | | | 70,420 | |
| | | | | | | |
| | | | 232,958 | | | | 132,271 | |
| Non-current assets of discontinued operations | | | — | | | | 32,398 | |
| | | | | | | |
Total assets | | $ | 3,145,939 | | | $ | 1,874,225 | |
| | | | | | | |
| | | | | | | | | |
LIABILITIES AND STOCKHOLDERS’ EQUITY | | | | | | | | |
Current liabilities: | | | | | | | | |
| Accounts payable | | $ | 975,155 | | | $ | 390,438 | |
| Accrued liabilities | | | 49,957 | | | | 41,785 | |
| Short-term debt — Holly Energy Partners | | | — | | | | 29,000 | |
| Current liabilities of discontinued operations | | | — | | | | 935 | |
| | | | | | | |
Total current liabilities | | | 1,025,112 | | | | 462,158 | |
| | | | | | | | | |
| Long-term debt — Holly Corporation | | | 328,260 | | | | — | |
| Long-term debt — Holly Energy Partners | | | 379,198 | | | | 341,914 | |
| Deferred income taxes | | | 124,585 | | | | 69,491 | |
| Other long-term liabilities | | | 81,003 | | | | 64,330 | |
| | | | | | | | | |
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 and 100,000,000 shares authorized; 76,359,006 and 73,543,873 shares issued as of December 31, 2009 and 2008, respectively | | | 764 | | | | 735 | |
| Additional capital | | | 195,565 | | | | 121,298 | |
| Retained earnings | | | 1,134,341 | | | | 1,145,388 | |
| Accumulated other comprehensive loss | | | (25,700 | ) | | | (35,081 | ) |
| Common stock held in treasury, at cost — 23,292,737 and 23,600,653 shares as of December 31, 2009 and 2008, respectively | | | (685,931 | ) | | | (690,800 | ) |
| | | | | | | |
Total Holly Corporation stockholders’ equity | | | 619,039 | | | | 541,540 | |
| | | | | | | | | |
Noncontrolling interest | | | 588,742 | | | | 394,792 | |
| | | | | | | |
Total equity | | | 1,207,781 | | | | 936,332 | |
| | | | | | | |
Total liabilities and equity | | $ | 3,145,939 | | | $ | 1,874,225 | |
| | | | | | | |
| | | | | | | | | |
| | | December 31, | | | December 31, | |
| | | 2010 | | | 2009 | |
ASSETS | | | | | | | | |
Current assets: | | | | | | | | |
Cash and cash equivalents(HEP: $403 and $2,508, respectively) | | $ | 229,101 | | | $ | 124,596 | |
| Marketable securities | | | 1,343 | | | | 1,223 | |
| | | | | | | | | |
Accounts receivable, net: Product and transportation(HEP: $22,508 and $18,767, respectively) | | | 299,081 | | | | 292,310 | |
| Crude oil resales | | | 694,035 | | | | 470,145 | |
| | | | | | | |
| | | | 993,116 | | | | 762,455 | |
| | | | | | | | | |
| Inventories: Crude oil and refined products | | | 353,636 | | | | 259,582 | |
Materials and supplies(HEP: $202 and $165, respectively) | | | 46,731 | | | | 43,931 | |
| | | | | | | |
| | | | 400,367 | | | | 303,513 | |
| | | | | | | | | |
| Income taxes receivable | | | 51,034 | | | | 38,072 | |
Prepayments and other(HEP: $573 and $574, respectively) | | | 28,474 | | | | 50,957 | |
Current assets of discontinued operations(HEP: $2,195) | | | — | | | | 2,195 | |
| | | | | | | |
Total current assets | | | 1,703,435 | | | | 1,283,011 | |
| | | | | | | | | |
Properties, plants and equipment, at cost(HEP: $552,398 and $491,999, respectively) | | | 2,215,828 | | | | 2,001,855 | |
Less accumulated depreciation(HEP: $(60,300) and $(33,478), respectively) | | | (459,137 | ) | | | (371,885 | ) |
| | | | | | | |
| | | | 1,756,691 | | | | 1,629,970 | |
| | | | | | | | | |
| Other assets: Turnaround costs | | | 69,533 | | | | 53,463 | |
Goodwill(HEP: $81,602 and $81,602) | | | 81,602 | | | | 81,602 | |
Intangibles and other(HEP: $72,434 and $77,443, respectively) | | | 90,214 | | | | 97,893 | |
| | | | | | | |
| | | | 241,349 | | | | 232,958 | |
| | | | | | | |
Total assets | | $ | 3,701,475 | | | $ | 3,145,939 | |
| | | | | | | |
| | | | | | | | | |
LIABILITIES AND EQUITY | | | | | | | | |
Current liabilities: | | | | | | | | |
Accounts payable(HEP: $10,238 and $6,211, respectively) | | $ | 1,317,446 | | | $ | 975,155 | |
Accrued liabilities(HEP: $21,206 and $13,594, respectively) | | | 72,409 | | | | 49,957 | |
| | | | | | | |
Total current liabilities | | | 1,389,855 | | | | 1,025,112 | |
| | | | | | | | | |
Long-term debt(HEP: $482,271 and $379,198, respectively) | | | 810,561 | | | | 707,458 | |
| Deferred income taxes | | | 131,935 | | | | 124,585 | |
Other long-term liabilities(HEP: $10,809 and $12,349, respectively) | | | 80,985 | | | | 81,003 | |
| | | | | | | | | |
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 and 76,359,006 shares issued as of December 31, 2010 and December 31, 2009, respectively | | | 763 | | | | 764 | |
| Additional capital | | | 194,378 | | | | 195,565 | |
| Retained earnings | | | 1,206,328 | | | | 1,134,341 | |
| Accumulated other comprehensive loss | | | (26,246 | ) | | | (25,700 | ) |
| Common stock held in treasury, at cost — 23,081,744 and 23,292,737 shares as of December 31, 2010 and 2009, respectively | | | (677,804 | ) | | | (685,931 | ) |
| | | | | | | |
Total Holly Corporation stockholders’ equity | | | 697,419 | | | | 619,039 | |
| | | | | | | | | |
Noncontrolling interest | | | 590,720 | | | | 588,742 | |
| | | | | | | |
Total equity | | | 1,288,139 | | | | 1,207,781 | |
| | | | | | | |
Total liabilities and equity | | $ | 3,701,475 | | | $ | 3,145,939 | |
| | | | | | | |
Parenthetical amounts represent asset and liability balances attributable to Holly Energy Partners, L.P. (“HEP”) as of December 31, 2010 and December 31, 2009. HEP is a consolidated variable interest entity.
See accompanying notes.
-76--75-
HOLLY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except per share data)
| | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | | | | | | | | | | | |
| | | 2009 | | 2008 | | 2007 | | | Years Ended December 31, | |
| | | | 2010 | | 2009 | | 2008 | |
Sales and other revenues | | $ | 4,834,268 | | $ | 5,860,357 | | $ | 4,791,742 | | | $ | 8,322,929 | | $ | 4,834,268 | | $ | 5,860,357 | |
| | | |
Operating costs and expenses: | | |
| Cost of products sold (exclusive of depreciation and amortization) | | 4,238,008 | | 5,280,699 | | 4,003,488 | | | 7,367,149 | | 4,238,008 | | 5,280,699 | |
| Operating expenses (exclusive of depreciation and amortization) | | 356,855 | | 265,705 | | 209,281 | | | 504,414 | | 356,855 | | 265,705 | |
| General and administrative expenses (exclusive of depreciation and amortization) | | 60,343 | | 55,278 | | 69,185 | | | 70,839 | | 60,343 | | 55,278 | |
| Depreciation and amortization | | 98,751 | | 62,995 | | 43,456 | | | 117,529 | | 98,751 | | 62,995 | |
| | | | | | | | | | | | | | | |
Total operating costs and expenses | | 4,753,957 | | 5,664,677 | | 4,325,410 | | | 8,059,931 | | 4,753,957 | | 5,664,677 | |
| | | | | | | | | | | | | | | |
| | | |
Income from operations | | 80,311 | | 195,680 | | 466,332 | | | 262,998 | | 80,311 | | 195,680 | |
| | | |
Other income (expense): | | |
| Equity in earnings of SLC Pipeline | | 1,919 | | — | | — | | | 2,393 | | 1,919 | | — | |
| Interest income | | 5,045 | | 10,797 | | 15,089 | | | 1,168 | | 5,045 | | 10,797 | |
| Interest expense | | | (40,346 | ) | | | (23,955 | ) | | | (1,086 | ) | | | (74,196 | ) | | | (40,346 | ) | | | (23,955 | ) |
| Acquisition costs — Tulsa refineries | | | (3,126 | ) | | — | | — | | | — | | | (3,126 | ) | | — | |
| Impairment of equity securities | | — | | | (3,724 | ) | | — | | | — | | — | | | (3,724 | ) |
| Gain on sale of Holly Petroleum, Inc. | | — | | 5,958 | | — | | | — | | — | | 5,958 | |
| Equity in earnings of Holly Energy Partners | | — | | 2,990 | | 19,109 | | | — | | — | | 2,990 | |
| | | | | | | | | | | | | | | |
| | | | (36,508 | ) | | | (7,934 | ) | | 33,112 | | | | (70,635 | ) | | | (36,508 | ) | | | (7,934 | ) |
| | | | | | | | | | | | | | | |
Income from continuing operations before income taxes | | 43,803 | | 187,746 | | 499,444 | | | 192,363 | | 43,803 | | 187,746 | |
| | | |
| Income tax provision: | | |
| Current | | | (30,062 | ) | | 31,094 | | 142,245 | | | 35,472 | | | (30,062 | ) | | 31,094 | |
| Deferred | | 37,522 | | 32,934 | | 23,071 | | | 23,840 | | 37,522 | | 32,934 | |
| | | | | | | | | | | | | | | |
| | | 7,460 | | 64,028 | | 165,316 | | | 59,312 | | 7,460 | | 64,028 | |
| | | | | | | | | | | | | | | |
Income from continuing operations | | 36,343 | | 123,718 | | 334,128 | | | 133,051 | | 36,343 | | 123,718 | |
| | | |
Discontinued operations | | |
| Income from discontinued operations, net of taxes | | 4,425 | | 2,918 | | — | | | — | | 4,425 | | 2,918 | |
| Gain on sale of discontinued operations, net of taxes | | 12,501 | | — | | — | | | — | | 12,501 | | — | |
| | | | | | | | | | | | | | | |
Income from discontinued operations | | 16,926 | | 2,918 | | — | | | — | | 16,926 | | 2,918 | |
| | | | | | | | | | | | | | | |
| | | |
Net income | | 53,269 | | 126,636 | | 334,128 | | | 133,051 | | 53,269 | | 126,636 | |
| | | |
| Less net income attributable to noncontrolling interest | | 33,736 | | 6,078 | | — | | | 29,087 | | 33,736 | | 6,078 | |
| | | | | | | | | | | | | | | |
| | | |
Net income attributable to Holly Corporation stockholders | | $ | 19,533 | | $ | 120,558 | | $ | 334,128 | | | $ | 103,964 | | $ | 19,533 | | $ | 120,558 | |
| | | | | | | | | | | | | | | |
| | | |
Earnings attributable to Holly Corporation stockholders: | | |
| Income from continuing operations | | $ | 15,209 | | $ | 119,206 | | $ | 334,128 | | | $ | 103,964 | | $ | 15,209 | | $ | 119,206 | |
| Income from discontinued operations | | 4,324 | | 1,352 | | — | | | — | | 4,324 | | 1,352 | |
| | | | | | | | | | | | | | | |
| Net income | | $ | 19,533 | | $ | 120,558 | | $ | 334,128 | | | $ | 103,964 | | $ | 19,533 | | $ | 120,558 | |
| | | | | | | | | | | | | | | |
| | | |
Earnings per share attributable to Holly Corporation stockholders — basic: | | |
| Income from continuing operations | | $ | 0.30 | | $ | 2.37 | | $ | 6.09 | | | $ | 1.95 | | $ | 0.30 | | $ | 2.37 | |
| Income from discontinued operations | | 0.09 | | 0.03 | | — | | | — | | 0.09 | | 0.03 | |
| | | | | | | | | | | | | | | |
| Net income | | $ | 0.39 | | $ | 2.40 | | $ | 6.09 | | | $ | 1.95 | | $ | 0.39 | | $ | 2.40 | |
| | | | | | | | | | | | | | | |
| | | |
Earnings per share attributable to Holly Corporation stockholders — diluted: | | |
| Income from continuing operations | | $ | 0.30 | | $ | 2.36 | | $ | 5.98 | | | $ | 1.94 | | $ | 0.30 | | $ | 2.36 | |
| Income from discontinued operations | | 0.09 | | 0.02 | | — | | | — | | 0.09 | | 0.02 | |
| | | | | | | | | | | | | | | |
| Net income | | $ | 0.39 | | $ | 2.38 | | $ | 5.98 | | | $ | 1.94 | | $ | 0.39 | | $ | 2.38 | |
| | | | | | | | | | | | | | | |
| | | |
Average number of common shares outstanding: | | |
| Basic | | 50,418 | | 50,202 | | 54,852 | | | 53,218 | | 50,418 | | 50,202 | |
| Diluted | | 50,603 | | 50,549 | | 55,850 | | | 53,609 | | 50,603 | | 50,549 | |
See accompanying notes.
-77--76-
HOLLY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | Years Ended December 31, | |
| | | 2009 | | 2008 | | 2007 | | | 2010 | | 2009 | | 2008 | |
Cash flows from operating activities: | | |
| Net income | | $ | 53,269 | | $ | 126,636 | | $ | 334,128 | | | $ | 133,051 | | $ | 53,269 | | $ | 126,636 | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | |
| Depreciation and amortization (includes discontinued operations) | | 99,633 | | 63,789 | | 43,456 | | | 117,529 | | 99,633 | | 63,789 | |
| SLC Pipeline earnings in excess of distributions | | | (419 | ) | | — | | — | | |
| SLC Pipeline distributions in excess of earnings (earnings in excess of distributions) | | | 482 | | | (419 | ) | | — | |
| Deferred income taxes | | 37,522 | | 32,934 | | 23,071 | | | 23,840 | | 37,522 | | 32,934 | |
| Distributions in excess of equity in earnings of Holly Energy Partners | | — | | 3,067 | | 3,688 | | | — | | — | | 3,067 | |
| Equity based compensation expense | | 7,549 | | 7,467 | | 9,993 | | | 11,498 | | 7,549 | | 7,467 | |
| Gain on sale of assets, before income taxes | | | (14,479 | ) | | | (5,958 | ) | | — | | | — | | | (14,479 | ) | | | (5,958 | ) |
| Change in fair value — interest rate swaps | | 175 | | 2,282 | | — | | | 1,464 | | 175 | | 2,282 | |
| Impairment of equity securities | | — | | 3,724 | | — | | | — | | — | | 3,724 | |
| (Increase) decrease in current assets: | | |
| Accounts receivable | | | (474,205 | ) | | 331,978 | | | (216,295 | ) | | | (228,466 | ) | | | (474,205 | ) | | 331,978 | |
| Inventories | | | (17,904 | ) | | 15,006 | | | (10,955 | ) | | | (96,854 | ) | | | (17,904 | ) | | 15,006 | |
| Income taxes receivable | | | (33,270 | ) | | 10,006 | | | (7,301 | ) | | | (14,990 | ) | | | (33,270 | ) | | 10,006 | |
| Prepayments and other | | | (15,816 | ) | | | (398 | ) | | 1,817 | | | 369 | | | (15,816 | ) | | | (398 | ) |
| Increase (decrease) in current liabilities: | | |
| Accounts payable | | 583,550 | | | (393,186 | ) | | 264,217 | | | 342,182 | | 583,550 | | | (393,186 | ) |
| Accrued liabilities | | 1,651 | | | (2,149 | ) | | | (16,476 | ) | | 22,414 | | 1,651 | | | (2,149 | ) |
| Income taxes payable | | — | | 1,781 | | — | | | — | | — | | 1,781 | |
| Turnaround expenditures | | | (33,541 | ) | | | (34,751 | ) | | | (2,669 | ) | | | (34,966 | ) | | | (33,541 | ) | | | (34,751 | ) |
| Other, net | | 17,830 | | | (6,738 | ) | | | (3,937 | ) | | 5,702 | | 17,830 | | | (6,738 | ) |
| | | | | | | | | | | | | | | |
Net cash provided by operating activities | | 211,545 | | 155,490 | | 422,737 | | | 283,255 | | 211,545 | | 155,490 | |
| | | |
Cash flows from investing activities: | | |
| Additions to properties, plants and equipment — Holly Corporation | | | (269,552 | ) | | | (383,742 | ) | | | (161,258 | ) | | | (188,129 | ) | | | (269,552 | ) | | | (383,742 | ) |
| Additions to properties, plants and equipment — Holly Energy Partners | | | (32,999 | ) | | | (34,317 | ) | | — | | | | (25,103 | ) | | | (32,999 | ) | | | (34,317 | ) |
| Acquisition of Tulsa Refinery facilities — Holly Corporation | | | (267,141 | ) | | — | | — | | | — | | | (267,141 | ) | | — | |
| Acquisition of logistics assets from Sinclair Oil Company — Holly Energy Partners | | | (25,665 | ) | | — | | — | | | — | | | (25,665 | ) | | — | |
| Investment in SLC Pipeline — Holly Energy Partners | | | (25,500 | ) | | — | | — | | | — | | | (25,500 | ) | | — | |
| Proceeds from sale of interest in Rio Grande Pipeline Company, net of transferred cash — Holly Energy Partners | | 31,865 | | — | | — | | | — | | 31,865 | | — | |
| Proceeds from sale of crude pipelines and tankage assets | | — | | 171,000 | | — | | | — | | — | | 171,000 | |
| Proceeds from sale of Holly Petroleum, Inc. | | — | | 5,958 | | — | | | — | | — | | 5,958 | |
| Increase in cash due to consolidation of Holly Energy Partners | | — | | 7,295 | | — | | | — | | — | | 7,295 | |
| Purchases of marketable securities | | | (175,892 | ) | | | (769,142 | ) | | | (641,144 | ) | | — | | | (175,892 | ) | | | (769,142 | ) |
| Sales and maturities of marketable securities | | 230,281 | | 945,461 | | 509,345 | | | — | | 230,281 | | 945,461 | |
| Investment in Holly Energy Partners | | — | | | (290 | ) | | — | | | — | | — | | | (290 | ) |
| | | | | | | | | | | | | | | |
Net cash used for investing activities | | | (534,603 | ) | | | (57,777 | ) | | | (293,057 | ) | | | (213,232 | ) | | | (534,603 | ) | | | (57,777 | ) |
| | | |
Cash flows from financing activities: | | |
| Proceeds from issuance of senior notes — Holly Corporation | | 287,925 | | — | | — | | |
| Proceeds from issuance of common units — Holly Energy Partners | | 133,035 | | — | | — | | |
| Borrowings under credit agreement — Holly Corporation | | 94,000 | | — | | — | | | 310,000 | | 94,000 | | — | |
| Repayments under credit agreement — Holly Corporation | | | (94,000 | ) | | — | | — | | | | (310,000 | ) | | | (94,000 | ) | | — | |
| Borrowings under credit agreement — Holly Energy Partners | | 239,000 | | 114,000 | | — | | | 66,000 | | 239,000 | | 114,000 | |
| Repayments under credit agreement — Holly Energy Partners | | | (233,000 | ) | | | (85,000 | ) | | — | | | | (113,000 | ) | | | (233,000 | ) | | | (85,000 | ) |
| Repayments under financing agreement — Holly Corporation | | | | (1,028 | ) | | — | | — | |
| Proceeds from issuance of senior notes — Holly Corporation | | | — | | 287,925 | | — | |
| Proceeds from issuance of senior notes — Holly Energy Partners | | | 147,540 | | — | | — | |
| Proceeds from issuance of common units — Holly Energy Partners | | | — | | 133,035 | | — | |
| Proceeds from Plains financing transaction | | 40,000 | | — | | — | | | — | | 40,000 | | — | |
| Deferred financing costs | | | (8,842 | ) | | | (913 | ) | | — | | | | (3,121 | ) | | | (8,842 | ) | | | (913 | ) |
| Purchase of treasury stock | | | (1,214 | ) | | | (151,106 | ) | | | (207,196 | ) | | | (1,368 | ) | | | (1,214 | ) | | | (151,106 | ) |
| Contribution from joint venture partner | | 15,150 | | 17,000 | | 8,333 | | | 23,500 | | 15,150 | | 17,000 | |
| Dividends | | | (30,123 | ) | | | (29,064 | ) | | | (23,208 | ) | | | (31,868 | ) | | | (30,123 | ) | | | (29,064 | ) |
| Distributions to noncontrolling interest | | | (33,200 | ) | | | (22,098 | ) | | — | | | | (48,493 | ) | | | (33,200 | ) | | | (22,098 | ) |
| Issuance of common stock upon exercise of options | | 134 | | 1,005 | | 2,288 | | | 118 | | 134 | | 1,005 | |
| Purchase of units for restricted grants | | | | (2,704 | ) | | | (616 | ) | | | (795 | ) |
| Excess tax (expense) benefit from equity based compensation | | | (1,209 | ) | | 5,694 | | 30,355 | | | | (1,094 | ) | | | (1,209 | ) | | 5,694 | |
| Other | | | (807 | ) | | | (795 | ) | | — | | | — | | | (191 | ) | | — | |
| | | | | | | | | | | | | | | |
Net cash provided by (used for) financing activities | | 406,849 | | | (151,277 | ) | | | (189,428 | ) | | 34,482 | | 406,849 | | | (151,277 | ) |
| | | |
Cash and cash equivalents: | | |
| | | |
Increase (decrease) for the period | | 83,791 | | | (53,564 | ) | | | (59,748 | ) | | 104,505 | | 83,791 | | | (53,564 | ) |
| Beginning of period | | | 40,805 | (1) | | 94,369 | | 154,117 | | | 124,596 | | 40,805 | | 94,369 | |
| | | | | | | | | | | | | | | |
End of period | | $ | 124,596 | | $ | 40,805 | (1) | | $ | 94,369 | | | $ | 229,101 | | $ | 124,596 | | $ | 40,805 | |
| | | | | | | | | | | | | | | |
| | | |
(1) Includes $1,561 in cash classified as current assets of discontinued operations at December 31, 2008. | | |
| | | |
Supplemental disclosure of cash flow information: | | |
| Cash paid during the period for | | |
| Interest | | $ | 39,995 | | $ | 14,346 | | $ | 818 | | | $ | 66,674 | | $ | 39,995 | | $ | 14,346 | |
| Income taxes | | $ | 19,344 | | $ | 21,084 | | $ | 139,400 | | | $ | 62,084 | | $ | 19,344 | | $ | 21,084 | |
See accompanying notes.
-78--77-
HOLLY CORPORATION
CONSOLIDATED STATEMENTS OF EQUITY
(In thousands)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Holly Corporation Stockholders’ Equity | | | Holly Corporation Stockholders’ Equity | | | | | |
| | | Accumulated | | | | | | | Accumulated Other | | Non- | | | |
| | | Other | | Non- | | | | |
| | | Common | | Additional | | Retained | | Comprehensive | | Treasury | | controlling | | | | |
| | | Stock | | Capital | | Earnings | | Income (Loss) | | Stock | | Interest | | Total Equity | | |
| | | |
Balance at December 31, 2006 | | $ | 718 | | $ | 66,500 | | $ | 745,994 | | $ | (11,358 | ) | | $ | (335,760 | ) | | $ | — | | $ | 466,094 | | |
| Net income | | — | | — | | 334,128 | | — | | — | | — | | 334,128 | | |
| Dividends | | — | | — | | | (25,148 | ) | | — | | — | | — | | | (25,148 | ) | |
| Other comprehensive loss | | — | | — | | — | | | (7,718 | ) | | — | | — | | | (7,718 | ) | |
| Contribution from joint venture partner | | — | | — | | — | | — | | — | | 8,333 | | 8,333 | | |
| Issuance of common stock upon exercise of stock options | | 11 | | 2,277 | | — | | — | | — | | — | | 2,288 | | |
| Tax benefit from stock options | | — | | 26,017 | | — | | — | | — | | — | | 26,017 | | |
| Issuance of restricted stock, net of forfeitures | | 4 | | 9,993 | | — | | — | | — | | — | | 9,997 | | |
| Other equity based compensation | | — | | 4,338 | | — | | — | | — | | — | | 4,338 | | |
| Purchase of treasury stock | | — | | — | | — | | — | | | (216,202 | ) | | — | | | (216,202 | ) | |
| | | | | | | | | | | | | | | | | | Common | | Additional | | Retained | | Comprehensive | | Treasury | | controlling | | | |
| | | | Stock | | Capital | | Earnings | | Income (Loss) | | Stock | | Interest | | Total Equity | |
Balance at December 31, 2007 | | $ | 733 | | $ | 109,125 | | $ | 1,054,974 | | $ | (19,076 | ) | | $ | (551,962 | ) | | $ | 8,333 | | $ | 602,127 | | | $ | 733 | | $ | 109,125 | | $ | 1,054,974 | | $ | (19,076 | ) | | $ | (551,962 | ) | | $ | 8,333 | | $ | 602,127 | |
| Reconsolidation of Holly Energy Partners (March 1, 2008) | | — | | — | | — | | — | | — | | 389,184 | | 389,184 | | | — | | — | | — | | — | | — | | 389,184 | | 389,184 | |
| Net income | | — | | — | | 120,558 | | — | | — | | 6,078 | | 126,636 | | | — | | — | | 120,558 | | — | | — | | 6,078 | | 126,636 | |
| Dividends | | — | | — | | | (30,144 | ) | | — | | — | | — | | | (30,144 | ) | | — | | — | | | (30,144 | ) | | — | | — | | — | | | (30,144 | ) |
| Distributions to noncontrolling interest holders | | — | | — | | — | | — | | — | | | (22,098 | ) | | | (22,098 | ) | | — | | — | | — | | — | | — | | | (22,098 | ) | | | (22,098 | ) |
| Other comprehensive loss | | — | | — | | — | | | (16,005 | ) | | — | | | (7,079 | ) | | | (23,084 | ) | | — | | — | | — | | | (16,005 | ) | | — | | | (7,079 | ) | | | (23,084 | ) |
| Contribution from joint venture partner | | — | | — | | — | | — | | — | | 18,500 | | 18,500 | | | — | | — | | — | | — | | — | | 18,500 | | 18,500 | |
| Issuance of common stock upon exercise of stock options | | 2 | | 1,003 | | — | | — | | — | | — | | 1,005 | | | 2 | | 1,003 | | — | | — | | — | | — | | 1,005 | |
| Tax benefit from stock options | | — | | 3,364 | | — | | — | | — | | — | | 3,364 | | | — | | 3,364 | | — | | — | | — | | — | | 3,364 | |
| Issuance of restricted stock, net of forfeitures | | — | | 5,476 | | — | | — | | — | | — | | 5,476 | | | — | | 5,476 | | — | | — | | — | | — | | 5,476 | |
| Other equity based compensation | | — | | 2,330 | | — | | — | | — | | 1,732 | | 4,062 | | | — | | 2,330 | | — | | — | | — | | 1,732 | | 4,062 | |
| Purchase of units for restricted grants | | — | | — | | — | | — | | — | | | (795 | ) | | | (795 | ) | | — | | — | | — | | — | | — | | | (795 | ) | | | (795 | ) |
| Purchase of treasury stock | | — | | — | | — | | — | | | (138,838 | ) | | — | | | (138,838 | ) | | — | | — | | — | | — | | | (138,838 | ) | | — | | | (138,838 | ) |
| Other | | — | | — | | — | | — | | — | | 937 | | 937 | | | — | | — | | — | | — | | — | | 937 | | 937 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
Balance at December 31, 2008 | | $ | 735 | | $ | 121,298 | | $ | 1,145,388 | | $ | (35,081 | ) | | $ | (690,800 | ) | | $ | 394,792 | | $ | 936,332 | | | $ | 735 | | $ | 121,298 | | $ | 1,145,388 | | $ | (35,081 | ) | | $ | (690,800 | ) | | $ | 394,792 | | $ | 936,332 | |
| Net income | | — | | — | | 19,533 | | — | | — | | 33,736 | | 53,269 | | | — | | — | | 19,533 | | — | | — | | 33,736 | | 53,269 | |
| Dividends | | — | | — | | | (30,580 | ) | | — | | — | | — | | | (30,580 | ) | | — | | — | | | (30,580 | ) | | — | | — | | — | | | (30,580 | ) |
| Distributions to noncontrolling interest holders | | — | | — | | — | | — | | — | | | (33,200 | ) | | | (33,200 | ) | | — | | — | | — | | — | | — | | | (33,200 | ) | | | (33,200 | ) |
| Elimination of noncontrolling interest upon HEP’s sale of Rio Grande Pipeline Company | | — | | — | | — | | — | | — | | | (8,718 | ) | | | (8,718 | ) | | — | | — | | — | | — | | — | | | (8,718 | ) | | | (8,718 | ) |
| Other comprehensive income | | — | | — | | — | | 9,381 | | — | | 2,021 | | 11,402 | | | — | | — | | — | | 9,381 | | — | | 2,021 | | 11,402 | |
| Issuance of common shares | | 28 | | 73,972 | | — | | — | | — | | — | | 74,000 | | | 28 | | 73,972 | | — | | — | | — | | — | | 74,000 | |
| Issuance of HEP common units, net of issuing costs | | — | | — | | — | | — | | — | | 186,801 | | 186,801 | | | — | | — | | — | | — | | — | | 186,801 | | 186,801 | |
| Contribution from joint venture partner | | — | | — | | — | | — | | — | | 13,650 | | 13,650 | | | — | | — | | — | | — | | — | | 13,650 | | 13,650 | |
| Issuance of common stock upon exercise of stock options | | 1 | | 134 | | — | | — | | — | | — | | 135 | | | 1 | | 134 | | — | | — | | — | | — | | 135 | |
| Tax benefit from stock options | | — | | 371 | | — | | — | | — | | — | | 371 | | | — | | 371 | | — | | — | | — | | — | | 371 | |
| Issuance of restricted stock, net of forfeitures | | — | | 5,270 | | — | | — | | — | | — | | 5,270 | | | — | | 5,270 | | — | | — | | — | | — | | 5,270 | |
| Other equity based compensation | | — | | | (5,480 | ) | | — | | — | | 6,083 | | 699 | | 1,302 | | | — | | | (5,480 | ) | | — | | — | | 6,083 | | 699 | | 1,302 | |
| Purchase of treasury stock | | — | | — | | — | | — | | | (1,214 | ) | | — | | | (1,214 | ) | | — | | — | | — | | — | | | (1,214 | ) | | — | | | (1,214 | ) |
| Other | | — | | — | | — | | — | | — | | | (1,039 | ) | | | (1,039 | ) | | — | | — | | — | | — | | — | | | (1,039 | ) | | | (1,039 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
Balance at December 31, 2009 | | $ | 764 | | $ | 195,565 | | $ | 1,134,341 | | $ | (25,700 | ) | | $ | (685,931 | ) | | $ | 588,742 | | $ | 1,207,781 | | | $ | 764 | | $ | 195,565 | | $ | 1,134,341 | | $ | (25,700 | ) | | $ | (685,931 | ) | | $ | 588,742 | | $ | 1,207,781 | |
| Net income | | | — | | — | | 103,964 | | — | | — | | 29,087 | | 133,051 | |
| Dividends | | | — | | — | | | (31,977 | ) | | — | | — | | — | | | (31,977 | ) |
| Distributions to noncontrolling interest holders | | | — | | — | | — | | — | | — | | | (48,493 | ) | | | (48,493 | ) |
| Other comprehensive loss | | | — | | — | | — | | | (546 | ) | | — | | | (1,623 | ) | | | (2,169 | ) |
| Contribution from joint venture partner | | | — | | — | | — | | — | | — | | 23,500 | | 23,500 | |
| Issuance of common stock upon exercise of stock options | | | — | | 118 | | — | | — | | — | | — | | 118 | |
| Tax benefit from stock options | | | — | | 416 | | — | | — | | — | | — | | 416 | |
| Issuance of restricted stock, net of forfeitures | | | — | | 7,773 | | — | | — | | — | | — | | 7,773 | |
| Other equity based compensation | | | | (1 | ) | | | (9,494 | ) | | — | | — | | 9,495 | | 2,215 | | 2,215 | |
| Purchase of treasury stock | | | — | | — | | — | | — | | | (1,368 | ) | | — | | | (1,368 | ) |
| Other | | | — | | — | | — | | — | | — | | | (2,708 | ) | | | (2,708 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
Balance at December 31, 2010 | | | $ | 763 | | $ | 194,378 | | $ | 1,206,328 | | $ | (26,246 | ) | | $ | (677,804 | ) | | $ | 590,720 | | $ | 1,288,139 | |
| | | | | | | | | | | | | | | | | |
See accompanying notes.
-79--78-
HOLLY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
| | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | | | | | | | | | | | |
| | | 2009 | | 2008 | | 2007 | | | Years Ended December 31, | |
| | | | 2010 | | 2009 | | 2008 | |
Net income | | $ | 53,269 | | $ | 126,636 | | $ | 334,128 | | | $ | 133,051 | | $ | 53,269 | | $ | 126,636 | |
| | | |
| Other comprehensive income (loss): | | |
| | | |
| Securities available-for-sale: | | |
| Unrealized gain (loss) on available-for-sale securities | | 173 | | 1,146 | | 1,857 | | | 114 | | 173 | | 1,146 | |
| Reclassification adjustment to net income on sale of securities | | 236 | | | (1,315 | ) | | | (78 | ) | |
| Reclassification adjustment to net income on sale of marketable securities | | | — | | 236 | | | (1,315 | ) |
| | | | | | | | | | | | | | | |
| Total unrealized gain (loss) on available-for-sale securities | | 409 | | | (169 | ) | | 1,779 | | | 114 | | 409 | | | (169 | ) |
| | | | | | | | | |
| | | |
| Hedging instruments: | | |
| Change in fair value of cash flow hedging instruments | | | | (1,999 | ) | | 3,726 | | | (12,967 | ) |
| Reclassification adjustment to net income on maturity/settlement of cash flow hedging instruments | | | 1,076 | | — | | — | |
| | | | | | | | | |
| Total unrealized gain (loss) on hedging instruments | | | | (923 | ) | | 3,726 | | | (12,967 | ) |
| | | |
| Retirement medical obligation adjustment | | 742 | | 1,433 | | | (5,038 | ) | | | (238 | ) | | 742 | | 1,433 | |
| Minimum pension liability adjustment | | 12,497 | | | (21,572 | ) | | | (9,373 | ) | | | (1,470 | ) | | 12,497 | | | (21,572 | ) |
| | | |
| Other comprehensive loss of Holly Energy Partners: | | |
| Change in fair value of cash flow hedge | | 3,726 | | | (12,967 | ) | | — | | |
| | | | | | | | | | | | | | | |
| | | |
| Other comprehensive income (loss) before income taxes | | 17,374 | | | (33,275 | ) | | | (12,632 | ) | | | (2,517 | ) | | 17,374 | | | (33,275 | ) |
| | | |
| Income tax expense (benefit) | | 5,972 | | | (10,191 | ) | | | (4,914 | ) | | | (348 | ) | | 5,972 | | | (10,191 | ) |
| | | | | | | | | | | | | | | |
| | | |
| Other comprehensive income (loss) | | 11,402 | | | (23,084 | ) | | | (7,718 | ) | | | (2,169 | ) | | 11,402 | | | (23,084 | ) |
| | | | | | | | | | | | | | | |
| | | |
| Total comprehensive income | | 64,671 | | 103,552 | | 326,410 | | | 130,882 | | 64,671 | | 103,552 | |
| | | |
| Less noncontrolling interest in comprehensive income (loss) | | 35,757 | | (1,001 | ) | | — | | | 27,464 | | 35,757 | | | (1,001 | ) |
| | | | | | | | | | | | | | | |
| | | |
Comprehensive income attributable to Holly Corporation stockholders | | $ | 28,914 | | $ | 104,553 | | $ | 326,410 | | | $ | 103,418 | | $ | 28,914 | | $ | 104,553 | |
| | | | | | | | | | | | | | | |
See accompanying notes.
-80--79-
HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1: Description of Business and Summary of Significant Accounting Policies
Description of Business:References herein to Holly Corporation include Holly Corporation and its consolidated subsidiaries. In accordance with the Securities and Exchange Commission’s (“SEC”) “Plain English” guidelines, this Annual Report on Form 10-K 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. For periods after our reconsolidation of Holly Energy Partners, L.P. (“HEP”) effective March 1, 2008, the words “we,” “our,” “ours” and “us” generally include HEP and its subsidiaries as consolidated subsidiaries of Holly Corporation with certain exceptions. This document containsexceptions 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.
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. See Note 2 for additional information on the Tulsa Refinery facilities acquired in 2009.
At December 31, 2009,2010, we owned a 34% interest in HEP, a consolidated subsidiary,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 both our Navajo, and 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 refiners in the Salt Lake City area.
On June 1, 2009, we acquired an 85,000 BPSD refinery in Tulsa, Oklahoma (the “Tulsa Refinery west facility”) from an affiliate of Sunoco, Inc. (“Sunoco”). On December 1, 2009, we acquired a 75,000 BSPD refinery that is also located in Tulsa, Oklahoma (the “Tulsa Refinery east facility”) from an affiliate of Sinclair Oil Company (“Sinclair”). We are in the process of integrating the operations of both Tulsa Refinery facilities. Upon completion, the Tulsa Refinery will have an integrated crude processing rate of 125,000 BSPD. See Note 2 for additional information on our 2009 Tulsa Refinery facility acquisitions.
On February 29, 2008, HEP acquired certain crude pipelines and tankage assets from us (the “Crude Pipelines and Tankage Assets”) that service our Navajo and Woods Cross Refineries (see Note 3).
We sold substantially all of the oil and gas properties of Holly Petroleum, Inc. (“HPI”), a subsidiary that previously conducted a small-scale oil and gas exploration and production program, in 2008 for $6 million, resulting in a gain of $6 million.
Principles of Consolidation:Our consolidated financial statements include our accounts and the accounts of partnerships and joint ventures that we control through a 50% or more ownership interest or through 50% or more variablea controlling financial interest in entities that are consideredwith respect to variable interest entities. All significant intercompany transactions and balances have been eliminated.
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Use of Estimates: The preparation of financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”) requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.
These consolidated financial statements reflect management’s evaluation of subsequent events through the time of our filing of this annual report on Form 10-K on February 26, 2010.
Reclassifications: There have been certain reclassifications to our December 31, 2008 deferred income tax information under Note 13, “Income Taxes” to conform to current year presentation.
Cash Equivalents:We consider all highly liquid instruments with a maturity of three months or less at the date of purchase to be cash equivalents. Cash equivalents are stated at cost, which approximates market value and are primarily invested in conservative, highly-rated instruments issued by financial institutions or government entities with strong credit standings.
Marketable Securities:We consider all marketable debt securities with maturities greater than three months at the date of purchase to be marketable securities. Our marketable securities are primarily issued by government entities with the maximum maturity of any individual issue not more than two years, while the maximum duration of the
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portfolio of investments is not greater than one year. These instruments are classified as available-for-sale, and as a result, are reported at fair value. Unrealized gains and losses, net of related income taxes, are reported as a component of accumulated other comprehensive income.
Accounts Receivable:The majority of the accounts receivable are due from companies in the petroleum industry. Credit is extended based on evaluation of the customer’s financial condition and in certain circumstances, collateral, such as letters of credit or guarantees, is required. We reserve for doubtful accounts based on current sales levels as well as specific accounts identified as high risk, which historically have been minimal. Credit losses are charged to incomethe allowance for doubtful accounts when an account is deemed uncollectible. Our allowance for doubtful accounts are deemed uncollectiblewas $2.1 million and historically have been minimal. $2.5 million at December 31, 2010 and 2009, respectively.
Accounts receivable attributable to crude oil resales generally represent the sell side of excess crude oil sales to other purchasers and / or users in cases when our crude oil supplies are in excess of our immediate needs as well as certain reciprocal buy /sell exchanges of crude oil. At times we enter into such buy / sell exchanges to facilitate the delivery of quantities to certain locations. In many cases, we enter into net settlement agreements relating to the buy/sell arrangements, which may mitigate credit risk.
Inventories:Inventories are stated at the lower of cost, using the last-in, first-out (“LIFO”) method for crude oil and refined products and the average cost method for materials and supplies, or market. Cost is determined using the LIFO inventory valuation methodology and market is determined using current estimated selling prices. Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. In periods of rapidly declining prices, LIFO inventories may have to be written down to market due to the higher costs assigned to LIFO layers in prior periods. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years that inventory volumes decline as the result of charging cost of sales with LIFO inventory costs generated in prior periods. An actual valuation of inventory under the LIFO method can be made only at the end of each year based on the inventory levels at that time. Accordingly, interim LIFO calculations are based on management’s estimates of expected year-end inventory levels and are subject to the final year-end LIFO inventory valuation.
Long-lived assets:We calculate depreciation and amortization based on estimated useful lives and salvage values of our assets. We evaluate long-lived assets for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset’s carrying value exceeds its fair value. No impairments of long-lived assets were recorded during the years ended December 31, 2010, 2009 2008 and 2007.2008.
Asset Retirement Obligations:We record legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of long-lived assets. The fair value of the estimated cost to retire a tangible long-lived asset is recorded as a liability with the associated retirement costs capitalized as part of the asset’s carrying amount in the period in which the liabilityit is incurred and when a reasonable estimate of the fair value of the liability can be made. If a reasonable estimate cannot be made at the time the liability is incurred, we record the liability when sufficient information is available to estimate the liability’s fair value.
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We have asset retirement obligations with respect to certain assets due to legal obligations to clean and/or dispose of various component parts at the time they are retired. At December 31, 2009,2010, we have an asset retirement obligation of $7.2$7.5 million, which is included in “Other long-term liabilities” in our consolidated balance sheets. This includes $5.8 million in asset retirement obligations acquired in connection with our Tulsa Refinery facility acquisitions in 2009 (see Note 2). Accretion expense was insignificant for the years ended December 31, 2010, 2009 2008 and 2007.2008.
Intangibles and Goodwill:Intangible assets are assets (other than financial assets) that lack physical substance. Goodwill represents the excess of the cost of an acquired entity over the fair value of the assets acquired less liabilities assumed. Goodwill acquired in a business combination and intangible assets with indefinite useful lives are not amortized and intangible assets with finite useful lives are amortized on a straight line basis. Goodwill and intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired.
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As of December 31, 2009,2010, our goodwill balance was $81.6 million. We recorded $32.5 million in goodwill due to our reconsolidation of HEP effective March 1, 2008. Additionally, HEP recorded $49.1 million in goodwill related to its acquisition of certain logistics and storage assets from Sinclair in December 2009 (see Note 3). Based on our impairment assessment as of December 31, 2009,2010, we determined that the fair value of the reporting unit’s goodwill exceeded the carrying value and therefore no impairment has occurred.
In addition to goodwill, our consolidated HEP assets include a third-party transportation agreement that currently generates minimum annual cash inflows of $21.7$22.7 million and has an expected remaining term through 2035. The transportation agreement is being amortized on a straight-line basis through 2035 that results in annual amortization expense of $2 million. At December 31, 2009,2010, the balance of this transportation agreement was $50.3$48.5 million, net of accumulated amortization of $9.7$11.7 million, which is included in “Intangible“Intangibles and Others”other” in our consolidated balance sheets.
The transportation agreement was evaluated for impairment as of December 31, 2009. Based on the evaluation, it was determined that projected cash flows to be received under the agreement substantially exceeded the carrying balance of the agreement.
There were no impairments of intangible assets or goodwill during the years ended December 31, 2010, 2009 2008 and 2007.2008.
Variable Interest Entity:HEP is a variable interest entity (“VIE”)VIE as defined under GAAP. A VIE is a legal entity whose equity owners do not have sufficient equity at risk or a controlling interest in the entity, or have voting rights that are not proportionate to their economic interest. As the general partner of HEP, we have the sole ability to direct the activities of HEP that most significantly impact HEP’s economic performance. Additionally, since our obligation to absorb losses and receive benefits from HEP are significant to HEP, we are HEP’s primary beneficiary and therefore we consolidate HEP.
Under GAAP, HEP’s acquisition of the Crude Pipelines and Tankage Assets (see Note 3) qualified as a reconsideration event whereby we reassessed whether HEP continued to qualify as a VIE. Following this transfer, we determined that HEP continued to qualify as a VIE, and furthermore, we determined that our beneficial interest in HEP exceeded 50%. Accordingly, weWe reconsolidated HEP effective March 1, 2008, following its acquisition of our crude pipeline and no longer accounttankage assets (see Note 3). Prior to March 1, 2008, we accounted for our investment in HEP under the equity method of accounting. As a result, our consolidated financial statements include the results of HEP. Additionally, HEP’s 2009 asset acquisitions and its November and May 2009 equity offerings qualified as reconsideration events whereby we determined that HEP continues to qualify as a VIE and we remain HEP’s primary beneficiary.
Underusing the equity method of accounting prior to March 1, 2008,whereby we recorded our pro-rata share of earnings in HEP. Contributions to and distributions from HEP were recorded as adjustments to our investment balance.
Investments in Joint Ventures:We consolidate the results of joint ventures in which we have an ownership interest of greater than 50% and use the equity method of accounting for investments in which we have a 50% or less ownership interest.
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In March 2009, HEP acquired a 25% joint venture interest in the SLC Pipeline that is accounted for using the equity method of accounting. As of December 31, 2009,2010, HEP’s underlying equity in the SLC Pipeline was $63$61.2 million compared to its recorded investment balance of $25.9$25.4 million, a difference of $37.1$35.8 million. This is attributable to the difference between HEP’s contributed capital and its allocated equity at formation of the SLC Pipeline. This difference is being amortized as an adjustment to HEP’s pro-rata share of earnings.
Derivative Instruments:All derivative instruments are recognized as either assets or liabilities in theour consolidated balance sheetsheets and are measured at fair value. Changes in the derivative instrument’s fair value are recognized in earnings unless specific hedge accounting criteria are met. See Note 12, Debt13, Derivative Instruments and Hedging Activities for additional information on HEP’s interest rate swap and hedging activities.
Noncontrolling Interest:Accounting standards became effective January 1, 2009 that change the classification of noncontrolling interests, also referred to as minority interests, in the consolidated financial statements. As a result, all previous references to “minority interest” in our consolidated financial statements have been replaced with “noncontrolling interest.” Therefore, net income attributable to the noncontrolling interest in our HEP subsidiary is now presented as an adjustment to net income to arrive at “Net income attributable to Holly Corporation stockholders” in our Consolidated Statements of Income. Prior to 2009, this amount was presented as “Minority interest in earnings of HEP,” a non-operating expense item before “Income before income taxes.” Additionally, equity attributable to noncontrolling interests is now presented as a separate component of total equity in our consolidated financial statements. We have adopted these standards on a retrospective basis. While this presentation differs from previous requirements under GAAP, it did not affect our net income and equity attributable to Holly Corporation stockholders.information.
Revenue Recognition:Refined product sales and related cost of sales are recognized when products are shipped and title has passed to customers. PipelineHEP recognizes pipeline transportation revenues are recognized as products are shipped on ourthrough its pipelines. All revenues are reported inclusive of shipping and handling costs billed and exclusive of any taxes billed to customers. Shipping and handling costs incurred are reported in cost of products sold.
Depreciation:Depreciation is provided by the straight-line method over the estimated useful lives of the assets, primarily 12 to 25 years for refining, facilities, 10 to 25 years for pipeline and terminal facilities, 3 to 5 years for transportation vehicles, 10 to 40 years for buildings and improvements and 75 to 30 years for other fixed assets.
Cost Classifications:Costs of products sold include the cost of crude oil, other feedstocks, blendstocks and purchased finished products, inclusive of transportation costs. 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
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that are recorded on a gross basis with the sales price recorded as revenues and the corresponding acquisition cost 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. Operating expenses include direct costs of labor, maintenance materials and services, utilities, marketing expense and other direct operating costs. General and administrative expenses include compensation, professional services and other support costs.
Deferred Maintenance Costs:Our refinery units require regular major maintenance and repairs which are commonly referred to as “turnarounds”. Catalysts used in certain refinery processes also require regular “change-outs”. The required frequency of the maintenance varies by unit and by catalyst, but generally is every two to five years. Turnaround costs are deferred and amortized over the period until the next scheduled turnaround. Other repairs and maintenance costs are expensed when incurred.
Environmental Costs:Environmental costs are charged to operating expenses if they relate to an existing condition caused by past operations and do not contribute to current or future revenue generation. Liabilities are recorded when site restoration and environmental remediation, cleanup and other obligations are either known or considered probable and can be reasonably estimated. Such estimates require judgment with respect to costs, timeframe and extent of required remedial and clean-up activities and are subject to periodic adjustments based on currently available information. Recoveries of environmental costs through insurance, indemnification arrangements or other sources are included in other assets to the extent such recoveries are considered probable.
Contingencies:We are subject to proceedings, lawsuits and other claims related to environmental, labor, product and other matters. We are required to assess the likelihood of any adverse judgments or outcomes to these matters as well as potential ranges of probable losses. A determination of the amount of reserves required, if any, for these contingencies is made after careful analysis of each individual issue. The required reserves may change in the future due to new developments in each matter or changes in approach such as a change in settlement strategy in dealing with these matters.
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Income Taxes:Provisions for income taxes include deferred taxes resulting from temporary differences in income for financial and tax purposes, using the liability method of accounting for income taxes. The liability method requires the effect of tax rate changes on current and accumulated deferred income taxes to be reflected in the period in which the rate change was enacted. The liability method also requires that deferred tax assets be reduced by a valuation allowance unless it is more likely than not that the assets will be realized.
Potential interest and penalties related to income tax matters are recognized in income tax expense. We believe we have appropriate support for the income tax positions taken and to be taken on our income tax returns and that our accruals for tax liabilities are adequate for all open years based on an assessment of many factors, including past experience and interpretations of tax law applied to the facts of each matter.
New Accounting Pronouncements:
In June 2009, new accounting standards were issued that replace the previous quantitative-based risk and rewards calculation provided under GAAP with a qualitative approach in determining whether an entity is the primary beneficiary of a VIE. Additionally, these standards require an entity to assess on an ongoing basis whether it is the primary beneficiary of a VIE and enhances disclosure requirements with respect to an entity’s involvement in a VIE. These standards are effective January 1, 2010 and will not have a material impact on our financial condition, results of operations and cash flows.
NOTE 2: Tulsa Refinery Acquisition
On June 1, 2009, we acquired the Tulsa Refinery west facility, an 85,000 BPSD refinery located in Tulsa, Oklahoma from Sunoco for $157.8 million in cash, including crude oil, refined product and other inventories valued at $92.8 million. The refinery produces fuel products including gasoline, diesel fuel and jet fuel and serves markets in the Mid-Continent region of the United States and also produces specialty lubricant products that are marketed throughout North America and are distributed in Central and South America. On October 20, 2009, we sold to an affiliate of Plains All American Pipeline, L.P. (“Plains”) a portion of the crude oil petroleum storage, and certain refining-related crude oil receiving pipeline facilities that were acquired as part of the refinery assets for $40 million. Due to our continuing involvement in these assets, this transaction has been accounted for as a financing transaction (see Note 12).
On December 1, 2009, we acquired the Tulsa Refinery east facility, a 75,000 BPSD refinery from an affiliate of Sinclair Oil Company (“Sinclair”) also located in Tulsa, Oklahoma for $183.3 million, including crude oil, refined product and other inventories valued at $46.4 million. The total purchase price consisted of $109.3 million in cash and 2,789,155 shares of our common stock having a value of $74 million. Additionally, we will reimbursereimbursed Sinclair approximately $8$8.4 million upon their satisfactory completion of certain environmental projects at the refinery.refinery in July 2010. The refinery also produces gasoline, diesel fuel and jet fuel products and also serves markets in the Mid-Continent region of the
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United States. We are integrating the operations of both Tulsa refineryRefinery facilities. This will result in the Tulsa Refinery having an integrated crude processing rate of 125,000 BPSD.
In accounting for these combined acquisitions, we recorded $20.6 million in materials and supplies, $139.2 million in crude oil and refined products inventory, $203.8 million in property,properties, plants and equipment, $8.2 million in prepayments and other, $6.3 million in accrued liabilities and $24.4 million in other long-term liabilities. The acquired liabilities primarily relate to environmental and asset retirement obligations. These amounts are based on management’s preliminary fair value estimates and are subject to change. Additionally, we incurred $3.1 million in costs directly related to these acquisitions that were expensed as acquisition costs.
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For the period from June 1, 2009 (commencement date of our Tulsa Refinery operations) through December 31, 2009, our Tulsa Refinery generated revenues of $1.1 billion and a net loss of $17.7 million. We have not provided disclosure of pro forma revenues and earnings as if the Tulsa Refinery had been operating as a part of our refining business during all periods presentedcosts in these financial statements. Pro forma financial information specific to the Tulsa Refinery operations for periods prior to our acquisition is not available in GAAP form. The compilation of such financial information would entail an extremely manual process of “unwinding” significant volumes of intra-company transactions and obtaining a comprehensive understanding of accounting policies as well as estimates employed by both Sunoco and Sinclair with respect to items including, but not limited to, inventory and depreciation. We would then need to recast historical financial information to reflect our own estimates and accounting policies. Furthermore, our operating plan with respect to these facilities is distinctly different from the pre-acquisition operations of these assets as we are fully integrating the operations of both facilities into a single refinery having a reduced integrated crude processing rate of 125,000 BPSD rather than as two distinct facilities. Therefore, we do not believe that it would be practical to produce this information, nor do we believe it would be representative or comparable with respect to our future operating results.2009.
NOTE 3: Holly Energy Partners
HEP, a consolidated VIE, is a publicly held master limited partnership that commencedwas 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 July 13, 2004 uponin 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 December 31, 2010, we owned a 34% interest in HEP, including the completion2% general partner interest. We are HEP’s primary beneficiary and therefore we consolidate HEP. See Note 21 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 80% of HEP’s total revenues for the year ended December 31, 2010. 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 initial public offering. senior notes. With the exception of the assets of HEP Logistics Holdings, L.P., one of our wholly-owned subsidiaries and HEP’s general partner, HEP’s creditors have no recourse to our assets. Any recourse to HEP’s 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 12 for a description of HEP’s debt obligations.
At December 31, 2009,2010, we held 7,290,000have an agreement to pledge 5,000,000 of our HEP common units to collateralize certain crude oil purchases in 2011. These units represent a 22% ownership interest in HEP.
HEP has risk associated with its operations. If a major shipper of HEP representingwere 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 34%new customer is not found. In the event that HEP incurs a loss, our operating results will reflect HEP’s loss, net of intercompany eliminations, to the extent of our ownership interest in HEP includingat that point in time.
2010 Acquisitions
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 2% general partner interest. In August 2009, all of the conditions necessary to end the subordination period ofTulsa Refinery east facility and an asphalt loading rack facility located at our HEP subordinated units were met and the units were converted into 7,000,000 HEP common units.
HEP is a variable interest entity as defined under GAAP. HEP’s acquisition of the Crude Pipelines and Tankage Assets (discussed below) qualified as a reconsideration event whereby we reassessed whether HEP continued to qualify as a VIE. Following this transfer, we determined that HEP continued to qualify as a VIE, and furthermore, we determined that our beneficial interestNavajo Refinery facility located in HEP exceeded 50%. Accordingly, we reconsolidated HEP effective March 1, 2008 and no longer account for our investment in HEP under the equity method of accounting. As a result, our consolidated financial statements include the results of HEP. Additionally, HEP’s 2009 asset acquisitions and its November and May 2009 equity offerings (discussed below) qualified as reconsideration events whereby we determined that HEP continues to qualify as a VIE and we remain HEP’s primary beneficiary.Lovington, New Mexico.
2009 Acquisitions
Sinclair Logistics and Storage Assets Transaction
On December 1, 2009, HEP acquired certain logistics and storage assets from an affiliate of Sinclair for $79.2 million consisting of storage tanks having approximately 1.4 million barrels of storage capacity and loading racks at Sinclair’s refinery located inwhat is now our Tulsa Oklahoma.Refinery east facility for $79.2 million. The purchase price
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consisted of $25.7 million in cash, including $4.2 million in taxes and 1,373,609 of HEP’s common units having a fair value of $53.5 million. Concurrent with this transaction we entered into a 15-year pipeline, tankage and loading rack throughput agreement with HEP (the “HEP PTTA”), whereby we agreed to transport, throughput and load volumes of product via HEP’s Tulsa logistics and storage assets that will initially result in minimum annual payments to HEP of $13.8 million.
Roadrunner / Beeson Pipelines Transaction
Also on December 1, 2009, HEP acquired our two newly constructed pipelines for $46.5 million, consisting of a 65-mile, 16-inch crude oil pipeline (the “Roadrunner Pipeline”) that connects our Navajo Refinery facility located in Lovington New Mexicofacility to a terminus of Centurion Pipeline L.P.’s pipeline extending between west Texas and Cushing, Oklahoma (the “Centurion Pipeline”) and a 37-mile, 8-inch crude oil pipeline that connects HEP’s New Mexico crude oil gathering system to our Navajo Refinery Lovington facility (the “Beeson Pipeline”).
The Roadrunner Pipeline provides our Navajo Refinery with direct access to a wide variety of crude oils available at Cushing, Oklahoma. In connection with this transaction, we entered into a 15-year pipeline agreement with HEP, (the “HEP RPA”), whereby we agreed to transport volumes of crude oil on HEP’s Roadrunner Pipeline that will initially result in minimum annual payments to HEP of $9.2 million.
The Beeson Pipeline operates as a component of HEP’s crude pipeline system and provides us with added flexibility to move crude oil from HEP’s crude oil gathering system to our Navajo Refinery Lovington facility for processing.
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Tulsa West Loading Racks Transaction
On August 1, 2009, HEP acquired from us, certain truck and rail loading/unloading facilities located at our Tulsa Refinery west facility for $17.5 million. The racks load refined products and lube oils produced at the Tulsa Refinery onto rail cars and/or tanker trucks.
In connection with this transaction, we entered into a 15-year equipment and throughput agreement with HEP, (the “HEP ETA”), whereby we agreed to throughput a minimum volume of products via HEP’s Tulsa loading racks that will initially result in minimum annual payments to HEP of $2.7 million.
Lovington-Artesia Pipeline Transaction
On June 1, 2009, HEP acquired our newly constructed, 16-inch intermediate pipeline for $34.2 million. The pipelinemillion that runs 65 miles from our Navajo Refinery’s crude oil distillation and vacuum facilities in Lovington, New Mexico to its petroleum refinery located in Artesia, New Mexico. This pipeline was placed in service effective June 1, 2009 and operates as a component of HEP’s intermediate pipeline system that services our Navajo Refinery.
In connection with this transaction, we agreed to amend our intermediate pipeline agreement with HEP (the “HEP IPA”). As a result, the term of the HEP IPA was extended by an additional four years and now expires in June 2024. Additionally, our minimum commitment under the HEP IPA was increased and currently, results in minimum annual payments to HEP of $20.7 million.
Since HEP is a consolidated subsidiary,VIE, our transactions with HEP including fees paid under our transportation agreements with HEP are eliminated and have no impact on our consolidated financial statements.
SLC Pipeline Joint Venture Interest
On March 1, 2009, HEP acquired a 25% joint venture interest in the SLC Pipeline, a new 95-mile intrastate pipeline system jointly owned with Plains. The SLC Pipeline commenced operations effective March 2009 and allows various refineries in the Salt Lake City area, including our Woods Cross Refinery, to ship crude oil into the Salt Lake City area from the Utah terminus of the Frontier Pipeline as well as crude oil flowing from Wyoming and Utah via Plains’ Rocky Mountain Pipeline. HEP’s capitalized joint venture contribution was $25.5 million.
Rio Grande Pipeline Sale
On December 1, 2009, HEP sold its 70% interest in Rio Grande Pipeline Company (“Rio Grande”) to a subsidiary of Enterprise Products Partners LP for $35 million. Accordingly, the resultsResults of operations of Rio Grande and the $14.5 million gain on the sale are presented in discontinued operations.
In accounting for the sale, HEP recorded a gain of $14.5 million.million and a receivable of $2.2 million representing its final distribution from Rio Grande. The recorded net asset balance of Rio Grande at December 1, 2009, was $20.5$22.7 million, consisting of cash of $3.1 million, $29.9 million in properties and equipment, net $2.2 million in accounts payable and $10.3 million in equity, representing BP, Plc’s 30% noncontrolling interest.
The following table provides income statement information related to discontinued operations:
| | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | Years Ended December 31, | |
| | | 2009 | | 2008 | | 2007 | | | 2009 | | 2008 | |
| | | (In thousands) | | | (In thousands) | |
| Income from discontinued operations before income taxes | | $ | 5,367 | | $ | 3,716 | | $ | — | | | $ | 5,367 | | $ | 3,716 | |
| Income tax expense | | | (942 | ) | | | (798 | ) | | — | | | | (942 | ) | | | (798 | ) |
| | | | | | | | | | | | | |
| Income from discontinued operations, net | | 4,425 | | 2,918 | | — | | | 4,425 | | 2,918 | |
| | | |
| Gain on sale of discontinued operations before income taxes | | 14,479 | | — | | — | | | 14,479 | | — | |
| Income tax expense | | | (1,978 | ) | | — | | — | | | | (1,978 | ) | | — | |
| | | | | | | | | | | | | |
| Gain on sale of discontinued operations, net | | 12,501 | | — | | — | | | 12,501 | | — | |
| | | | | | | | | | | | | |
| | | |
| Income from discontinued operations, net | | $ | 16,926 | | $ | 2,918 | | $ | — | | | $ | 16,926 | | $ | 2,918 | |
| | | | | | | | | | | | | |
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2008 Crude Pipelines and Tankage Transaction
On February 29, 2008, we closed on the sale of the Crude Pipelinessold certain crude pipelines and Tankage Assetstankage assets to HEP for $180 million. The assets consisted of crude oil trunk lines that deliver crude oil to our Navajo Refinery in southeast New Mexico, gathering and connection pipelines located in west Texas and New Mexico, on-site crude tankage located within the Navajo and Woods Cross Refinery complexes, a jet fuel products pipeline between Artesia and Roswell, New Mexico and a leased jet fuel terminal in Roswell, New Mexico. Consideration received consisted of $171 million in cash and 217,497 HEP common units having a fair value of $9 million. At the time of this transaction, HEP was not a consolidated entity, therefore, the assets were transferred at fair value.
Under GAAP, HEP’s acquisition of these assets qualified as a reconsideration event whereby we reassessed whether HEP continued to qualify as a VIE. Following this transfer, we determined that HEP continued to qualify as a VIE, and furthermore, we determined that our beneficial interest in HEP exceeded 50%. Therefore, we reconsolidated HEP effective March 1, 2008.
The balance sheet impact of our reconsolidation of HEP on March 1, 2008 was an increase in cash of $7.3 million, an increase in other current assets of $5.9 million, an increase in property,properties, plant and equipment of $336.9 million, an increase in goodwill, intangibles and other assets of $86.5 million, an increase in current liabilities of $19.6 million, an increase in long-term debt of $338.5 million, an increase in deferred income taxes of $5 million, a decrease in other long-term liabilities of $0.5 million, an increase in minority interest of $389.1 million and a decrease in distributions in excess of investment in HEP of $315.1 million.
Transportation Agreements
HEP serves our refineries in New Mexico, Utah and Oklahoma under several long-term pipeline and terminal, tankage and throughput agreements.
In connection with our 2009 asset transfers to HEP, as described above, we entered into three new 15-year transportation agreements with HEP, each expiring in 2024.
In addition we have an agreement that relates to the pipelines and terminals contributed to HEP by us at the time of their initial public offering in 2004 and expires in 2019 (the “HEP PTA”). We also have the HEP IPA that relates to the intermediate pipelines sold to HEP in 2005 and in June 2009 and expires in 2024 and an agreement that relates to the Crude Pipelines and Tankage Assets sold to HEP also discussed above that expires in February 2023 (the “HEP CPTA”) | • | | 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); |
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| • | | HEP IPA (intermediate pipelines throughput agreement expiring in 2024 that relates to the intermediate pipelines sold to HEP in 2005 and 2009); |
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| • | | 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); |
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| • | | 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); |
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| • | | HEP RPA (pipeline throughput agreement expiring in 2024 that relates to the Roadrunner Pipeline sold to HEP in 2009); |
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| • | | HEP ETA (equipment and throughput agreement expiring in 2024 that relates to the Tulsa west loading rack facilities sold to HEP in 2009); |
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| • | | HEP NPA (natural gas pipeline throughput agreement expiring in 2024); and |
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| • | | 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 HEP’s pipeline and terminal, tankage and loading rack facilities that result in minimum annual payments to HEP. These minimum annual payments are adjusted each year at a percentage change based upon the change in the Producer Price Index (“PPI”) but will not decrease as a result of a decrease in the PPI. Under these agreements, the agreed upon tariff rates are adjusted each year on July 1 at a rate based upon the percentage change in 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. The FERC index is the change in the PPI plus a FERC adjustment factor that is reviewed periodically. Following the July 1, 20092010 PPI rate adjustments, these agreements including our new 2009 agreements with HEP, will result in minimum annualized payments to HEP of $118.5 million for the twelve months ending June 30, 2010.
Additionally, in February 2010, we entered into a pipeline systems operating agreement with HEP expiring in 2014 (the “HEP Pipeline Operating Agreement”). Under the HEP Pipeline Operating Agreement, effective December 1, 2009, HEP will operate certain of our tankage, pipelines, asphalt racks and terminal buildings for an annual management fee of $1.3$133 million.
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HEP Equity Offerings
In November 2009, HEP closed on a public offering ofissued 2,185,000 of its common units including 285,000 common units issued pursuant to the underwriters’ exercise of their over-allotment option.priced at $35.78 per unit. Aggregate net proceeds of $74.9 million were used to fund the cash portion of HEP’s December 1, 2009 asset acquisitions, to repay outstanding borrowings under the HEP Credit Agreement and for general partnership purposes.
Additionally in May 2009, HEP closed a public offering ofissued 2,192,400 of its common units including 192,400 common units issued pursuant to the underwriters’ exercise of their over-allotment option.priced at $27.80 per unit. Net proceeds of $58.4 million were used to repay outstanding borrowings under the HEP Credit Agreement and for general partnership purposes.
Transactions prior to Reconsolidation
We have related party transactions with HEP for pipeline and terminal expenses, certain employee costs, insurance costs and administrative costs under our long-term transportation agreements and our omnibus agreement with HEP. Effective March 1, 2008, we reconsolidated HEP. As a result, our financial statements include the consolidated results of HEP and intercompany transactions with HEP are eliminated. Related party transactions prior to our reconsolidation of HEP are as follows:
Pipeline and terminal expenses paid to HEP were $10.6 million for the period from January 1, 2008 through February 29, 2008 and $61 million for the year ended December 31, 2007, respectively. | • | | Pipeline and terminal expenses paid to HEP were $10.6 million for the period from January 1, 2008 through February 29, 2008. |
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| • | | We charged HEP $0.4 million for the period from January 1, 2008 through February 29, 2008 for general and administrative services under an omnibus agreement that we have with HEP that we recorded as a reduction in expenses. |
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| • | | HEP reimbursed us for costs of employees supporting their operations of $2.1 million for the period from January 1, 2008 through February 29, 2008 which we recorded as a reduction in expenses. |
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| • | | We received as regular distributions on our subordinated units, common units and general partner interest $6.1 million for the period from January 1, 2008 through February 29, 2008. Our distributions included $0.7 million for the period from January 1, 2008 through February 29, 2008 in incentive distributions with respect to our general partner interest. |
We charged HEP $0.4 million for the period from January 1, 2008 through February 29, 2008 and $2 million for the year ended December 31, 2007, respectively, for general and administrative services under an omnibus agreement that we have with HEP that we recorded as a reduction in expenses.
HEP reimbursed us for costs of employees supporting their operations of $2.1 million for the period from January 1, 2008 through February 29, 2008 and $8.5 million for the year ended December 31 2007, respectively, which we recorded as a reduction in expenses.
We reimbursed HEP $0.3 million for the year ended December 31, 2007 for certain costs paid on our behalf.
We received as regular distributions on our subordinated units, common units and general partner interest $6.1 million for the period from January 1, 2008 through February 29, 2008 and $22.8 million for the year ended December 31, 2007, respectively. Our distributions included $0.7 million for the period from January 1, 2008 through February 29, 2008 and $2.2 million for the year ending December 31, 2007, respectively, in incentive distributions with respect to our general partner interest.
We had a related party receivable from HEP of $6 million at February 29, 2008 and December 31, 2007.
We had accounts payable to HEP of zero and $5.7 million at February 29, 2008 and December 31, 2007, respectively.
Note 4: Financial Instruments
Our financial instruments consist of cash and cash equivalents, investments in marketable securities, accounts receivable, accounts payable, debt and interest rate swaps.derivative instruments. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-tem maturity of these instruments.
Our debtDebt consists of outstanding principal under our long-term senior notes and HEP’s $300 million revolving credit agreement (the “HEP Credit agreement”), our 9.875% senior notes due 2017 (the “Holly 9.875% Senior Notes”), HEP’s 6.25% senior notes due 2015 (the “HEP 6.25% Senior Notes”) and long-termHEP’s 8.25% senior notes.notes due 2018 (the “HEP 8.25% Senior Notes”). The $206$159 million carrying amount of outstanding debt under HEP’sthe HEP Credit Agreement approximates fair value as interest rates are reset frequently using current interest rates. TheAt December 31, 2010, the estimated fair value of the Holly 9.875% Senior Notes, was $318HEP 6.25% Senior Notes and HEP 8.25% Senior Notes were $327 million, $183.2 million and the$156.8 million, respectively. These fair value of the HEP Senior Notes was $177.6 million at December 31, 2009. This fair value estimate isestimates are based on market quotes provided from a third-party bank. See Note 12 for additional information on these instruments.
Fair Value Measurements
Fair value measurements are derived using inputs, assumptions(assumptions that market participants would use in pricing an asset or liability, including assumptions about risk.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. |
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| • | | (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. |
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(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.
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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 swapsswap that are 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 our interest ratethe respective swap agreements. OurThe 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 a market-based observable input.with respect to HEP’s interest rate swap. See Note 1213 for additional information on our interest rate swaps,these swap contracts, including fair value measurements.
NOTE 5: Earnings Per Share
Basic earnings per share from continuing operations is calculated as income from continuing operations divided by the average number of shares of common stock outstanding. Diluted earnings per share from continuing operations 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 income from continuing operations:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | Years Ended December 31, | |
| | | 2009 | | 2008 | | 2007 | | | 2010 | | 2009 | | 2008 | |
| | | (In thousands, except per share data) | | | (In thousands, except per share data) | |
| | | |
| Earnings attributable to Holly Corporation stockholders: | | |
| Income from continuing operations | | $ | 15,209 | | $ | 119,206 | | $ | 334,128 | | | $ | 103,964 | | $ | 15,209 | | $ | 119,206 | |
| | | | | | | | | | | | | | | |
| | | |
| Average number of shares of common stock outstanding | | 50,418 | | 50,202 | | 54,852 | | | 53,218 | | 50,418 | | 50,202 | |
| Effect of dilutive stock options, variable restricted shares and performance share units | | 185 | | 347 | | 998 | | | 391 | | 185 | | 347 | |
| | | | | | | | | | | | | | | |
| Average number of shares of common stock outstanding assuming dilution | | 50,603 | | 50,549 | | 55,850 | | | 53,609 | | 50,603 | | 50,549 | |
| | | | | | | | | | | | | | | |
| | | |
| Basic earnings per share from continuing operations | | $ | 0.30 | | $ | 2.37 | | $ | 6.09 | | | $ | 1.95 | | $ | 0.30 | | $ | 2.37 | |
| | | |
| Diluted earnings per share from continuing operations | | $ | 0.30 | | $ | 2.36 | | $ | 5.98 | | | $ | 1.94 | | $ | 0.30 | | $ | 2.36 | |
NOTE 6: Stock-Based Compensation
On December 31, 2009, Holly2010, we had three principal share-based compensation plans, whichthat are described below.below (collectively, the “Long-Term Incentive Compensation Plan”). The compensation cost that has been charged against income for these plans was $9.3 million, $6.8 million $7.6 million and $10.8$7.6 million for the years ended December 31, 2010, 2009 2008 and 2007,2008, respectively. The total income tax benefit recognized in the income statement for share-based compensation arrangements was $3.6 million, $2.6 million $2.9 million and $4.2$2.9 million for the years ended December 31, 2010, 2009 2008 and 2007,2008, 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. At December 31, 2009, 1,932,2782010, 1,625,678 shares of common stock were reserved for future grants under the current long-term incentive compensation plan,Long-Term Incentive Compensation Plan, which reservation allows for awards of options, restricted stock, or other performance awards.
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 HEP’s share-based compensation plans for the yearyears ended December 31, 2010, 2009 and 2008 was $2.2 million, $1.2 million and $1.7 million, respectivelyrespectively.
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Stock Options
Under our long-term incentive compensation planLong-Term Incentive Compensation Plan and a previous stock option plan, we have granted stock options to certain officers and other key employees. All the options have been granted at prices equal to the market value of the shares at the time of the grant and normally expire on the tenth anniversary of the grant date. These awards generally vest 20% at the end of each of the five years after the grant date. There have been no options granted since December 2001. The fair value on the date of grant for each option awarded was been estimated using the Black-Scholes option pricing model.
A summary of option activity and changes during the year ended December 31, 20092010 is presented below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Weighted- | | | | | Weighted- | | | |
| | | Weighted | | Average | | Aggregate | | | Weighted- | | Average | | Aggregate | |
| | | Average | | Remaining | | Intrinsic | | | Average | | Remaining | | Intrinsic | |
| | | Exercise | | Contractual | | Value | | | Exercise | | Contractual | | Value | |
| Options | | Shares | | Price | | Term | | ($000) | | | Shares | | Price | | Term | | ($000) | |
| | | |
| Outstanding at January 1, 2009 | | 85,200 | | $ | 2.98 | | |
| Outstanding at January 1, 2010 | | | 40,200 | | $ | 2.98 | |
| Exercised | | | (45,000 | ) | | 2.98 | | | 40,200 | | 2.98 | |
| | | | | | | |
| Outstanding and exercisable at December 31, 2009 | | 40,200 | | $ | 2.98 | | 1.2 | | $ | 911 | | |
| Outstanding and exercisable at December 31, 2010 | | | — | | $ | — | | — | | $ | — | |
| | | | | | | | | | | | | | | | | | | |
The total intrinsic value of options exercised during the years ended December 31, 2010, 2009 and 2008, and 2007, was $1.1 million, $0.9 million $8.6 million and $68$8.6 million, respectively.
Cash received from option exercises under the stock option plans were $0.1 million, $0.1 million and $1 million, for the years ended December 31, 2010, 2009 2008 and 2007, was $.1 million, $1 million and $2.3 million,2008, respectively. The actual tax benefit realized for the tax deductions from option exercises under the stock option plans totaled $0.4 million, $3.4$0.4 million and $26$3.4 million for the years ended December 31, 2010, 2009 2008 and 2007,2008, respectively.
Restricted Stock
Under our long-term incentive compensation plan,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 earnings per shareperformance 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 year ended December 31, 20092010 is presented below:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Weighted | | Aggregate | | | Weighted- | | | |
| | | Average | | Intrinsic | | | Average | | | |
| | | Grant-Date | | Value | | | Grant-Date | | Aggregate Intrinsic | |
| Restricted Stock | | Grants | | Fair Value | | ($000) | | | Grants | | Fair Value | | Value ($000) | |
| | | |
| Outstanding at January 1, 2009 (non-vested) | | 235,310 | | $ | 35.86 | | |
| Outstanding at January 1, 2010 (non-vested) | | | 284,450 | | $ | 31.82 | |
| Vesting and transfer of ownership to recipients | | | (133,616 | ) | | 26.59 | | | | (119,557 | ) | | 34.94 | |
| Granted | | 186,801 | | 23.16 | | | 188,502 | | 29.04 | |
| Forfeited | | | (4,045 | ) | | 40.06 | | | | (6,399 | ) | | 27.53 | |
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| Outstanding at December 31, 2009 (non-vested) | | 284,450 | | $ | 31.82 | | $ | 7,290 | | |
| Outstanding at December 31, 2010 (non-vested) | | | 346,996 | | $ | 29.31 | | $ | 14,147 | |
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The total fair value of restricted stock vested and transferred to recipients during the years ended December 31, 2010, 2009 and 2008 and 2007 was $4.2 million, $3.4 million $2.5 million and $12.9$2.5 million, respectively. As of December 31, 2009,2010, there was $1.8$2.2 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 1.3 years.0.9 year.
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Performance Share Units
Under our long-term incentive compensation plan,Long-Term Incentive Compensation Plan, we grant certain officers and other key employees performance share units, which are payable in either cash or 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 either a “financial performance” or a “market performance”financial performance criteria.
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During the year ended December 31, 2009,2010, we granted 122,555110,489 performance share units withhaving a fair value based on our grant date closing stock price of $22.94. All shares were granted during the first quarter of 2009 and$29.17. These units are payable in stock and are subject to certain financial performance criteria.
The fair value of each performance share unit award subject to the financial performance criteria and payable in stock 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 December 31, 2009,2010, estimated share payouts for outstanding non-vested performance share unit awards ranged from 130% to 170%150%.
The fair value of each performance share unit award based on market performance criteria and payable in stock is computed based on an expected-cash-flow approach. The analysis utilizes the grant date closing stock price, dividend yield, historical total returns, expected total returns based on a capital asset pricing model methodology, standard deviation of historical returns and comparison of expected total returns with the peer group. The expected total return and historical standard deviation are applied to a lognormal expected return distribution in a Monte Carlo simulation model to identify the expected range of potential returns and probabilities of expected returns.
A summary of performance share unit activity and changes during the year ended December 31, 20092010 is presented below:
| | | | | |
| Performance Share Units | | Grants | |
| | | | |
Outstanding at January 1, 20092010 (non-vested) | | | 169,669215,170 | |
| Vesting and transfer of ownership to recipients | | | (72,05938,653 | ) |
| Granted | | | 122,555110,489 | |
| Forfeited | | | (4,9958,913 | ) |
| | | | |
Outstanding at December 31, 20092010 (non-vested) | | | 215,170278,093 | |
| | | | |
For the year ended December 31, 20092010 we issued 110,97166,483 shares of our common stock having a fair value of $2.2 million related to vested performance share units, representing a 154%172% payout. Based on the weighted average grant date fair value of $35.07$29.94 there was $3.5$4.5 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 1.71.2 years.
NOTE 7: Cash and Cash Equivalents and Investments in Marketable Securities
Our investment portfolio consists of cash and cash equivalents and investments in debt securities primarily issued by government entities.at December 31, 2010. In addition, we haveown 1,000,000 shares of Connacher Oil and Gas Limited common stock that was received as partial consideration upon ourthe sale of theour Montana refinery in 2006.
DuringAt times we also invest available cash in highly-rated marketable debt securities, primarily issued by government entities that have maturities at the date of purchase of greater than three months.
Our investments in marketable securities are classified as available-for-sale, and as a result, are reported at fair value using quoted market prices. 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.
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The following is a summary of our available-for-sale securities:
| | | | | | | | | | | | | |
| | | Available-for-Sale Securities | |
| | | | | | | | | | | Estimated Fair | |
| | | | | | | Gross | | | Value | |
| | | | | | | Unrealized | | | (Net Carrying | |
| | | Amortized Cost | | | Gain | | | Amount) | |
| | | (In thousands) | |
December 31, 2010 | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Equity securities | | $ | 610 | | | $ | 733 | | | $ | 1,343 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
December 31, 2009 | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Equity securities | | $ | 604 | | | $ | 619 | | | $ | 1,223 | |
| | | | | | | | | | |
There were no sales or maturities of marketable securities for the year ended December 31, 2008,2010. For the year ended December 31, 2009, we received a total of $230.3 million related to sales and maturities of marketable debt securities.
We recorded ana $3.7 million impairment loss of $3.7 million related to our investment in Connacher common stock having an initial cost basis of $4.3 million.during the year ended December 31, 2008. Although this investment in equity securities having a cost basis of $4.3 million was in an unrealized loss position for less than 12-months, we accounted for this as an other-than-temporary decline due to the severity of the loss in fair value of this investment.
The following is a summary of our available-for-sale securities at December 31, 2009:
| | | | | | | | | | | | | |
| | | Available-for-Sale Securities | |
| | | | | | | | | | | Estimated | |
| | | | | | | Gross | | | Fair Value | |
| | | Amortized | | | Unrealized | | | (Net Carrying | |
| | | Cost | | | Gain | | | Amount) | |
| | | (In thousands) | |
| | | | | | | | | | | | | |
| Equity securities | | $ | 604 | | | $ | 619 | | | $ | 1,223 | |
| | | | | | | | | | |
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The following is a summary of our available-for-sale securities at December 31, 2008:
| | | | | | | | | | | | | | | | | |
| | | Available-for-Sale Securities | |
| | | | | | | | | | | | | | | Estimated | |
| | | | | | | Gross | | | Recognized | | | Fair Value | |
| | | Amortized | | | Unrealized | | | Impairment | | | (Net Carrying | |
| | | Cost | | | Gain | | | Loss | | | Amount) | |
| | | (In thousands) | |
| States and political subdivisions | | $ | 54,389 | | | $ | 210 | | | $ | — | | | $ | 54,599 | |
| Equity securities | | | 4,328 | | | | — | | | | (3,724 | ) | | | 604 | |
| | | | | | | | | | | | | |
| Total marketable securities | | $ | 58,717 | | | $ | 210 | | | $ | (3,724 | ) | | $ | 55,203 | |
| | | | | | | | | | | | | |
For the years ended December 31, 2009 and 2008, we received a total of $230.3 million and $945.5 million, respectively, related to sales and maturities of our investments in marketable debt securities.
NOTE 8: Inventories
Inventories are stated at the lower of cost, using the LIFO method for crude oil and refined products and the average cost method for materials and supplies, or market. Cost is determined using the LIFO inventory valuation methodology and market is determined using current estimated selling prices. Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. In periods of rapidly declining prices, LIFO inventories may have to be written down to market due to the higher costs assigned to LIFO layers in prior periods. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years that inventory volumes decline as the result of charging cost of sales with LIFO inventory costs generated in prior periods.
Inventory consists of the following components:
| | | | | | | | | | |
| | | December 31, | | | | | | | | | |
| | | 2009 | | 2008 | | | December 31, | |
| | | (In thousands) | | | 2010 | | 2009 | |
| | | | (In thousands) | |
| Crude oil | | $ | 60,874 | | $ | 21,446 | | | $ | 96,570 | | $ | 60,874 | |
Other raw materials and unfinished products(1) | | 42,783 | | 2,640 | | | 68,792 | | 42,783 | |
Finished products(2) | | 155,925 | | 83,725 | | | 188,274 | | 155,925 | |
Process chemicals(3) | | 22,823 | | 3,800 | | | 22,512 | | 22,823 | |
| Repairs and maintenance supplies and other | | 21,108 | | 14,124 | | | 24,219 | | 21,108 | |
| | | | | | | | | | | |
| Total inventory | | $ | 303,513 | | $ | 125,735 | | | $ | 400,367 | | $ | 303,513 | |
| | | | | | | | | | | |
| | |
| (1) | | Other raw materials and unfinished products include feedstocks and blendstocks, other than crude. |
| |
| (2) | | Finished products include gasolines, jet fuels, diesels, lubricants, asphalts, LPG’s and residual fuels. |
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| (3) | | Process chemicals include catalysts, additives and other chemicals. |
The excess of current cost over the LIFO value of inventory was $207$284 million and $33$207 million at December 31, 20092010 and 2008,2009, respectively. For the year ended December 31, 2009,2010, we recognized a $8.4 million charge to cost of products sold. This charge was due to the liquidation of certain LIFO inventory quantities that were carried at higher costs as compared to 2009 LIFO inventory acquisition costs. For the year ended December 31, 2008, we recognized an $8.4$4.1 million reduction in cost of products sold. This cost reduction resulted from liquidationsliquidation of certain LIFO inventory quantities that were carried at lower costs as compared to 2010 LIFO inventory acquisition costs. For the year ended December 31, 2009, we recognized an $8.4 million charge to cost of products sold. This charge resulted from liquidations of certain LIFO inventory quantities that were carried at higher costs at the beginning of the 2008 year.compared to 2009 LIFO inventory acquisition costs.
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NOTE 9: Properties, Plants and Equipment
| | | | | | | | | | |
| | | December 31, | | | | | | | | | |
| | | 2009 | | 2008 | | | December 31, | |
| | | (In thousands) | | | 2010 | | 2009 | |
| | | | (In thousands) | |
| Land, buildings and improvements | | $ | 73,973 | | $ | 54,529 | | | $ | 91,169 | | $ | 73,973 | |
| Refining facilities | | 981,594 | | 493,706 | | | 1,174,980 | | 981,594 | |
| Pipelines and terminals | | 478,522 | | 338,558 | | | 539,045 | | 478,522 | |
| Transportation vehicles | | 20,760 | | 19,313 | | | 20,972 | | 20,760 | |
| Other fixed assets | | 80,546 | | 50,187 | | | 83,199 | | 80,546 | |
| Construction in progress | | 366,460 | | 553,408 | | | 306,463 | | 366,460 | |
| | | | | | | | | | | |
| | | 2,001,855 | | 1,509,701 | | | 2,215,828 | | 2,001,855 | |
| Accumulated depreciation | | | (371,885 | ) | | | (304,379 | ) | | | (459,137 | ) | | | (371,885 | ) |
| | | | | | | | | | | |
| | | $ | 1,629,970 | | $ | 1,205,322 | | | $ | 1,756,691 | | $ | 1,629,970 | |
| | | | | | | | | | | |
During the years ended December 31, 20092010 and 20082009 we capitalized $3.2$7.2 million and $1$3.2 million, respectively, in interest attributable to construction projects.
Depreciation expense was $94 million, $78.4 million $53.3 million and $35.8$53.3 million for the years ended December 31, 2010, 2009 2008 and 2007,2008, respectively. Depreciation expense for the years ended December 31, 2010, 2009 and 2008 includes $27 million, $25 million and $17.5 million, respectively, of depreciation expense attributable to the operations of HEP as a result of our reconsolidation effective March 1, 2008.HEP.
NOTE 10: Joint Venture
In December 2007, we entered intoUnder a definitive agreement with Sinclair, towe are jointly buildbuilding 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 northNorth Las Vegas areas (the “UNEV Pipeline”). Under the agreement, we own a 75% interest in the joint venture pipeline andwith Sinclair, ownsour 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. The current total cost of the pipeline project including terminals is expected to be $275approximately $325 million, with our share of thisthe cost totaling $206$244 million. This includes the construction of ethanol blending and storage facilities at the Cedar City terminal. We have commenced the final construction phase of the pipeline and expect the pipeline to be mechanically complete in the second quarter of 2011.
In connection with this project, we have entered into a 10-year commitment to ship an annual average of 15,000 BPDbarrels per day of refined products on the UNEV Pipeline at an agreed tariff rate.tariff. Our commitment for each year is subject to reduction by up to 5,000 BPDbarrels 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. We expect the project will be ready to commence operations in the fall of 2010.
We currently anticipate that all regulatory approvals required to commence the construction of the UNEV Pipeline will be received by the end of the second quarter of 2010. Once such approvals are received, construction of the pipeline will take approximately nine months. Under this schedule, the pipeline would become operational during the first quarter of 2011.
NOTE 11: Environmental Costs
Consistent with our accounting policy for environmental remediation costs, we expensed $4.2 million $0.6 million and $2.3$0.6 million for the years ended December 31, 2009 2008 and 2007,2008, respectively, for environmental remediation obligations. During 2010, we revised certain environmental accruals to reflect current cost assessments reducing our environmental accrual by $0.6 million. The accrued environmental liability reflected in the consolidated balance sheetsheets was $30.4$26.2 million and $7.3$30.4 million at December 31, 20092010 and 2008,2009, respectively, of which $24.2$20.4 million and $4.2$24.2 million, respectively, was classified as other long-term liabilities. These liabilities includeaccruals reflect $22.3 million of environmental obligations that we assumed in connection with our Tulsa Refinery acquisitions on June 1, 2009west and December 1,east facilities acquired in 2009. Costs of future expenditures for environmental remediation that are expected to be incurred over the next several years and are not discounted to their present value.
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NOTE 12: Debt
Holly Credit FacilitiesAgreement
We have a $370$400 million senior secured credit agreement expiring in March 2013. In April 2009, we entered into a second amended and restated $300 million senior secured revolving credit agreement that amended and restated our previous credit agreement in its entirety2013 (the “Holly Credit Agreement”) with Bank of America, N.A. as administrative agent and one of a syndicate of lenders (the “Hollylenders. The Holly Credit Agreement”). Additionally, we upsized the credit agreement by $50 million in November 2009 and by an additional $20 million in December 2009 pursuant to the accordion feature. The credit agreementAgreement 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 December 31, 2009.2010. At December 31, 2009,2010, we had no outstanding borrowings and outstanding letters of credit totaling $56.3$71 million under the Holly Credit Agreement. At that level of usage, the unused commitment underwas $329 million at December 31, 2010. We entered into an amendment to the Holly Credit Agreement was $313.7 million atin May 2010 that changed certain financial covenants and provided other enhancements to the agreement.
HEP Credit Agreement
At December 31, 2009.
2010, the HEP hasCredit Agreement consisted of a $300 million senior secured revolving credit agreementfacility expiring in August 2011 with an outstanding balance of $159 million. On February 14, 2011, the HEP Credit Agreement was amended, slightly reducing the size of the credit facility from $300 million to $275 million (the “HEP Amended Credit Agreement”). The HEP Amended Credit Agreement expires in February 2016; provided that the HEP Amended Credit Agreement will expire on September 1, 2014 in the event that, on or prior to such date, the 6.25% HEP Senior Notes have not been repurchased, refinanced, extended or repaid. The HEP Amended Credit Agreement is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for other general partnership purposes. At December 31, 2009, HEP had outstanding borrowings totaling $206 million under the HEP Credit Agreement with unused borrowing capacity of $94 million.
HEP’s obligations under the HEP Amended Credit Agreement are collateralized by substantially all of HEP’s assets. HEP assets that are included(presented parenthetically in our Consolidated Balance Sheets at December 31, 2009 consist of $2.5 million in cash and cash equivalents, $7.6 million in trade accounts receivable and other current assets, $458.5 million in property, plant and equipment, net and $159 million in intangible and other assets.Sheets). Indebtedness under the HEP Amended Credit Agreement is recourse to HEP Logistics Holdings, L.P., its general partner, and guaranteed by HEP’s 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. Navajo Pipeline Co., L.P., Navajo Refining Company, L.L.C.HEP’s creditors have no other recourse to our assets. Furthermore, our creditors have no recourse to the assets of HEP and Woods Cross Refining Company, L.L.C., threeits consolidated subsidiaries. During the first quarter of 2010, our subsidiaries, have agreedprevious agreements to indemnify HEP’s controlling partner to the extent it makes any payment in satisfaction of debt service due on up to a $171 million aggregate principal amount of borrowings under the HEP Credit Agreement.Agreement were terminated.
Holly Senior Notes Due 2017
In June 2009, we issued $200 million in aggregate principal amount of the Holly 9.875% Senior Notes. A portion of the $188$187.9 million in net proceeds received was used for post-closing payments for inventories of crude oil and refined products acquired from Sunoco following the closing of the Tulsa Refinery west facility purchase on June 1, 2009. In October 2009, we issued an additional $100 million aggregate principal amount as an add-on offering to the Holly 9.875% Senior Notes that was used to fund the cash portion of our acquisition of Sinclair’s 75,000 BPD refinery located inthe Tulsa Oklahoma.Refinery east facility.
The $300 million aggregate principal amount of Holly Senior Notes mature on June 15, 2017 and bear interest at 9.875%. The Holly Senior Notes are unsecured and impose certain restrictive covenants, including limitations on Holly’sour 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 Moody’s and Standard & Poor’s 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 2015
In March 2010, HEP issued $150 million in aggregate principal amount of HEP 8.25% Senior Notes maturing March 15, 2018. A portion of the $147.5 million in net proceeds received was used to fund HEP’s $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.
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The HEP senior notes maturing6.25% Senior Notes having an aggregate principle amount of $185 million mature March 1, 2015 and are registered with the SECSEC. The HEP 6.25% Senior Notes and bear interest at 6.25% (“HEP 8.25% Senior Notes (collectively, the “HEP Senior Notes”). The HEP Senior Notes are unsecured and impose certain restrictive covenants, including limitations on HEP’s 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 Moody’s and Standard & Poor’s 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 HEP’s wholly-owned subsidiaries. AnyHowever, 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. Navajo Pipeline Co., L.P., oneHEP’s creditors have no other recourse to our assets. Furthermore, our creditors have no recourse to the assets of HEP and its consolidated subsidiaries. During the first quarter of 2010, our subsidiaries, has agreedprevious agreement to indemnify HEP’s controlling partner to the extent it makes any payment in satisfaction of debt service due on up to $35 million of the principal amount of the HEP 6.25% Senior Notes.Notes was terminated.
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Holly Financing Obligation
OnIn October 20, 2009, we sold to Plains a portionapproximately 400,000 barrels of the crude oil petroleum storage, and certain refining-related crude oil receiving pipeline facilities locatedtankage at our Tulsa Refinery east facility.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 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 ourthese assets on our books and establishedrecorded a liability representing the $40 million in proceeds received.
The carrying amounts of long-term debt are as follows:
| | | | | | | | | | | | | | | | | |
| | | December 31, | | December 31, | | | December 31, | | December 31, | |
| | | 2009 | | 2008 | | | 2010 | | 2009 | |
| | | (In thousands) | | | (In thousands) | |
| Holly Senior Notes | | |
| Holly 9.875% Senior Notes | | |
| Principal | | $ | 300,000 | | $ | — | | | $ | 300,000 | | $ | 300,000 | |
| Unamortized discount | | | (11,549 | ) | | — | | | | (10,491 | ) | | | (11,549 | ) |
| | | | | | | | | | | |
| | | | 289,509 | | 288,451 | |
| | | 288,451 | | — | | |
| Holly Financing Obligation | | |
| Holly financing obligation | | |
| Principal | | 39,809 | | — | | | 38,781 | | 39,809 | |
| | | | | | | | | | | |
| | | |
| Total Holly long-term debt | | $ | 328,260 | | $ | — | | | 328,290 | | 328,260 | |
| | | | | | | | | | | |
| | | |
| HEP Credit Agreement | | $ | 206,000 | | $ | 200,000 | | | 159,000 | | 206,000 | |
| | | |
| HEP Senior Notes | | |
| HEP 6.25% Senior Notes | | |
| Principal | | 185,000 | | 185,000 | | | 185,000 | | 185,000 | |
| Unamortized discount | | | (13,593 | ) | | | (16,223 | ) | | | (10,961 | ) | | | (13,593 | ) |
| Unamortized premium — de-designated fair value hedge | | 1,791 | | 2,137 | | |
| Unamortized premium — dedesignated fair value hedge | | | 1,444 | | 1,791 | |
| | | | | | | | | | | |
| | | 173,198 | | 170,914 | | | 175,483 | | 173,198 | |
| | | | | | |
| Total HEP debt | | 379,198 | | 370,914 | | |
| Less HEP Credit Agreement borrowings classified as short-term debt | | — | | 29,000 | | |
| HEP 8.25% Senior Notes | | |
| Principal | | | 150,000 | | — | |
| Unamortized discount | | | | (2,212 | ) | | — | |
| | | | | | | |
| | | | 147,788 | | — | |
| | | | | | | | | | | |
| | | |
| Total HEP long-term debt | | $ | 379,198 | | $ | 341,914 | | | 482,271 | | 379,198 | |
| | | | | | | | | | | |
| | | |
| Total long-term debt | | | $ | 810,561 | | $ | 707,458 | |
| | | | | | | |
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NOTE 13: Derivative Instruments and Hedging Activities
AtCommodity 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; and |
|
| • | | prices of refined products. |
As of December 31, 2009,2010, we have outstanding commodity price swap contracts serving as economic hedges to protect the estimatedvalue of a temporary crude oil inventory build of 120,000 barrels against price volatility. These contracts are measured quarterly at fair valuesvalue with offsetting adjustments (gains / losses) recorded directly to cost of products sold.
We also have outstanding price swap contracts that fix our purchase price on forecasted natural gas purchases aggregating of 1,500,000 MMBTUs to be ratably purchased between January and March 2011 at a weighted-average cost of $4.20 per MMBTU. These price swap contracts have been designated as cash flow hedges and mature in March 2011.
Under hedge accounting, a cash flow hedge is adjusted quarterly to fair value with offsetting fair value adjustments to other comprehensive income. These fair value adjustments (gains / losses) are later reclassified into earnings as the hedging instrument matures. Also on a quarterly basis, hedge effectiveness is measured by comparing the change in fair value of the Holly Senior Notes andswap contracts against the HEP Senior Notes were $318 million and $177.6 million, respectively.expected future cash inflows/outflows on the respective transaction being hedged. Any ineffectiveness is reclassified from accumulated other comprehensive income into earnings.
Interest Rate Risk Management
HEP uses interest rate swaps (derivative instruments) to mangemanage its exposure to interest rate risk.
As of December 31, 2009, HEP has three interest rate swap contracts.
2010, HEP has an interest rate swap to hedgecontract that hedges its exposure to the cash flow risk caused by the effects of LIBOR changes on the $171a $155 million HEP Credit Agreement advance that was used to finance HEP’s purchase of the Crude Pipelines and Tankage Assets from us.advance. This interest rate swap effectively converts its $171$155 million of LIBOR based debt to fixed rate debt having an interest rate of 3.74% plus an applicable margin currentlyof 1.75%, which equaled an effective interest rate of 5.49% as of December 31, 2009.2010. 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.
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HEP designated this interest rate swap as a cash flow hedge. Based on its assessmentThe following table presents balance sheet locations and related fair values of effectiveness using the change in variable cash flows method, HEP determined that this interest rate swap is effective in offsetting the variability in interest payments on the $171 million variable rate debt resulting from changes in LIBOR. Under hedge accounting, HEP adjusts the cash flow hedge on a quarterly basis to its fair value with the offsetting fair value adjustment to accumulated other comprehensive income. Also on a quarterly basis, HEP measures hedge effectiveness by comparing the present value of the cumulative change in the expected future interest to be paid or received on the variable leg of the swap against the expected future interest payments on the $171 million variable rate debt. Any ineffectiveness is reclassified from accumulated other comprehensive income to interest expense. As of December 31, 2009, HEP had no ineffectiveness on its cash flow hedge.outstanding derivative instruments.
HEP also has an interest rate swap contract that effectively converts interest expense associated with $60 million of the HEP 6.25% Senior Notes from fixed to variable rate debt (“Variable Rate Swap”). Under this swap contract, interest on the $60 million notional amount is computed using the three-month LIBOR plus a spread of 1.1575%, which equaled an effective interest rate of 1.41% as of December 31, 2009. The maturity date of this swap contract is March 1, 2015, matching the maturity of the HEP Senior Notes.| | | | | | | | | | | | | |
| | | Balance Sheet | | | | | | Location of | | Offsetting | |
| Derivative Instruments | | Location | | Fair Value | | | Offsetting Balance | | Amount | |
| | | (Dollars in thousands) | |
December 31, 2010 | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Derivatives 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 | | $ | 497 | |
| | | | | | | | | | | |
| | | | | | | | | | | | | |
December 31, 2009 | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Derivative designated as cash flow hedging instrument: | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Variable-to-fixed interest rate swap contract ($171 million LIBOR based debt interest payments) | | Other long-term liabilities | | $ | 9,141 | | | Accumulated other comprehensive loss | | $ | 9,141 | |
| | | | | | | | | | | |
| | | | | | | | | | | | | |
Derivatives not designated as hedging instruments: | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Fixed-to-variable interest rate swap contract ($60 million of HEP 6.25% Senior Notes) | | Other assets | | $ | 2,294 | | | Long-term debt | | $ | 1,791 | (1) |
| | | | | | | | | Equity | | | 503 | (2) |
| | | | | | | | | | | |
| | | | | $ | 2,294 | | | | | $ | 2,294 | |
| | | | | | | | | | | |
| | | | | | | | | | | | | |
| Variable-to-fixed interest rate swap contract ($60 million of HEP 6.25% Senior Notes) | | Other long-term liabilities | | $ | 2,555 | | | Equity | | $ | 2,555 | (2) |
| | | | | | | | | | | |
In October 2008, HEP entered into an additional interest rate swap contract, effective December 1, 2008, that effectively unwinds the effects of the Variable Rate Swap discussed above, converting $60 million of its hedged long-term debt back to fixed rate debt (“Fixed Rate Swap”). Under the Fixed Rate Swap, interest on a notional amount of $60 million is computed at a fixed rate of 3.59% versus three-month LIBOR which when added to the 1.1575% spread on the Variable Rate Swap results in an effective fixed interest rate of 4.75%. The maturity date of this swap contract is December 1, 2013.Prior to the execution of HEP’s Fixed Rate Swap, the Variable Rate Swap was designated as a fair value hedge of $60 million in outstanding principal under the HEP Senior Notes. HEP de-designated this hedge in October 2008. At that time, the carrying balance of the HEP Senior Notes included a $2.2 million premium due to the application of hedge accounting until the de-designation date. This premium is being amortized as a reduction to interest expense over the remaining term of the Variable Rate Swap.
HEP’s interest rate swaps not having a “hedge” designation are measured quarterly at fair value either as an asset or a liability in the consolidated balance sheets with the offsetting fair value adjustment to interest expense. For the years ended December 31, 2009 and 2008, HEP recognized an increase of $0.2 million and $2.3 million, respectively, in interest expense as a result of fair value adjustments to its interest rate swaps.
HEP records interest expense equal to the variable rate payments under the swaps. Receipts under the swap agreements are recorded as a reduction of interest expense.
Additional information on HEP’s interest rate swaps at December 31, 2009 is as follows:
| | | | | | | | | | | | | |
| | | Balance Sheet | | | | | | Location of Offsetting | | Offsetting | |
| Interest Rate Swaps | | Location | | Fair Value | | | Balance | | Amount | |
| | | (In thousands) | |
Asset | | | | | | | | | | | | |
Fixed-to-variable interest rate swap —
$60 million of 6.25% HEP Senior Notes | | Other assets | | $ | 2,294 | | | Long-term debt — HEP | | $ | (1,791 | )(1) |
| | | | | | | | | Equity | | | (1,942 | )(2) |
| | | | | | | | | Interest expense | | | 1,439 | (3) |
| | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | $ | 2,294 | | | | | $ | (2,294 | ) |
| | | | | | | | | | | |
Liability | | | | | | | | | | | | |
| Cash flow hedge — $171 million LIBOR based debt | | Other long-term liabilities | | $ | (9,141 | ) | | Accumulated other comprehensive loss | | $ | 9,141 | |
| | | | | | | | | | | | | |
| Variable-to-fixed interest rate swap — | | Other long-term liabilities | | | | | | Equity | | | 4,166 | (2) |
| $60 million | | | | | (2,555 | ) | | Interest expense | | | (1,611 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | $ | (11,696 | ) | | | | $ | 11,696 | |
| | | | | | | | | | | |
| | |
| (1) | | Represents unamortized balance of a deferred hedge premium attributable to HEP’s fair value hedge that was dedesignated hedge premium.in 2008 that is being amortized as a reduction to interest expense over the remaining term of the HEP 6.25% Senior Notes. |
| |
| (2) | | Represents prior year charges to interest expense. |
|
(3) | | Net of amortization of premium attributable to dedesignated hedge. |
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On January 29,For the year ended December 31, 2010, we recognized a $1.3 million charge to cost of products sold and a $0.4 million charge to operating expenses that are attributable to losses resulting from fair value changes to our commodity price swap contracts.
For the years ended December 31, 2010, 2009 and 2008, HEP received notice fromrecognized $1.5 million, $0.2 million and $2.3 million, respectively, in charges to interest expense as a result of fair value changes to its interest rate swap contracts.
There was no ineffectiveness on the counterparty that it is exercising its option to cancelcash flow hedges during the Variable Rate Swap on March 1, 2010, pursuant to the terms of the swap contract. HEP will receive a cancellation premium of $1.9 million.periods covered in these consolidated financial statements.
NOTE 13:14: Income Taxes
The provision for income taxes from continuing operations is comprised of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | Years Ended December 31, | |
| | | 2009 | | 2008 | | 2007 | | | 2010 | | 2009 | | 2008 | |
| | | (In thousands) | | | (In thousands) | |
| Current | | |
| Federal | | $ | (24,876 | ) | | $ | 27,795 | | $ | 113,999 | | | $ | 30,999 | | $ | (24,876 | ) | | $ | 27,795 | |
| State | | | (2,266 | ) | | 4,097 | | 28,246 | | | 4,473 | | | (2,266 | ) | | 4,097 | |
| Deferred | | |
| Federal | | 33,269 | | 27,727 | | 21,867 | | | 21,796 | | 33,269 | | 27,727 | |
| State | | 4,253 | | 5,207 | | 1,204 | | | 2,044 | | 4,253 | | 5,207 | |
| | | | | | | | | | | | | | | |
| | | $ | 10,380 | | $ | 64,826 | | $ | 165,316 | | | $ | 59,312 | | $ | 10,380 | | $ | 64,826 | |
| | | | | | | | | | | | | | | |
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The statutory federal income tax rate applied to pre-tax book income from continuing operations reconciles to income tax expense as follows:
| | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | | | | | | | | | | | |
| | | 2009 | | 2008 | | 2007 | | | Years Ended December 31, | |
| | | (In thousands) | | | 2010 | | 2009 | | 2008 | |
| | | | (In thousands) | |
| Tax computed at statutory rate | | $ | 15,331 | | $ | 65,711 | | $ | 174,805 | | | $ | 67,327 | | $ | 15,331 | | $ | 65,711 | |
| State income taxes, net of federal tax benefit | | 1,708 | | 7,322 | | 19,478 | | | 4,372 | | 1,708 | | 7,322 | |
| Federal tax credits | | | (65 | ) | | | (1,896 | ) | | | (16,078 | ) | | | (158 | ) | | | (65 | ) | | | (1,896 | ) |
| Domestic production activities deduction | | — | | | (2,380 | ) | | | (8,670 | ) | | | (940 | ) | | — | | | (2,380 | ) |
| Tax exempt interest | | | (168 | ) | | | (2,772 | ) | | | (4,200 | ) | | — | | | (168 | ) | | | (2,772 | ) |
| Discontinued operations (including noncontrolling interest) | | 7,720 | | 1,820 | | — | | | — | | 7,720 | | 1,820 | |
| Noncontrolling interest in continuing operations | | | (13,123 | ) | | | (2,739 | ) | | — | | | | (11,315 | ) | | | (13,123 | ) | | | (2,739 | ) |
| Other | | | (1,023 | ) | | | (240 | ) | | | (19 | ) | | 26 | | | (1,023 | ) | | | (240 | ) |
| | | | | | | | | | | | | | | |
| | | $ | 10,380 | | $ | 64,826 | | $ | 165,316 | | | $ | 59,312 | | $ | 10,380 | | $ | 64,826 | |
| | | | | | | | | | | | | | | |
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Our deferred income tax assets and liabilities for continuing operations as of December 31, 20092010 and 20082009 are as follows:
| | | | | | | | | | | | | |
| | | December 31, 2010 | |
| | | Assets | | | Liabilities | | | Total | |
| | | (In thousands) | |
| Deferred taxes | | | | | | | | | | | | |
| Accrued employee benefits | | $ | 9,235 | | | $ | — | | | $ | 9,235 | |
| Accrued postretirement benefits | | | 2,126 | | | | — | | | | 2,126 | |
| Accrued environmental costs | | | 556 | | | | — | | | | 556 | |
| Inventory differences | | | 258 | | | | (8,612 | ) | | | (8,354 | ) |
| Deferred Turnaround Costs | | | — | | | | (356 | ) | | | (356 | ) |
| Prepayments and other | | | 4,458 | | | | (2,874 | ) | | | 1,584 | |
| | | | | | | | | | |
Total current(1) | | | 16,633 | | | | (11,842 | ) | | | 4,791 | |
| Properties, plants and equipment (due primarily to tax in excess of book depreciation) | | | — | | | | (207,861 | ) | | | (207,861 | ) |
| Accrued postretirement benefits | | | 18,319 | | | | (2,558 | ) | | | 15,761 | |
| Accrued environmental costs | | | 947 | | | | — | | | | 947 | |
| Deferred turnaround costs | | | — | | | | (23,326 | ) | | | (23,326 | ) |
| Investment in HEP | | | 78,851 | | | | (4,211 | ) | | | 74,640 | |
| Other | | | 11,626 | | | | (3,722 | ) | | | 7,904 | |
| | | | | | | | | | |
| Total noncurrent | | | 109,743 | | | | (241,678 | ) | | | (131,935 | ) |
| | | | | | | | | | |
| Total | | $ | 126,376 | | | $ | (253,520 | ) | | $ | (127,144 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| | | December 31, 2009 | |
| | | Assets | | | Liabilities | | | Total | |
| | | (In thousands) | |
| Deferred taxes | | | | | | | | | | | | |
| Accrued employee benefits | | $ | 7,701 | | | $ | — | | | $ | 7,701 | |
| Accrued postretirement benefits | | | 1,812 | | | | — | | | | 1,812 | |
| Accrued environmental costs | | | 2,339 | | | | — | | | | 2,339 | |
| Inventory differences | | | 7,951 | | | | — | | | | 7,951 | |
| Prepayments and other | | | 2,423 | | | | (3,321 | ) | | | (898 | ) |
| | | | | | | | | | |
Total current(1) | | | 22,226 | | | | (3,321 | ) | | | 18,905 | |
| Properties, plants and equipment (due primarily to tax in excess of book depreciation) | | | — | | | | (176,889 | ) | | | (176,889 | ) |
| Accrued postretirement benefits | | | 13,488 | | | | — | | | | 13,488 | |
| Accrued environmental costs | | | 9,420 | | | | — | | | | 9,420 | |
| Deferred turnaround costs | | | — | | | | (18,257 | ) | | | (18,257 | ) |
| Investment in HEP | | | 47,188 | | | | (4,507 | ) | | | 42,681 | |
| Other | | | 7,512 | | | | (2,540 | ) | | | 4,972 | |
| | | | | | | | | | |
| Total noncurrent | | | 77,608 | | | | (202,193 | ) | | | (124,585 | ) |
| | | | | | | | | | |
| Total | | $ | 99,834 | | | $ | (205,514 | ) | | $ | (105,680 | ) |
| | | | | | | | | | |
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| | | | | | | | | | | | | |
| | | December 31, 2008 | |
| | | Assets | | | Liabilities | | | Total | |
| | | (In thousands) | |
| Deferred taxes | | | | | | | | | | | | |
| Accrued employee benefits | | $ | 7,135 | | | $ | (29 | ) | | $ | 7,106 | |
| Accrued postretirement benefits | | | 2,893 | | | | — | | | | 2,893 | |
| Accrued environmental costs | | | 1,202 | | | | — | | | | 1,202 | |
| Inventory differences | | | 736 | | | | — | | | | 736 | |
| Prepayments and other | | | 1,066 | | | | (2,297 | ) | | | (1,231 | ) |
| | | | | | | | | | |
Total current(1) | | | 13,032 | | | | (2,326 | ) | | | 10,706 | |
| Properties, plants and equipment (due primarily to tax in excess of book depreciation) | | | — | | | | (122,684 | ) | | | (122,684 | ) |
| Accrued postretirement benefits | | | 14,824 | | | | — | | | | 14,824 | |
| Accrued environmental costs | | | 1,591 | | | | — | | | | 1,591 | |
| Deferred turnaround costs | | | — | | | | (11,491 | ) | | | (11,491 | ) |
| Investment in HEP | | | 44,612 | | | | — | | | | 44,612 | |
| Other | | | 6,212 | | | | (2,555 | ) | | | 3,657 | |
| | | | | | | | | | |
| Total noncurrent | | | 67,239 | | | | (136,730 | ) | | | (69,491 | ) |
| | | | | | | | | | |
| Total | | $ | 80,271 | | | $ | (139,056 | ) | | $ | (58,785 | ) |
| | | | | | | | | | |
| | |
| (1) | | Our net current deferred tax assets are classified as other current assets under “Prepayments and other” in our consolidated balance sheets. |
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We made income tax payments of $19.3 million in 2009, $21.1 million in 2008 and $139.4 million in 2007.
The total amount of unrecognized tax benefits as of December 31, 2009,2010, was $2 million. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
| | | | | | | | | |
| | | Liability for | | | Liability for | |
| | | Unrecognized | | | Unrecognized | |
| | | Tax Benefits | | | Tax Benefits | |
| | | (In thousands) | | | (In thousands) | |
| Balance at January 1, 2009 | | $ | 4,350 | | |
| Balance at January 1, 2010 | | | $ | 1,964 | |
| Additions based on tax positions related to the current year | | 3 | | | — | |
| Additions for tax positions of prior years | | 358 | | | 6 | |
| Reductions for tax positions of prior years | | | (2,747 | ) | | | (106 | ) |
| | | | | | | |
| | | |
| Balance at December 31, 2009 | | $ | 1,964 | | |
| Balance at December 31, 2010 | | | $ | 1,864 | |
| | | | | | | |
Included in the unrecognized tax benefits at December 31, 20092010 are $1.1 million of tax benefits that, if recognized, would affect our effective tax rate. Unrecognized tax benefits are adjusted in the period in which new information about a tax position becomes available or the final outcome differs from the amount recorded.
We recognize interest and penalties relating to liabilities for unrecognized tax benefits as an element of tax expense. During the year ended December 31, 2009,2010, we recognized $1$0.6 million in interesttax benefit (net of related tax benefits)interest) as a component of tax expense. We have not recorded any penalties related to our uncertain tax positions as we believe that it is more likely than not that there will not be any assessment of penalties. We do not expect that unrecognized tax benefits for tax positions taken with respect to 20092010 and prior years will significantly change over the next twelve months.
We are subject to U.S. federal income tax, New Mexico, Utah and Oklahoma income tax and to income tax of multiple other state jurisdictions. We have substantially concluded all U.S. federal, income tax matters for tax years through December 31, 2005 and all state and local income tax matters for tax years through December 31, 2003.2005. In late 2010, the Internal Revenue Service commenced an examination of our U.S. federal tax returns for the tax years ended December 31, 2006, 2007 and 2008. We anticipate that these audits will be completed by the end of 2012.
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NOTE 14:15: Stockholders’ Equity
The following table showsShares of our common sharesstock outstanding and activity for the activity during the year:years ended December 31, 2010, 2009 and 2008 is presented below:
| | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | | | | | | | | | | | |
| | | 2009 | | 2008 | | 2007 | | | Years Ended December 31, |
| | | | 2010 | | 2009 | | 2008 |
| Common shares outstanding at beginning of year | | 49,943,220 | | 52,616,169 | | 55,316,615 | | | 53,066,269 | | 49,943,220 | | 52,616,169 | |
| Common shares issued to Sinclair in connection with Tulsa Refinery east facility acquisition | | 2,789,155 | | — | | — | | | — | | 2,789,155 | | — | |
| Issuance of common stock upon exercise of stock options | | 45,000 | | 406,000 | | 1,085,600 | | | 40,200 | | 45,000 | | 406,000 | |
| Issuance of restricted stock, excluding restricted stock with performance feature | | 154,078 | | 46,943 | | 49,677 | | | 141,443 | | 154,078 | | 46,943 | |
| Vesting of performance units | | 146,664 | | 84,948 | | 151,000 | | | 70,143 | | 146,664 | | 84,948 | |
| Vesting of restricted stock with performance feature | | 49,719 | | 57,572 | | 180,519 | | | 6,150 | | 49,719 | | 57,572 | |
| Forfeitures of restricted stock | | | (1,633 | ) | | | (2,033 | ) | | | (23,537 | ) | | | (15,042 | ) | | | (1,633 | ) | | | (2,033 | ) |
Purchase of treasury stock(1) | | | (59,934 | ) | | | (3,266,379 | ) | | | (4,143,705 | ) | | | (44,475 | ) | | | (59,934 | ) | | | (3,266,379 | ) |
| | | | | | | | | | | | | | | |
| Common shares outstanding at end of year | | 53,066,269 | | 49,943,220 | | 52,616,169 | | | 53,264,688 | | 53,066,269 | | 49,943,220 | |
| | | | | | | | | | | | | | | |
| | |
| (1) | | Includes 44,475, 59,934 and 55,515 shares purchased in 2010, 2009 and 2008, respectively, under the terms of restricted stock agreements to provide funds for the payment of payroll and income taxes due at vesting of restricted stock. |
Common Stock Repurchases:Under oura common stock repurchase program, common stock repurchases are being made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors. Duringwe purchased 3,228,489 shares during the year ended December 31, 2009, we did not purchase any shares of common stock, other than shares purchased to provide funds for the payment of payroll and income taxes due at the vesting of restricted shares for certain officers and employees who did not elect to satisfy such taxes by other means. Since inception of our common stock repurchase initiative beginning in May 2005 through December 31, 2009, we have repurchased 16,759,395 shares2008 at a cost of $655.2$137.1 million or an average of $39.10$42.48 per share. This program has been inactive since 2008.
During the yearyears ended December 31, 2010, 2009 and 2008, we repurchased at market price from certain executives 59,934 shares of our common stock at a cost ofmarket price from certain employees costing $1.2 million.million, $1.2 million and $2 million, respectively. 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.
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NOTE 15:16: 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) | |
For the year ended December 31, 2009 | | | | | | | | | | | | |
| Unrealized gain on available-for-sale securities | | $ | 409 | | | $ | 158 | | | $ | 251 | |
| Retirement medical obligation adjustment | | | 742 | | | | 289 | | | | 453 | |
| Minimum pension liability adjustment | | | 12,497 | | | | 4,862 | | | | 7,635 | |
| Unrealized gain on HEP cash flow hedge | | | 3,726 | | | | 663 | | | | 3,063 | |
| | | | | | | | | | |
| Other comprehensive income | | | 17,374 | | | | 5,972 | | | | 11,402 | |
| Less other comprehensive income attributable to noncontrolling interest | | | 2,021 | | | | — | | | | 2,021 | |
| | | | | | | | | | |
| Other comprehensive income attributable to Holly Corporation stockholders | | $ | 15,353 | | | $ | 5,972 | | | $ | 9,381 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
For the year ended December 31, 2008 | | | | | | | | | | | | |
| Unrealized loss on available-for-sale securities | | $ | (169 | ) | | $ | (67 | ) | | $ | (102 | ) |
| Retirement medical obligation adjustment | | | 1,433 | | | | 557 | | | | 876 | |
| Minimum pension liability adjustment | | | (21,572 | ) | | | (8,391 | ) | | | (13,181 | ) |
| Unrealized loss on HEP cash flow hedge | | | (12,967 | ) | | | (2,290 | ) | | | (10,677 | ) |
| | | | | | | | | | |
| Other comprehensive loss | | | (33,275 | ) | | | (10,191 | ) | | | (23,084 | ) |
| Less other comprehensive loss attributable to noncontrolling interest | | | (7,079 | ) | | | — | | | | (7,079 | ) |
| | | | | | | | | | |
| Other comprehensive loss attributable to Holly Corporation stockholders | | $ | (26,196 | ) | | $ | (10,191 | ) | | $ | (16,005 | ) |
| | | | | | | | | | |
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| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Tax Expense | | | | | Tax Expense | | | |
| | | Before-Tax | | (Benefit) | | After-Tax | | | Before-Tax | | (Benefit) | | After-Tax | |
| | | (In thousands) | | | (In thousands) | |
For the year ended December 31, 2007 | | |
Year Ended December 31, 2010 | | |
| Unrealized gain on available-for-sale securities | | | $ | 114 | | $ | 42 | | $ | 72 | |
| Unrealized loss on hedging activities | | | | (923 | ) | | 275 | | | (1,198 | ) |
| Retirement medical obligation adjustment | | | | (238 | ) | | | (93 | ) | | | (145 | ) |
| Minimum pension liability adjustment | | $ | (9,373 | ) | | $ | (3,647 | ) | | $ | (5,726 | ) | | | (1,470 | ) | | | (572 | ) | | | (898 | ) |
| | | | | | | | | |
| Other comprehensive loss | | | | (2,517 | ) | | | (348 | ) | | | (2,169 | ) |
| Less other comprehensive loss attributable to noncontrolling interest | | | | (1,623 | ) | | — | | | (1,623 | ) |
| | | | | | | | | |
| Other comprehensive loss attributable to Holly stockholders | | | $ | (894 | ) | | $ | (348 | ) | | $ | (546 | ) |
| | | | | | | | | |
| | | |
Year Ended December 31, 2009 | | |
| Unrealized gain on available-for-sale securities | | | $ | 409 | | $ | 158 | | $ | 251 | |
| Unrealized gain on hedging activities | | | 3,726 | | 663 | | 3,063 | |
| Retirement medical obligation adjustment | | | (5,038 | ) | | | (1,960 | ) | | | (3,078 | ) | | 742 | | 289 | | 453 | |
| Unrealized gain on available-for-sale securities | | 1,779 | | 693 | | 1,086 | | |
| Minimum pension liability adjustment | | | 12,497 | | 4,862 | | 7,635 | |
| | | | | | | | | | | | | | | |
| Other comprehensive loss attributable to Holly Corporation stockholders | | $ | (12,632 | ) | | $ | (4,914 | ) | | $ | (7,718 | ) | |
| Other comprehensive income | | | 17,374 | | 5,972 | | 11,402 | |
| Less other comprehensive income attributable to noncontrolling interest | | | 2,021 | | — | | 2,021 | |
| | | | | | | | | | | | | | | |
| Other comprehensive income attributable to Holly stockholders | | | $ | 15,353 | | $ | 5,972 | | $ | 9,381 | |
| | | | | | | | | |
| | | |
Year Ended December 31, 2008 | | |
| Unrealized loss on available-for-sale securities | | | $ | (169 | ) | | $ | (67 | ) | | $ | (102 | ) |
| Unrealized loss on hedging activities | | | | (12,967 | ) | | | (2,290 | ) | | | (10,677 | ) |
| Retirement medical obligation adjustment | | | 1,433 | | 557 | | 876 | |
| Minimum pension liability adjustment | | | | (21,572 | ) | | | (8,391 | ) | | | (13,181 | ) |
| | | | | | | | | |
| Other comprehensive loss | | | | (33,275 | ) | | | (10,191 | ) | | | (23,084 | ) |
| Less other comprehensive loss attributable to noncontrolling interest | | | | (7,079 | ) | | — | | | (7,079 | ) |
| | | | | | | | | |
| Other comprehensive loss attributable to Holly stockholders | | | $ | (26,196 | ) | | $ | (10,191 | ) | | $ | (16,005 | ) |
| | | | | | | | | |
The temporary unrealized gain (loss) on available-for-sale securities available-for-sale is due to changes in the market prices of securities.
Accumulated other comprehensive loss in the equity section of our Consolidated Balance Sheetsconsolidated balance sheets includes:
| | | | | | | | | | |
| | | December 31, | | | | | | | | | |
| | | 2009 | | 2008 | | | December 31, | |
| | | (In thousands) | | | 2010 | | 2009 | |
| | | | (In thousands) | |
| Pension obligation adjustment | | $ | (21,774 | ) | | $ | (29,409 | ) | | $ | (22,672 | ) | | $ | (21,774 | ) |
| Retiree medical obligation adjustment | | | (1,749 | ) | | | (2,202 | ) | | | (1,894 | ) | | | (1,749 | ) |
| Unrealized gain on securities available-for-sale | | 379 | | 128 | | | 451 | | 379 | |
| Unrealized loss on HEP cash flow hedge, net of minority interest | | | (2,556 | ) | | | (3,598 | ) | |
| Unrealized loss on hedging activities, net of noncontrolling interest | | | | (2,131 | ) | | | (2,556 | ) |
| | | | | | | | | | | |
| Accumulated other comprehensive loss | | $ | (25,700 | ) | | $ | (35,081 | ) | | $ | (26,246 | ) | | $ | (25,700 | ) |
| | | | | | | | | | | |
NOTE 16:17: Retirement Plans
Retirement Plan: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 employee’s years of service and compensation.
Effective January 1, 2007, theThe retirement plan was frozenis closed to new employees hired subsequent to 2006 and not covered by collective bargaining agreements with labor unions. To the extent ana 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.
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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 following table sets forth the changes in the benefit obligation and plan assets of our retirement plan for the years ended December 31, 20092010 and 2008:2009:
| | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2009 | | | 2008 | |
| | | (In thousands) | |
| Change in plan’s benefit obligation | | | | | | | | |
| Pension plan’s benefit obligation — beginning of year | | $ | 74,488 | | | $ | 72,842 | |
| Service cost | | | 4,314 | | | | 4,229 | |
| Interest cost | | | 4,943 | | | | 4,692 | |
| Benefits paid | | | (3,726 | ) | | | (6,188 | ) |
| Actuarial (gain) loss | | | 1,151 | | | | (1,087 | ) |
| | | | | | | |
| Pension plan’s benefit obligation — end of year | | | 81,170 | | | | 74,488 | |
| | | | | | | | | |
| Change in pension plan assets | | | | | | | | |
| Fair value of plan assets — beginning of year | | | 45,342 | | | | 56,454 | |
| Actual return on plan assets | | | 12,977 | | | | (19,924 | ) |
| Benefits paid | | | (3,726 | ) | | | (6,188 | ) |
| Employer contributions | | | 1,025 | | | | 15,000 | |
| | | | | | | |
| Fair value of plan assets — end of year | | | 55,618 | | | | 45,342 | |
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| | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | Years Ended December 31, | |
| | | | 2010 | | 2009 | |
| | | | (In thousands) | |
| Change in plan’s benefit obligation | | |
| Pension plan’s benefit obligation — beginning of year | | | $ | 81,170 | | $ | 74,488 | |
| Service cost | | | 4,595 | | 4,314 | |
| Interest cost | | | 5,154 | | 4,943 | |
| Benefits paid | | | | (4,825 | ) | | | (3,726 | ) |
| Actuarial (gain) loss | | | 7,989 | | 1,151 | |
| | | | | | | |
| Pension plan’s benefit obligation — end of year | | | $ | 94,083 | | $ | 81,170 | |
| | | | | | | |
| | | |
| Change in pension plan assets | | |
| Fair value of plan assets — beginning of year | | | $ | 55,618 | | $ | 45,342 | |
| Actual return on plan assets | | | 8,297 | | 12,977 | |
| Benefits paid | | | | (4,825 | ) | | | (3,726 | ) |
| Employer contributions | | | 5,400 | | 1,025 | |
| | | | | | | |
| Fair value of plan assets — end of year | | | $ | 64,490 | | $ | 55,618 | |
| | | 2009 | | 2008 | | | | | | |
| | | (In thousands) | | |
| Funded status | | |
| Under-funded balance | | $ | (25,552 | ) | | $ | (29,146 | ) | | $ | (29,593 | ) | | $ | (25,552 | ) |
| | | | | | | | | | | |
| | | |
| Amounts recognized in consolidated balance sheets | | |
| Accrued pension liability | | $ | (25,552 | ) | | $ | (29,146 | ) | | $ | (29,593 | ) | | $ | (25,552 | ) |
| | | | | | | | | | | |
| | | |
| Amounts recognized in accumulated other comprehensive loss | | |
| Actuarial loss | | $ | (31,677 | ) | | $ | (43,475 | ) | | $ | (33,750 | ) | | $ | (31,677 | ) |
| Prior service cost | | | (2,811 | ) | | | (3,201 | ) | | | (2,420 | ) | | | (2,811 | ) |
| | | | | | | | | | | |
| Total | | $ | (34,488 | ) | | $ | (46,676 | ) | | $ | (36,170 | ) | | $ | (34,488 | ) |
| | | | | | | | | | | |
The accumulated benefit obligation was $65$75.4 million and $58.7$65 million at December 31, 20092010 and 2008,2009, respectively. The measurement dates used for our retirement plan were December 31, 20092010 and 2008.2009.
The weighted average assumptions used to determine end of period benefit obligations:
| | | | | | | | | | |
| | | December 31, | | | | | | | | | |
| | | 2009 | | 2008 | | | December 31, |
| | | | 2010 | | 2009 |
| Discount rate | | | 6.20 | % | | | 6.50 | % | | | 5.65 | % | | | 6.20 | % |
| Rate of future compensation increases | | | 4.00 | % | | | 4.00 | % | | | 4.00 | % | | | 4.00 | % |
Net periodic pension expense consisted of the following components:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | Years Ended December 31, | |
| | | 2009 | | 2008 | | 2007 | | | 2010 | | 2009 | | 2008 | |
| | | (In thousands) | | | (In thousands) | |
| Service cost — benefit earned during the year | | $ | 4,314 | | $ | 4,229 | | $ | 4,110 | | | $ | 4,595 | | $ | 4,314 | | $ | 4,229 | |
| Interest cost on projected benefit obligations | | 4,943 | | 4,692 | | 4,075 | | | 5,154 | | 4,943 | | 4,692 | |
| Expected return on plan assets | | | (3,843 | ) | | | (4,793 | ) | | | (4,078 | ) | | | (4,576 | ) | | | (3,843 | ) | | | (4,793 | ) |
| Amortization of prior service cost | | 390 | | 390 | | 390 | | | 390 | | 390 | | 390 | |
| Amortization of net loss | | 3,815 | | 1,218 | | 908 | | | 2,196 | | 3,815 | | 1,218 | |
| | | | | | | | | | | | | | | |
| Net periodic pension expense | | $ | 9,619 | | $ | 5,736 | | $ | 5,405 | | | $ | 7,759 | | $ | 9,619 | | $ | 5,736 | |
| | | | | | | | | | | | | | | |
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The weighted average assumptions used to determine net periodic benefit expense:
| | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | | | | | | | | | | | |
| | | 2009 | | 2008 | | 2007 | | | Years Ended December 31, |
| | | | 2010 | | 2009 | | 2008 |
| Discount rate | | | 6.50 | % | | | 6.40 | % | | | 6.00 | % | | | 6.20 | % | | | 6.50 | % | | | 6.40 | % |
| Rate of future compensation increases | | | 4.00 | % | | | 4.00 | % | | | 4.00 | % | | | 4.00 | % | | | 4.00 | % | | | 4.00 | % |
| Expected long-term rate of return on assets | | | 8.50 | % | | | 8.50 | % | | | 8.50 | % | | | 8.50 | % | | | 8.50 | % | | | 8.50 | % |
The estimated amounts that will be amortized from accumulated other comprehensive income into net periodic benefit expense in 2010 are as follows:
| | | | | | | | | |
| | | (In thousands) | | | (In thousands) | |
| Actuarial loss | | $ | 2,496 | | | $ | 2,126 | |
| Prior service cost | | 390 | | | 390 | |
| | | | | | | |
| Total | | $ | 2,886 | | | $ | 2,516 | |
| | | | | | | |
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At year end, our retirement plan assets were allocated as follows:
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Percentage of Plan Assets at |
| | | Percentage of Plan Assets at | | | Year End |
| | | Target | | Year End | | | Target | | | | |
| | | Allocation | | December 31, | | December 31, | | | Allocation | | December 31, | | December 31, |
| Asset Category | | 2010 | | 2009 | | 2008 | | | 2011 | | 2010 | | 2009 |
| Equity securities | | | 70 | % | | | 69 | % | | | 65 | % | | | 62 | % | | | 66 | % | | | 69 | % |
| Debt Securities | | | 30 | % | | | 31 | % | | | 35 | % | |
| Debt securities | | | | 30 | % | | | 30 | % | | | 31 | % |
| Alternative investments | | | | 8 | % | | | 4 | % | | — | |
| | | | | | | | | | | | | | | |
| Total | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % |
| | | | | | | | | | | | | | | |
The investment policy developed for the Holly Corporation Pension Plan (the “Plan”) has been designed exclusively for the purpose of providing the highest probabilities of delivering benefits to Plan members and beneficiaries. Among the factors considered in developing the investment policy are: the Plans’ primary investment goal, rate of return objective, investment risk, investment time horizon, role of asset classes and asset allocation.
The most important component of the investment strategy is the asset allocation between the various classes of securities available to the Plan for investment purposes. The current target asset allocation is 70%62% equity investments, and 30% fixed income investments and 8% alternative investments. Equity investments include a blend of domestic growth and value stocks of various sizes of capitalization and international stocks. Debt investments include a blend of domestic and global debt instruments. Alternative investments include a single fund that may invest in hedge funds, private equity, debt or real estate funds or other investments. The equity and debt investments are valued using quoted market prices, a Level 1 input. The alternative investments may be valued using significant other observable or unobservable inputs, Level 2 or 3 inputs. See Note 4, Financial Instruments for information on Level 1, 2 and 3 inputs.
The overall expected long-term rate of return on Plan assets is 8.5% and is estimated using a financial simulation model of asset returns. Model assumptions are derived using historical data given the assumption that capital markets are informationally efficient.
We expect to contribute between zero and $10 million to the retirement plan in 2010.2011. Benefit payments, which reflect expected future service, are expected to be paid as follows: $5.6 million in 2010; $6.3$6.8 million in 2011; $5.5 million in 2012; $7.1 million in 2012;2013; $8 million in 2013; $7.82014; $8.2 million in 20142015 and $55.2$56.1 million in 2015-2019.2016-2020.
Retirement Restoration Plan:Plan
We adopted an unfunded retirement restoration plan that provides for additional payments from us so that total retirement plan benefits for certain executives will be maintained at the levels provided in the retirement plan before the application of Internal Revenue Code limitations. We expensed $0.6 million, $0.7 million $1.1 million and $0.9$1.1 million for the years ended December 31, 2010, 2009 2008 and 2007,2008, respectively, in connection with this plan. The accrued liability reflected in the consolidated balance sheets was $6.2 million and $6.1 million at December 31, 2010 and 2009, and 2008.respectively. As of December 31, 2009,2010, the projected benefit obligation under this plan was $6.1$6.2 million. Benefit payments, which reflect expected future service, are expected to be paid as follows: $0.4 million in 2010; $1.2$0.6 million in 2011; $1.1 million in 2012; $0.5 million in 2012; $1.72013; $1.5 million in 2013;2014; $0.5 million in 20142015 and $3.2$3 million in 2015-2019.2016-2020.
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Defined Contribution Plans:Plans
We have defined contribution “401(k)” plans that cover substantially all employees. Our contributions are based on employee’s compensation and partially match employee contributions. We expensed $5.5 million, $5 million $3.7 million and $2.8$3.7 million for the years ended December 31, 2010, 2009 2008 and 2007,2008, respectively, in connection with these plans.
Postretirement Medical Plans:Plans
We adopted an unfunded postretirement medical plan as part of the voluntary early retirement program offered to eligible employees in fiscal 2000. As part of the early retirement program, we agreed to allow retiring employees to continue coverage at a reduced cost under our group medical plans until normal retirement age. The accrued liability reflected in the consolidated balance sheets was $6.6 million and $6.6 million at December 31, 2009 and 2008, respectively, related to this plan.
Additionally, we maintain an unfunded postretirement medical plan whereby certain retirees between the ages of 62 and 65 can receive benefits paid by us. Periodic costs under this plan have historically been insignificant.
As of The accrued liability reflected in the consolidated balance sheets was $7.9 million and $6.6 million at December 31, 2010 and 2009, the total accumulated postretirement benefit obligation under our postretirement medical plans was $6.6 million.respectively, related to this plan.
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NOTE 17:18: Lease Commitments
We lease certain facilities and equipment under operating leases, most of which contain renewal options. At December 31, 2009,2010, the minimum future rental commitments under operating leases having non-cancellable lease terms in excess of one year are as follows (in thousands):follows:
| | | | | | | | | |
| 2010 | | $ | 16,712 | | |
| | | | (in thousands) | |
| 2011 | | 14,963 | | | $ | 16,375 | |
| 2012 | | 11,683 | | | 14,012 | |
| 2013 | | 9,919 | | | 12,119 | |
| 2014 | | 9,360 | | | 10,966 | |
| 2015 | | | 10,510 | |
| Thereafter | | 25,125 | | | 19,945 | |
| | | | | | | |
| Total | | $ | 87,762 | | | $ | 83,927 | |
| | | | | | | |
Rental expense charged to operations was $13.3 million, $11.8 million $9.8 million and $3.2$9.8 million for the years ended December 31, 2010, 2009 2008 and 2007,2008, respectively. Rental expense for the years ended December 31, 2010, 2009 and 2008 includes $7.1 million, $7.1 million and $6.5 million, respectively, of rental expense attributable to the operations of HEP as a result of our reconsolidation effective March 1, 2008.HEP.
NOTE 18:19: Contingencies and Contractual Obligations
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 SFPP’s 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 byas 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 income tax issuecase was remanded to FERC and theconsolidated with other remaining issues relating tocases that together addressed SFPP’s obligations to shippers are being handled by the FERC in a single compliance proceeding coveringrates for the period from January 1992 through May 2006. We currently estimate that, as a result of the May 2007 Court of Appeals decision and prior rulings by the Court of Appeals and the FERC in these proceedings, a net amount will be due from SFPP to us for the period January 1992 through May 2006 in addition to the $15.3 millionIn 2003 we received in 2003an initial payment of $15.3 million from SFPP as reparations for the period from 1992 through July 2000. Because proceedings inOn April 16, 2010, a settlement among us, SFPP, and other shippers was filed with FERC for its approval. FERC approved the FERC followingsettlement on May 28, 2010. Pursuant to the Courtsettlement, we received an additional settlement payment of Appeals decision have not been completed and final action by$8.6 million. This settlement finally resolves the FERC could be subject to further court proceedings, it is not possible at this time to determine what will beamount of additional payments SFPP owes us for the net amount payable to us at the conclusion of these proceedings.period January 1992 through May 2006.
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We and other shippers have beenalso engaged in settlement discussions with SFPP on remaining issues relating to East Line service in the FERC proceedings.proceedings that address periods after May 2006. A partial settlement regarding the East Line’s 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 approximately $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 Line’s Phase II expansion rates covering the period from December 20082007 through November 2010. The FERC approved the settlement on January 29, 2009. The settlement reduced SFPP’s current rates and required SFPP to make additional payments to us of approximately $2.9 million, which was received on May 18, 2009.
On June 2, 2009, SFPP notified us that it would terminate the October 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. The hearing was held from June 29, 2010 to be heldAugust 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 2010.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 SFPP’s 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.
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We are a party to various other litigation and proceedings not mentioned in this report thatwhich 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.
Contractual Obligations
We have a long-term supply agreement to secure a hydrogen supply source for our Woods Cross hydrotreater unit. The contract commits us to purchase a minimum of 5 million standard cubic feet of hydrogen per day at market prices over a 15-year period expiring in 2023. The contract also requires the payment of a base facility charge for use of the supplier’s facility over the supply term.
We also have crude oil transportation agreements that obligate us to ship a total of approximately 43,000 barrels per day for initial terms of 10 years expiring in 2019 through 2024.
Other contractual obligations relate tounder agreements with third parties for the transportation of crude oil, natural gas and feedstocks to our refineries under contracts expiring in 2016 through 2024 and various service contracts with expiration dates through 2011.2024.
NOTE 19:20: 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 Company. The Refining segmentand involves the purchase and refining of crude oil and wholesale and branded marketing of refined products, such as gasoline, diesel fuel and jet fuel. TheThese petroleum products produced by the Refining segment are primarily marketed in the Southwest, Rocky Mountain and Mid-Continent regions of the United States and northern Mexico. Additionally, the Refining segment also 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.
HEP is a VIE as defined under GAAP. A VIE is legal entity whose equity owners do not have sufficient equity at risk or a controlling interest in the entity, or have voting rights that are not proportionate to their economic interest.
Under GAAP, HEP’s acquisition of the Crude Pipelines and Tankage Assets (see Note 3) qualified as a reconsideration event whereby we reassessed whether HEP continued to qualify as a VIE. Following this transfer, we determined that HEP continued to qualify as a VIE, and furthermore, we determined that our beneficial interest in HEP exceeded 50%. Accordingly, we reconsolidated HEP effective March 1, 2008 and no longer account for our investment in HEP under the equity method of accounting. As a result, our consolidated financial statements include the results of HEP.
The HEP segment involvesincludes all of the operations of HEP effective March 1, 2008 (date of reconsolidation). HEP, a consolidated VIE, 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 Utah.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
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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 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 HEP’s 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 HEP’s periodic public filings.
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| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Consolidations | | |
| | | | | | | | | | | Corporate | | and | | Consolidated |
| | | Refining(1) | | HEP(2) | | and Other | | Eliminations | | Total |
| | | (In thousands) |
Year Ended December 31, 2010 | | | | | | | | | | | | | | | | | | | | |
| Sales and other revenues | | $ | 8,287,000 | | | $ | 182,114 | | | $ | 415 | | | $ | (146,600 | ) | | $ | 8,322,929 | |
| Depreciation and amortization | | $ | 84,587 | | | $ | 29,062 | | | $ | 4,562 | | | $ | (682 | ) | | $ | 117,529 | |
| Income (loss) from operations | | $ | 242,466 | | | $ | 92,386 | | | $ | (69,654 | ) | | $ | (2,200 | ) | | $ | 262,998 | |
| Capital expenditures | | $ | 186,441 | | | $ | 25,103 | | | $ | 1,688 | | | $ | — | | | $ | 213,232 | |
| Total assets | | $ | 2,490,193 | | | $ | 669,820 | | | $ | 573,531 | | | $ | (32,069 | ) | | $ | 3,701,475 | |
| | | | | | | | | | | | | | | | | | | | | |
Year Ended December 31, 2009 | | | | | | | | | | | | | | | | | | | | |
| Sales and other revenues | | $ | 4,789,821 | | | $ | 146,561 | | | $ | (636 | ) | | $ | (101,478 | ) | | $ | 4,834,268 | |
| Depreciation and amortization | | $ | 67,347 | | | $ | 24,599 | | | $ | 6,805 | | | $ | — | | | $ | 98,751 | |
| Income (loss) from operations | | $ | 71,281 | | | $ | 70,373 | | | $ | (60,239 | ) | | $ | (1,104 | ) | | $ | 80,311 | |
| Capital expenditures | | $ | 266,648 | | | $ | 32,999 | | | $ | 2,904 | | | $ | — | | | $ | 302,551 | |
| Total assets | | $ | 2,142,317 | | | $ | 641,775 | | | $ | 392,007 | | | $ | (30,160 | ) | | $ | 3,145,939 | |
| | | | | | | | | | | | | | | | | | | | | |
Year Ended December 31, 2008 | | | | | | | | | | | | | | | | | | | | |
| Sales and other revenues | | $ | 5,837,449 | | | $ | 94,439 | | | $ | 2,641 | | | $ | (74,172 | ) | | $ | 5,860,357 | |
| Depreciation and amortization | | $ | 40,090 | | | $ | 18,390 | | | $ | 4,515 | | | $ | — | | | $ | 62,995 | |
| Income (loss) from operations | | $ | 210,252 | | | $ | 37,082 | | | $ | (51,654 | ) | | $ | — | | | $ | 195,680 | |
| Capital expenditures | | $ | 381,227 | | | $ | 34,317 | | | $ | 2,515 | | | $ | — | | | $ | 418,059 | |
| Total assets | | $ | 1,288,211 | | | $ | 458,049 | | | $ | 141,768 | | | $ | (13,803 | ) | | $ | 1,874,225 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Consolidations | | | | |
| | | | | | | | | | | Corporate | | | and | | | Consolidated | |
| | | Refining(1) | | | HEP(2) | | | and Other | | | Eliminations | | | Total | |
| | | (In thousands) | |
Year Ended December 31, 2009 | | | | | | | | | | | | | | | | | | | | |
| Sales and other revenues | | $ | 4,786,937 | | | $ | 146,561 | | | $ | 2,248 | | | $ | (101,478 | ) | | $ | 4,834,268 | |
| Depreciation and amortization | | $ | 67,347 | | | $ | 24,599 | | | $ | 6,805 | | | $ | — | | | $ | 98,751 | |
| Income (loss) from operations | | $ | 68,397 | | | $ | 70,373 | | | $ | (57,355 | ) | | $ | (1,104 | ) | | $ | 80,311 | |
| Capital expenditures | | $ | 266,648 | | | $ | 32,999 | | | $ | 2,904 | | | $ | — | | | $ | 302,551 | |
| Total assets | | $ | 2,142,317 | | | $ | 641,775 | | | $ | 392,007 | | | $ | (30,160 | ) | | $ | 3,145,939 | |
| | | | | | | | | | | | | | | | | | | | | |
Year Ended December 31, 2008 | | | | | | | | | | | | | | | | | | | | |
| Sales and other revenues | | $ | 5,837,449 | | | $ | 94,439 | | | $ | 2,641 | | | $ | (74,172 | ) | | $ | 5,860,357 | |
| Depreciation and amortization | | $ | 40,090 | | | $ | 18,390 | | | $ | 4,515 | | | $ | — | | | $ | 62,995 | |
| Income (loss) from operations | | $ | 210,252 | | | $ | 37,082 | | | $ | (51,654 | ) | | $ | — | | | $ | 195,680 | |
| Capital expenditures | | $ | 381,227 | | | $ | 34,317 | | | $ | 2,515 | | | $ | — | | | $ | 418,059 | |
| Total assets | | $ | 1,288,211 | | | $ | 458,049 | | | $ | 141,768 | | | $ | (13,803 | ) | | $ | 1,874,225 | |
| | | | | | | | | | | | | | | | | | | | | |
Year Ended December 31, 2007 | | | | | | | | | | | | | | | | | | | | |
| Sales and other revenues | | $ | 4,790,164 | | | $ | — | | | $ | 1,578 | | | $ | — | | | $ | 4,791,742 | |
| Depreciation and amortization | | $ | 40,325 | | | $ | — | | | $ | 3,131 | | | $ | — | | | $ | 43,456 | |
| Income (loss) from operations | | $ | 537,118 | | | $ | — | | | $ | (70,786 | ) | | $ | — | | | $ | 466,332 | |
| Capital expenditures | | $ | 151,448 | | | $ | — | | | $ | 9,810 | | | $ | — | | | $ | 161,258 | |
| Total assets | | $ | 1,271,163 | | | $ | — | | | $ | 392,782 | | | $ | — | | | $ | 1,663,945 | |
| | |
| (1) | | The Refining segment reflects the operations of our Tulsa Refinery west and east facilities beginning on our respective acquisition dates of June 1, 2009 and December 1, 2009, respectively. |
| |
| (2) | | HEP segment revenues from external customers were $36 million, $45.5 million and $19.3 million for the years ended December 31, 2010, 2009 and 2008, respectively. The HEP segment reflects the operations of various 2009 asset acquisitions (see Note 3). |
|
NOTE 20:21: 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 HEP’s 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 HEP’s periodic public filings.
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Condensed Consolidating Balance Sheet
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Non- | | Holly Corp. | | Non-Guarantor | | | | | | | Non- | | Holly Corp. | | Non-Guarantor | | | | | |
| | | Guarantor | | Guarantor | | Before | | Non-Restricted | | | | | | | Guarantor | | Guarantor | | Before | | Non-Restricted | | | | | |
| | | Restricted | | Restricted | | Consolidation | | Subsidiaries | | | | | | | Restricted | | Restricted | | Consolidation | | Subsidiaries | | | | | |
| December 31, 2009 | | Parent | | Subsidiaries | | Subsidiaries | | Eliminations | | of HEP(1) | | (HEP Segment) | | Eliminations | | Consolidated | | |
| December 31, 2010 | | | Parent | | Subsidiaries | | Subsidiaries | | Eliminations | | of HEP | | (HEP Segment) | | Eliminations | | Consolidated | |
| | | (In thousands) | | | (In thousands) | |
ASSETS | | |
| Current assets: | | |
| Cash and cash equivalents | | $ | 127,560 | | $ | (12,477 | ) | | $ | 7,005 | | $ | — | | $ | 122,088 | | $ | 2,508 | | $ | — | | $ | 124,596 | | | $ | 230,082 | | $ | (9,035 | ) | | $ | 7,651 | | $ | — | | $ | 228,698 | | $ | 403 | | $ | — | | $ | 229,101 | |
| Marketable securities | | — | | 1,223 | | — | | — | | 1,223 | | — | | — | | 1,223 | | | — | | 1,343 | | — | | — | | 1,343 | | — | | — | | 1,343 | |
| Accounts receivable | | 973 | | 759,140 | | — | | — | | 760,113 | | 18,767 | | | (16,425 | ) | | 762,455 | | | 1,683 | | 991,778 | | — | | — | | 993,461 | | 22,508 | | | (22,853 | ) | | 993,116 | |
| Intercompany accounts receivable (payable) | | | (1,134,296 | ) | | 817,647 | | 316,649 | | — | | — | | — | | — | | — | | | | (1,401,580 | ) | | 981,691 | | 419,889 | | — | | — | | — | | — | | — | |
| Inventories | | — | | 303,348 | | — | | — | | 303,348 | | 165 | | — | | 303,513 | | | — | | 400,165 | | — | | — | | 400,165 | | 202 | | — | | 400,367 | |
| Income taxes receivable | | 38,071 | | 1 | | — | | — | | 38,072 | | — | | — | | 38,072 | | | 51,034 | | — | | — | | — | | 51,034 | | — | | — | | 51,034 | |
| Prepayments and other assets | | 24,940 | | 29,018 | | — | | — | | 53,958 | | 574 | | | (3,575 | ) | | 50,957 | | | 10,210 | | 20,942 | | — | | — | | 31,152 | | 573 | | | (3,251 | ) | | 28,474 | |
| Current assets of discontinued operations | | — | | — | | — | | — | | — | | 2,195 | | — | | 2,195 | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total current assets | | | (942,752 | ) | | 1,897,900 | | 323,654 | | — | | 1,278,802 | | 24,209 | | | (20,000 | ) | | 1,283,011 | | | | (1,108,571 | ) | | 2,386,884 | | 427,540 | | — | | 1,705,853 | | 23,686 | | | (26,104 | ) | | 1,703,435 | |
| | | |
| Properties and equipment, net | | 21,918 | | 1,005,422 | | 155,413 | | — | | 1,182,753 | | 458,521 | | | (11,304 | ) | | 1,629,970 | | | 17,177 | | 1,017,877 | | 236,648 | | — | | 1,271,702 | | 492,098 | | | (7,109 | ) | | 1,756,691 | |
| Investment in subsidiaries | | 2,010,510 | | 435,970 | | | (314,973 | ) | | | (2,131,507 | ) | | — | | — | | — | | — | | | 2,273,159 | | 595,888 | | | (393,011 | ) | | | (2,476,036 | ) | | — | | — | | — | | — | |
| Intangibles and other assets | | 8,752 | | 64,017 | | — | | — | | 72,769 | | 159,045 | | 1,144 | | 232,958 | | | 8,569 | | 77,600 | | — | | — | | 86,169 | | 154,036 | | 1,144 | | 241,349 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total assets | | $ | 1,098,428 | | $ | 3,403,309 | | $ | 164,094 | | $ | (2,131,507 | ) | | $ | 2,534,324 | | $ | 641,775 | | $ | (30,160 | ) | | $ | 3,145,939 | | | $ | 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 | | $ | 8,968 | | $ | 974,177 | | $ | 2,224 | | $ | — | | $ | 985,369 | | $ | 6,211 | | $ | (16,425 | ) | | $ | 975,155 | | | $ | 7,170 | | $ | 1,319,316 | | $ | 3,575 | | $ | — | | $ | 1,330,061 | | $ | 10,238 | | $ | (22,853 | ) | | $ | 1,317,446 | |
| Accrued liabilities | | 23,752 | | 15,477 | | 709 | | — | | 39,938 | | 13,594 | | | (3,575 | ) | | 49,957 | | | 25,512 | | 28,145 | | 797 | | — | | 54,454 | | 21,206 | | | (3,251 | ) | | 72,409 | |
| Other liabilities | | — | | — | | — | | — | | — | | — | | — | | — | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total current liabilities | | 32,720 | | 989,654 | | 2,933 | | — | | 1,025,307 | | 19,805 | | | (20,000 | ) | | 1,025,112 | | | 32,682 | | 1,347,461 | | 4,372 | | — | | 1,384,515 | | 31,444 | | | (26,104 | ) | | 1,389,855 | |
| | | |
| Long-term debt | | 288,451 | | 39,809 | | — | | — | | 328,260 | | 379,198 | | — | | 707,458 | | | 289,509 | | 55,706 | | — | | — | | 345,215 | | 482,271 | | | (16,925 | ) | | 810,561 | |
| Non-current liabilities | | 37,859 | | 48,137 | | — | | — | | 85,996 | | 12,349 | | | (17,342 | ) | | 81,003 | | | 42,655 | | 27,521 | | — | | — | | 70,176 | | 10,809 | | — | | 80,985 | |
| Deferred income taxes | | 119,127 | | 229 | | 278 | | — | | 119,634 | | — | | 4,951 | | 124,585 | | | 126,160 | | 259 | | 565 | | — | | 126,984 | | — | | 4,951 | | 131,935 | |
| Distributions in excess of inv in HEP | | — | | 314,970 | | — | | — | | 314,970 | | — | | | (314,970 | ) | | — | | | — | | 374,143 | | — | | — | | 374,143 | | — | | | (374,143 | ) | | — | |
| Equity — Holly Corporation | | 620,271 | | 2,010,510 | | 160,883 | | | (2,171,393 | ) | | 620,271 | | 230,423 | | | (231,655 | ) | | 619,039 | | | 699,328 | | 2,273,159 | | 266,240 | | | (2,539,399 | ) | | 699,328 | | 145,296 | | | (147,205 | ) | | 697,419 | |
| Equity — Noncontrolling interest | | — | | — | | — | | 39,886 | | 39,886 | | — | | 548,856 | | 588,742 | | |
| Equity — noncontrolling interest | | | — | | — | | — | | 63,363 | | 63,363 | | — | | 527,357 | | 590,720 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total liabilities and equity | | $ | 1,098,428 | | $ | 3,403,309 | | $ | 164,094 | | $ | (2,131,507 | ) | | $ | 2,534,324 | | $ | 641,775 | | $ | (30,160 | ) | | $ | 3,145,939 | | | $ | 1,190,334 | | $ | 4,078,249 | | $ | 271,177 | | $ | (2,476,036 | ) | | $ | 3,063,724 | | $ | 669,820 | | $ | (32,069 | ) | | $ | 3,701,475 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
-107-
Condensed Consolidating Balance Sheet
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Non- | | Holly Corp. | | Non-Guarantor | | | | | | | Non- | | Holly Corp. | | Non-Guarantor | | | | | |
| | | Guarantor | | Guarantor | | Before | | Non-Restricted | | | | | | | Guarantor | | Guarantor | | Before | | Non-Restricted | | | | | |
| | | Restricted | | Restricted | | Consolidation | | Subsidiaries | | | | | | | Restricted | | Restricted | | Consolidation | | Subsidiaries | | | | | |
| December 31, 2008 | | Parent | | Subsidiaries | | Subsidiaries | | Eliminations | | of HEP(1) | | (HEP Segment) | | Eliminations | | Consolidated | | |
| December 31, 2009 | | | Parent | | Subsidiaries | | Subsidiaries | | Eliminations | | of HEP(1) | | (HEP Segment) | | Eliminations | | Consolidated | |
| | | (In thousands) | | | (In thousands) | |
ASSETS | | |
| Current assets: | | |
| Cash and cash equivalents | | $ | 33,316 | | $ | (1,182 | ) | | $ | 3,402 | | $ | — | | $ | 35,536 | | $ | 3,708 | | $ | — | | $ | 39,244 | | | $ | 127,560 | | $ | (12,477 | ) | | $ | 7,005 | | $ | — | | $ | 122,088 | | $ | 2,508 | | $ | — | | $ | 124,596 | |
| Marketable securities | | 48,590 | | 604 | | — | | — | | 49,194 | | — | | — | | 49,194 | | | — | | 1,223 | | — | | — | | 1,223 | | — | | — | | 1,223 | |
| Accounts receivable | | 1,734 | | 283,480 | | 1,524 | | — | | 286,738 | | 13,332 | | | (11,451 | ) | | 288,619 | | | 973 | | 759,140 | | — | | — | | 760,113 | | 18,767 | | | (16,425 | ) | | 762,455 | |
| Intercompany accounts receivable (payable) | | | (1,419,212 | ) | | 1,134,118 | | 285,094 | | — | | — | | — | | — | | — | | | | (1,134,296 | ) | | 817,647 | | 316,649 | | — | | — | | — | | — | | — | |
| Inventories | | — | | 125,613 | | — | | — | | 125,613 | | 122 | | — | | 125,735 | | | — | | 303,348 | | — | | — | | 303,348 | | 165 | | — | | 303,513 | |
| Income taxes receivable | | 6,350 | | — | | — | | — | | 6,350 | | — | | — | | 6,350 | | | 38,071 | | 1 | | — | | — | | 38,072 | | — | | — | | 38,072 | |
| Prepayments and other assets | | 13,814 | | 6,842 | | — | | — | | 20,656 | | 471 | | | (2,352 | ) | | 18,775 | | | 24,940 | | 29,018 | | — | | — | | 53,958 | | 574 | | | (3,575 | ) | | 50,957 | |
| Current assets of discontinued operations | | — | | — | | — | | — | | — | | 2,706 | | — | | 2,706 | | | — | | — | | — | | — | | — | | 2,195 | | — | | 2,195 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total current assets | | | (1,315,408 | ) | | 1,549,475 | | 290,020 | | — | | 524,087 | | 20,339 | | | (13,803 | ) | | 530,623 | | | | (942,752 | ) | | 1,897,900 | | 323,654 | | — | | 1,278,802 | | 24,209 | | | (20,000 | ) | | 1,283,011 | |
| | | |
| Properties and equipment, net | | 22,997 | | 718,575 | | 109,660 | | — | | 851,232 | | 321,692 | | — | | 1,172,924 | | | 21,918 | | 1,005,422 | | 155,413 | | — | | 1,182,753 | | 458,521 | | | (11,304 | ) | | 1,629,970 | |
| Marketable securities (long-term) | | 6,009 | | — | | — | | — | | 6,009 | | — | | — | | 6,009 | | |
| Investment in subsidiaries | | 1,911,613 | | 371,964 | | | (321,003 | ) | | | (1,962,574 | ) | | — | | — | | — | | — | | | 2,010,510 | | 435,970 | | | (314,973 | ) | | | (2,131,507 | ) | | — | | — | | — | | — | |
| Intangibles and other assets | | — | | 48,651 | | — | | — | | 48,651 | | 83,620 | | — | | 132,271 | | | 8,752 | | 64,017 | | — | | — | | 72,769 | | 159,045 | | 1,144 | | 232,958 | |
| Non-current assets of discontinued operations | | — | | — | | — | | — | | — | | 32,398 | | — | | 32,398 | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total assets | | $ | 625,211 | | $ | 2,688,665 | | $ | 78,677 | | $ | (1,962,574 | ) | | $ | 1,429,979 | | $ | 458,049 | | $ | (13,803 | ) | | $ | 1,874,225 | | | $ | 1,098,428 | | $ | 3,403,309 | | $ | 164,094 | | $ | (2,131,507 | ) | | $ | 2,534,324 | | $ | 641,775 | | $ | (30,160 | ) | | $ | 3,145,939 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
LIABILITIES AND EQUITY | | |
| Current liabilities: | | |
| Accounts payable | | $ | 9,269 | | $ | 384,285 | | $ | 1,021 | | $ | — | | $ | 394,575 | | $ | 7,315 | | $ | (11,452 | ) | | $ | 390,438 | | | $ | 8,968 | | $ | 974,177 | | $ | 2,224 | | $ | — | | $ | 985,369 | | $ | 6,211 | | $ | (16,425 | ) | | $ | 975,155 | |
| Accrued liabilities | | 15,086 | | 8,118 | | 11 | | — | | 23,215 | | 20,921 | | | (2,351 | ) | | 41,785 | | | 23,752 | | 15,477 | | 709 | | — | | 39,938 | | 13,594 | | | (3,575 | ) | | 49,957 | |
| Other liabilities | | | (8,130 | ) | | 8,130 | | — | | — | | — | | — | | — | | — | | |
| Short-term debt | | — | | — | | — | | — | | — | | 29,000 | | — | | 29,000 | | |
| Current liabilities of discontinued operations | | — | | — | | — | | — | | — | | 935 | | — | | 935 | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total current liabilities | | 16,225 | | 400,533 | | 1,032 | | — | | 417,790 | | 58,171 | | | (13,803 | ) | | 462,158 | | | 32,720 | | 989,654 | | 2,933 | | — | | 1,025,307 | | 19,805 | | | (20,000 | ) | | 1,025,112 | |
| | | |
| Long-term debt | | — | | — | | — | | — | | — | | 341,914 | | — | | 341,914 | | | 288,451 | | 57,151 | | — | | — | | 345,602 | | 379,198 | | | (17,342 | ) | | 707,458 | |
| Non-current liabilities | | 41,693 | | 5,033 | | — | | — | | 46,726 | | 17,604 | | — | | 64,330 | | | 37,859 | | 30,795 | | — | | — | | 68,654 | | 12,349 | | — | | 81,003 | |
| Deferred income taxes | | 24,894 | | 44,597 | | — | | — | | 69,491 | | — | | — | | 69,491 | | | 119,127 | | 229 | | 278 | | — | | 119,634 | | — | | 4,951 | | 124,585 | |
| Distributions in excess of inv in HEP | | — | | 326,889 | | — | | — | | 326,889 | | — | | | (326,889 | ) | | — | | | — | | 314,970 | | — | | — | | 314,970 | | — | | | (314,970 | ) | | — | |
| Equity — Holly Corporation | | 542,399 | | 1,911,613 | | 77,645 | | | (1,989,258 | ) | | 542,399 | | 30,142 | | | (31,001 | ) | | 541,540 | | | 620,271 | | 2,010,510 | | 160,883 | | | (2,171,393 | ) | | 620,271 | | 230,423 | | | (231,655 | ) | | 619,039 | |
| Equity — Noncontrolling interest | | — | | — | | — | | 26,684 | | 26,684 | | 10,218 | | 357,890 | | 394,792 | | |
| Equity — noncontrolling interest | | | — | | — | | — | | 39,886 | | 39,886 | | — | | 548,856 | | 588,742 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total liabilities and equity | | $ | 625,211 | | $ | 2,688,665 | | $ | 78,677 | | $ | (1,962,574 | ) | | $ | 1,429,979 | | $ | 458,049 | | $ | (13,803 | ) | | $ | 1,874,225 | | | $ | 1,098,428 | | $ | 3,403,309 | | $ | 164,094 | | $ | (2,131,507 | ) | | $ | 2,534,324 | | $ | 641,775 | | $ | (30,160 | ) | | $ | 3,145,939 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
-108--105-
Condensed Consolidating Statement of Income
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Non- | | Holly Corp. | | Non-Guarantor | | | | | | | Non- | | Holly Corp. | | Non-Guarantor | | | | | |
| | | Guarantor | | Guarantor | | Before | | Non-Restricted | | | | | | | Guarantor | | Guarantor | | Before | | Non-Restricted | | | | | |
| | | Restricted | | Restricted | | Consolidation | | Subsidiaries | | | | | | | Restricted | | Restricted | | Consolidation | | Subsidiaries | | | | | |
| Year Ended December 31, 2009 | | Parent | | Subsidiaries | | Subsidiaries | | Eliminations | | of HEP(1) | | (HEP Segment) | | Eliminations | | Consolidated | | |
| Year Ended December 31, 2010 | | | Parent | | Subsidiaries | | Subsidiaries | | Eliminations | | of HEP | | (HEP Segment) | | Eliminations | | Consolidated | |
| | | (In thousands) | | | (In thousands) | |
| Sales and other revenues | | $ | 3,346 | | $ | 4,785,781 | | $ | 58 | | $ | — | | $ | 4,789,185 | | $ | 146,561 | | $ | (101,478 | ) | | $ | 4,834,268 | | | $ | 412 | | $ | 8,287,000 | | $ | 3 | | $ | — | | $ | 8,287,415 | | $ | 182,114 | | $ | (146,600 | ) | | $ | 8,322,929 | |
| | | | �� | |
| Operating costs and expenses: | | |
| Cost of products sold | | — | | 4,336,973 | | 900 | | — | | 4,337,873 | | — | | | (99,865 | ) | | 4,238,008 | | | — | | 7,510,172 | | 185 | | — | | 7,510,357 | | — | | | (143,208 | ) | | 7,367,149 | |
| Operating expenses | | — | | 313,361 | | — | | — | | 313,361 | | 44,003 | | | (509 | ) | | 356,855 | | | 2,411 | | 449,534 | | 32 | | — | | 451,977 | | 52,947 | | | (510 | ) | | 504,414 | |
| General and administrative expenses | | 51,648 | | 1,318 | | | (209 | ) | | — | | 52,757 | | 7,586 | | — | | 60,343 | | | 62,130 | | 990 | | — | | — | | 63,120 | | 7,719 | | — | | 70,839 | |
| Depreciation and amortization | | 3,928 | | 68,956 | | 1,268 | | — | | 74,152 | | 24,599 | | — | | 98,751 | | | 3,745 | | 85,517 | | | (113 | ) | | — | | 89,149 | | 29,062 | | | (682 | ) | | 117,529 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| Total operating costs and expenses | | 55,576 | | 4,720,608 | | 1,959 | | — | | 4,778,143 | | 76,188 | | | (100,374 | ) | | 4,753,957 | | | 68,286 | | 8,046,213 | | 104 | | — | | 8,114,603 | | 89,728 | | | (144,400 | ) | | 8,059,931 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| Income (loss) from operations | | | (52,230 | ) | | 65,173 | | | (1,901 | ) | | — | | 11,042 | | 70,373 | | | (1,104 | ) | | 80,311 | | | | (67,874 | ) | | 240,787 | | | (101 | ) | | — | | 172,812 | | 92,386 | | | (2,200 | ) | | 262,998 | |
| | | |
| Other income (expense): | | |
| Equity in earnings of subsidiaries | | 96,266 | | 31,643 | | 33,052 | | | (127,909 | ) | | 33,052 | | — | | | (33,052 | ) | | — | | |
| Equity in earnings of subsidiaries and joint venture | | | 265,367 | | 30,036 | | 30,069 | | | (295,403 | ) | | 30,069 | | 2,393 | | | (30,069 | ) | | 2,393 | |
| Interest income (expense) | | | (13,713 | ) | | 1,096 | | 44 | | — | | | (12,573 | ) | | | (21,490 | ) | | | (1,238 | ) | | | (35,301 | ) | | | (33,838 | ) | | | (5,456 | ) | | 45 | | — | | | (39,249 | ) | | | (36,245 | ) | | 2,466 | | | (73,028 | ) |
| Other income (expense) | | | (1,480 | ) | | 1,480 | | — | | — | | — | | 1,986 | | | (67 | ) | | 1,919 | | |
| Acquisition costs | | — | | | (3,126 | ) | | — | | — | | | (3,126 | ) | | | (1,356 | ) | | 1,356 | | | (3,126 | ) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| | | 81,073 | | 31,093 | | 33,096 | | | (127,909 | ) | | 17,353 | | | (20,860 | ) | | | (33,001 | ) | | | (36,508 | ) | | 231,529 | | 24,580 | | 30,114 | | | (295,403 | ) | | | (9,180 | ) | | | (33,852 | ) | | | (27,603 | ) | | | (70,635 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| Income (loss) from continuing operations before income taxes | | 28,843 | | 96,266 | | 31,195 | | | (127,909 | ) | | 28,395 | | 49,513 | | | (34,105 | ) | | 43,803 | | |
| Income from continuing operations before income taxes | | | 163,655 | | 265,367 | | 30,013 | | | (295,403 | ) | | 163,632 | | 58,534 | | | (29,803 | ) | | 192,363 | |
| | | |
| Income tax provision | | 10,295 | | — | | — | | — | | 10,295 | | 20 | | | (2,855 | ) | | 7,460 | | | 59,016 | | — | | — | | — | | 59,016 | | 296 | | — | | 59,312 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| Income from continuing operations | | 18,548 | | 96,266 | | 31,195 | | | (127,909 | ) | | 18,100 | | 49,493 | | | (31,250 | ) | | 36,343 | | |
| | | |
| Income from discontinued operations | | — | | — | | — | | — | | — | | 19,780 | | | (2,854 | ) | | 16,926 | | |
| | | | | | | | | | | | | | | | | | | |
| | | |
| Net Income | | 18,548 | | 96,266 | | 31,195 | | | (127,909 | ) | | 18,100 | | 69,273 | | | (34,104 | ) | | 53,269 | | |
| Net income | | | 104,639 | | 265,367 | | 30,013 | | | (295,403 | ) | | 104,616 | | 58,238 | | | (29,803 | ) | | 133,051 | |
| | | |
| Less net income attributable to noncontrolling interest | | — | | — | | — | | | (448 | ) | | | (448 | ) | | — | | 34,184 | | 33,736 | | | — | | — | | — | | 23 | | 23 | | — | | | (29,110 | ) | | | (29,087 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| Net income attributable to Holly Corporation stockholders | | $ | 18,548 | | $ | 96,266 | | $ | 31,195 | | $ | (127,461 | ) | | $ | 18,548 | | $ | 69,273 | | $ | (68,288 | ) | | $ | 19,533 | | | $ | 104,639 | | $ | 265,367 | | $ | 30,013 | | $ | (295,380 | ) | | $ | 104,639 | | $ | 58,238 | | $ | (58,913 | ) | | $ | 103,964 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Condensed Consolidating Statement of Income
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Non- | | Holly Corp. | | Non-Guarantor | | | | | | | Non- | | Holly Corp. | | Non-Guarantor | | | | | |
| | | Guarantor | | Guarantor | | Before | | Non-Restricted | | | | | | | Guarantor | | Guarantor | | Before | | Non-Restricted | | | | | |
| | | Restricted | | Restricted | | Consolidation | | Subsidiaries | | | | | | | Restricted | | Restricted | | Consolidation | | Subsidiaries | | | | | |
| Year Ended December 31, 2008 | | Parent | | Subsidiaries | | Subsidiaries | | Eliminations | | of HEP(1) | | (HEP Segment) | | Eliminations | | Consolidated | | |
| Year Ended December 31, 2009 | | | Parent | | Subsidiaries | | Subsidiaries | | Eliminations | | of HEP | | (HEP Segment) | | Eliminations | | Consolidated | |
| | | (In thousands) | | | (In thousands) | |
| Sales and other revenues | | $ | 1,831 | | $ | 5,838,244 | | $ | 15 | | $ | — | | $ | 5,840,090 | | $ | 94,439 | | $ | (74,172 | ) | | $ | 5,860,357 | | | $ | 3,346 | | $ | 4,785,781 | | $ | 58 | | $ | — | | $ | 4,789,185 | | $ | 146,561 | | $ | (101,478 | ) | | $ | 4,834,268 | |
| | | |
| Operating costs and expenses: | | |
| Cost of products sold | | 23 | | 5,354,561 | | — | | — | | 5,354,584 | | — | | | (73,885 | ) | | 5,280,699 | | | — | | 4,336,973 | | 900 | | — | | 4,337,873 | | — | | | (99,865 | ) | | 4,238,008 | |
| Operating expenses | | 17 | | 231,995 | | 627 | | — | | 232,639 | | 33,353 | | | (287 | ) | | 265,705 | | | — | | 313,361 | | — | | — | | 313,361 | | 44,003 | | | (509 | ) | | 356,855 | |
| General and administrative expenses | | 46,230 | | 3,434 | | — | | — | | 49,664 | | 5,614 | | — | | 55,278 | | | 51,648 | | 1,318 | | | (209 | ) | | — | | 52,757 | | 7,586 | | — | | 60,343 | |
| Depreciation and amortization | | 3,627 | | 40,299 | | 679 | | — | | 44,605 | | 18,390 | | — | | 62,995 | | | 3,928 | | 68,956 | | 1,268 | | — | | 74,152 | | 24,599 | | — | | 98,751 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| Total operating costs and expenses | | 49,897 | | 5,630,289 | | 1,306 | | — | | 5,681,492 | | 57,357 | | | (74,172 | ) | | 5,664,677 | | | 55,576 | | 4,720,608 | | 1,959 | | — | | 4,778,143 | | 76,188 | | | (100,374 | ) | | 4,753,957 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| Income (loss) from operations | | | (48,066 | ) | | 207,955 | | | (1,291 | ) | | — | | 158,598 | | 37,082 | | — | | 195,680 | | | | (52,230 | ) | | 65,173 | | | (1,901 | ) | | — | | 11,042 | | 70,373 | | | (1,104 | ) | | 80,311 | |
| | | |
| Other income (expense): | | |
| Equity in earnings of subsidiaries | | 257,587 | | 15,700 | | 16,633 | | | (273,287 | ) | | 16,633 | | — | | | (13,643 | ) | | 2,990 | | | 96,266 | | 31,643 | | 33,052 | | | (127,909 | ) | | 33,052 | | — | | | (33,052 | ) | | — | |
| Interest income (expense) | | | (23,875 | ) | | 31,698 | | 507 | | — | | 8,330 | | | (21,488 | ) | | — | | | (13,158 | ) | | | (13,713 | ) | | 1,096 | | 44 | | — | | | (12,573 | ) | | | (21,490 | ) | | | (1,238 | ) | | | (35,301 | ) |
| Net gain (loss) | | — | | 2,234 | | — | | — | | 2,234 | | — | | — | | 2,234 | | |
| Other income (expense) | | | | (1,480 | ) | | 1,480 | | — | | — | | — | | 1,986 | | | (67 | ) | | 1,919 | |
| Acquisition costs | | | — | | | (3,126 | ) | | — | | — | | | (3,126 | ) | | | (1,356 | ) | | 1,356 | | | (3,126 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| | | 233,712 | | 49,632 | | 17,140 | | | (273,287 | ) | | 27,197 | | | (21,488 | ) | | | (13,643 | ) | | | (7,934 | ) | | 81,073 | | 31,093 | | 33,096 | | | (127,909 | ) | | 17,353 | | | (20,860 | ) | | | (33,001 | ) | | | (36,508 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| Income (loss) from continuing operations before income taxes | | 185,646 | | 257,587 | | 15,849 | | | (273,287 | ) | | 185,795 | | 15,594 | | | (13,643 | ) | | 187,746 | | | 28,843 | | 96,266 | | 31,195 | | | (127,909 | ) | | 28,395 | | 49,513 | | | (34,105 | ) | | 43,803 | |
| | | |
| Income tax provision | | 64,537 | | — | | — | | — | | 64,537 | | 238 | | | (747 | ) | | 64,028 | | | 10,295 | | — | | — | | — | | 10,295 | | 20 | | | (2,855 | ) | | 7,460 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| Income from continuing operations | | 121,109 | | 257,587 | | 15,849 | | | (273,287 | ) | | 121,258 | | 15,356 | | | (12,896 | ) | | 123,718 | | | 18,548 | | 96,266 | | 31,195 | | | (127,909 | ) | | 18,100 | | 49,493 | | | (31,250 | ) | | 36,343 | |
| | | |
| Income from discontinued operations | | — | | — | | — | | — | | — | | 3,665 | | | (747 | ) | | 2,918 | | | — | | — | | — | | — | | — | | 19,780 | | | (2,854 | ) | | 16,926 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| Net Income | | 121,109 | | 257,587 | | 15,849 | | | (273,287 | ) | | 121,258 | | 19,021 | | | (13,643 | ) | | 126,636 | | |
| Net income | | | 18,548 | | 96,266 | | 31,195 | | | (127,909 | ) | | 18,100 | | 69,273 | | | (34,104 | ) | | 53,269 | |
| | | |
| Less net income attributable to noncontrolling interest | | — | | — | | — | | | (149 | ) | | | (149 | ) | | — | | | (6,227 | ) | | | (6,078 | ) | | — | | — | | — | | 448 | | 448 | | — | | | (34,184 | ) | | | (33,736 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| Net income attributable to Holly Corporation stockholders | | $ | 121,109 | | $ | 257,587 | | $ | 15,849 | | $ | (273,138 | ) | | $ | 121,407 | | $ | 19,021 | | $ | (19,870 | ) | | $ | 120,558 | | | $ | 18,548 | | $ | 96,266 | | $ | 31,195 | | $ | (127,461 | ) | | $ | 18,548 | | $ | 69,273 | | $ | (68,288 | ) | | $ | 19,533 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
-109--106-
Condensed Consolidating Statement of Income
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Non- | | Holly Corp. | | Non-Guarantor | | | | | | | Non- | | Holly Corp. | | Non-Guarantor | | | | | |
| | | Guarantor | | Guarantor | | Before | | Non-Restricted | | | | | | | Guarantor | | Guarantor | | Before | | Non-Restricted | | | | | |
| | | Restricted | | Restricted | | Consolidation | | Subsidiaries | | | | | | | Restricted | | Restricted | | Consolidation | | Subsidiaries | | | | | |
| Year Ended December 31, 2007 | | Parent | | Subsidiaries | | Subsidiaries | | Eliminations | | of HEP(1) | | (HEP Segment) | | Eliminations | | Consolidated | | |
| Year Ended December 31, 2008 | | | Parent | | Subsidiaries | | Subsidiaries | | Eliminations | | of HEP | | (HEP Segment) | | Eliminations | | Consolidated | |
| | | (In thousands) | | | (In thousands) | |
| Sales and other revenues | | $ | 13 | | $ | 4,791,729 | | $ | — | | $ | — | | $ | 4,791,742 | | $ | — | | $ | — | | $ | 4,791,742 | | | $ | 1,831 | | $ | 5,838,244 | | $ | 15 | | $ | — | | $ | 5,840,090 | | $ | 94,439 | | $ | (74,172 | ) | | $ | 5,860,357 | |
| | | |
| Operating costs and expenses: | | |
| Cost of products sold | | — | | 3,999,931 | | 3,557 | | — | | 4,003,488 | | — | | — | | 4,003,488 | | | 23 | | 5,354,561 | | — | | — | | 5,354,584 | | — | | | (73,885 | ) | | 5,280,699 | |
| Operating expenses | | 12 | | 209,192 | | 77 | | — | | 209,281 | | — | | — | | 209,281 | | | 17 | | 231,995 | | 627 | | — | | 232,639 | | 33,353 | | | (287 | ) | | 265,705 | |
| General and administrative expenses | | 66,305 | | 2,880 | | — | | — | | 69,185 | | — | | — | | 69,185 | | | 46,230 | | 3,434 | | — | | — | | 49,664 | | 5,614 | | — | | 55,278 | |
| Depreciation and amortization | | 2,245 | | 41,211 | | — | | — | | 43,456 | | — | | — | | 43,456 | | | 3,627 | | 40,299 | | 679 | | — | | 44,605 | | 18,390 | | — | | 62,995 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| Total operating costs and expenses | | 68,562 | | 4,253,214 | | 3,634 | | — | | 4,325,410 | | — | | — | | 4,325,410 | | | 49,897 | | 5,630,289 | | 1,306 | | — | | 5,681,492 | | 57,357 | | | (74,172 | ) | | 5,664,677 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| Income (loss) from operations | | | (68,549 | ) | | 538,515 | | | (3,634 | ) | | — | | 466,332 | | — | | — | | 466,332 | | | | (48,066 | ) | | 207,955 | | | (1,291 | ) | | — | | 158,598 | | 37,082 | | — | | 195,680 | |
| | | |
| Other income (expense): | | |
| Equity in earnings of subsidiaries | | 653,060 | | 15,233 | | 19,109 | | | (668,293 | ) | | 19,109 | | — | | — | | 19,109 | | | 257,587 | | 15,700 | | 16,633 | | | (273,287 | ) | | 16,633 | | — | | | (13,643 | ) | | 2,990 | |
| Interest income (expense) | | | (85,067 | ) | | 99,312 | | | (242 | ) | | — | | 14,003 | | — | | — | | 14,003 | | | | (23,875 | ) | | 31,698 | | 507 | | — | | 8,330 | | | (21,488 | ) | | — | | | (13,158 | ) |
| Net gain (loss) | | | — | | 2,234 | | — | | — | | 2,234 | | — | | — | | 2,234 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| | | 567,993 | | 114,545 | | 18,867 | | | (668,293 | ) | | 33,112 | | — | | — | | 33,112 | | | 233,712 | | 49,632 | | 17,140 | | | (273,287 | ) | | 27,197 | | | (21,488 | ) | | | (13,643 | ) | | | (7,934 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| Income (loss) from continuing operations before income taxes | | 499,444 | | 653,060 | | 15,233 | | | (668,293 | ) | | 499,444 | | — | | — | | 499,444 | | | 185,646 | | 257,587 | | 15,849 | | | (273,287 | ) | | 185,795 | | 15,594 | | | (13,643 | ) | | 187,746 | |
| | | |
| Income tax provision | | 165,316 | | — | | — | | — | | 165,316 | | — | | — | | 165,316 | | | 64,537 | | — | | — | | — | | 64,537 | | 238 | | | (747 | ) | | 64,028 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| Income from continuing operations | | | 121,109 | | 257,587 | | 15,849 | | | (273,287 | ) | | 121,258 | | 15,356 | | | (12,896 | ) | | 123,718 | |
| | | |
| Income from discontinued operations | | | — | | — | | — | | — | | — | | 3,665 | | | (747 | ) | | 2,918 | |
| | | | | | | | | | | | | | | | | | | |
| | | |
| Net income | | | 121,109 | | 257,587 | | 15,849 | | | (273,287 | ) | | 121,258 | | 19,021 | | | (13,643 | ) | | 126,636 | |
| | | |
| Less net income attributable to noncontrolling interest | | | — | | — | | — | | | 149 | | | | 149 | | | — | | | (6,227 | ) | | | (6,078 | ) |
| | | | | | | | | | | | | | | | | | | |
| | | |
| Net income attributable to Holly Corporation stockholders | | $ | 334,128 | | $ | 653,060 | | $ | 15,233 | | $ | (668,293 | ) | | $ | 334,128 | | $ | — | | $ | — | | $ | 334,128 | | | $ | 121,109 | | $ | 257,587 | | $ | 15,849 | | $ | (273,138 | ) | | $ | 121,407 | | $ | 19,021 | | $ | (19,870 | ) | | $ | 120,558 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Condensed Consolidating Statement of Cash Flows
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Non- | | | Holly Corp. | | | Non-Guarantor | | | | | | | |
| | | | | | | Guarantor | | | Guarantor | | | Before | | | Non-Restricted | | | | | | | |
| | | | | | | Restricted | | | Restricted | | | Consolidation | | | Subsidiaries | | | | | | | |
| Year Ended December 31, 2010 | | Parent | | | Subsidiaries | | | Subsidiaries | | | of HEP | | | (HEP Segment) | | | Eliminations | | | Consolidated | |
| | | (In thousands) | |
| Cash flows from operating activities | | $ | 140,934 | | | $ | 74,234 | | | $ | 1,268 | | | $ | 216,436 | | | $ | 103,168 | | | $ | (36,349 | ) | | $ | 283,255 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Cash flows from investing activities | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Additions to properties, plants and equipment — Holly | | | (1,573 | ) | | | (105,434 | ) | | | (81,122 | ) | | | (188,129 | ) | | | — | | | | — | | | | (188,129 | ) |
| Additions to properties, plants and equipment — HEP | | | — | | | | — | | | | — | | | | — | | | | (60,629 | ) | | | 35,526 | | | | (25,103 | ) |
| Proceeds from sale of assets | | | — | | | | 39,040 | | | | — | | | | 39,040 | | | | — | | | | (39,040 | ) | | | — | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | (1,573 | ) | | | (66,394 | ) | | | (81,122 | ) | | | (149,089 | ) | | | (60,629 | ) | | | (3,514 | ) | | | (213,232 | ) |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Cash flows from financing activities | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net repayments under credit agreements — HEP | | | — | | | | — | | | | — | | | | — | | | | (47,000 | ) | | | — | | | | (47,000 | ) |
| Proceeds from issuance of senior notes — HEP | | | — | | | | — | | | | — | | | | — | | | | 147,540 | | | | — | | | | 147,540 | |
| Repayments under financing obligation — Holly | | | — | | | | (1,444 | ) | | | — | | | | (1,444 | ) | | | — | | | | 416 | | | | (1,028 | ) |
| Purchase of treasury stock | | | (1,368 | ) | | | — | | | | — | | | | (1,368 | ) | | | — | | | | — | | | | (1,368 | ) |
| Contribution from joint venture partner | | | — | | | | (57,000 | ) | | | 80,500 | | | | 23,500 | | | | — | | | | — | | | | 23,500 | |
| Dividends | | | (31,868 | ) | | | — | | | | — | | | | (31,868 | ) | | | — | | | | — | | | | (31,868 | ) |
| Purchase price in excess of transferred basis in assets | | | — | | | | 54,046 | | | | — | | | | 54,046 | | | | (57,560 | ) | | | 3,514 | | | | — | |
| Distributions to noncontrolling interest | | | — | | | | — | | | | — | | | | — | | | | (84,426 | ) | | | 35,933 | | | | (48,493 | ) |
| Excess tax expense from equity based compensation | | | (1,094 | ) | | | — | | | | — | | | | (1,094 | ) | | | — | | | | — | | | | (1,094 | ) |
| Deferred financing costs | | | (2,627 | ) | | | — | | | | — | | | | (2,627 | ) | | | (494 | ) | | | — | | | | (3,121 | ) |
| Purchase of units for HEP restricted grants | | | — | | | | — | | | | — | | | | — | | | | (2,704 | ) | | | — | | | | (2,704 | ) |
| Other | | | 118 | | | | — | | | | — | | | | 118 | | | | — | | | | — | | | | 118 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | (36,839 | ) | | | (4,398 | ) | | | 80,500 | | | | 39,263 | | | | (44,644 | ) | | | 39,863 | | | | 34,482 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Increase (decrease) for the period | | | 102,522 | | | | 3,442 | | | | 646 | | | | 106,610 | | | | (2,105 | ) | | | — | | | | 104,505 | |
| Beginning of period | | | 127,560 | | | | (12,477 | ) | | | 7,005 | | | | 122,088 | | | | 2,508 | | | | — | | | | 124,596 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| End of period | | $ | 230,082 | | | $ | (9,035 | ) | | $ | 7,651 | | | $ | 228,698 | | | $ | 403 | | | $ | — | | | $ | 229,101 | |
| | | | | | | | | | | | | | | | | | | | | | |
-110--107-
Condensed Consolidating Statement of Cash Flows
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Non- | | Holly Corp. | | Non-Guarantor | | | | | | | Non- | | Holly Corp. | | Non-Guarantor | | | | | |
| | | Guarantor | | Guarantor | | Before | | Non-Restricted | | | | | | | Guarantor | | Guarantor | | Before | | Non-Restricted | | | | | |
| | | Restricted | | Restricted | | Consolidation | | Subsidiaries | | | | | | | Restricted | | Restricted | | Consolidation | | Subsidiaries | | | | | |
| Year Ended December 31, 2009 | | Parent | | Subsidiaries | | Subsidiaries | | Eliminations | | of HEP(1) | | (HEP Segment) | | Eliminations | | Consolidated | | | Parent | | Subsidiaries | | Subsidiaries | | of HEP | | (HEP Segment) | | Eliminations | | Consolidated | |
| | | (In thousands) | | | (In thousands) | |
| Cash flows from operating activities | | $ | (277,912 | ) | | $ | 448,020 | | $ | 308 | | $ | — | | $ | 170,416 | | $ | 68,195 | | $ | (27,066 | ) | | $ | 211,545 | | | $ | (277,912 | ) | | $ | 448,020 | | $ | 308 | | $ | 170,416 | | $ | 68,195 | | $ | (27,066 | ) | | $ | 211,545 | |
| | | |
| Cash flows from investing activities | | |
| Additions to properties, plants and equipment — Holly | | | (2,904 | ) | | | (215,343 | ) | | | (51,305 | ) | | — | | | (269,552 | ) | | | (25,665 | ) | | — | | | (295,217 | ) | | | (2,904 | ) | | | (215,343 | ) | | | (51,305 | ) | | | (269,552 | ) | | | (25,665 | ) | | — | | | (295,217 | ) |
| Additions to properties, plants and equipment — HEP | | — | | — | | — | | — | | — | | | (128,079 | ) | | 95,080 | | | (32,999 | ) | | — | | — | | — | | — | | | (128,079 | ) | | 95,080 | | | (32,999 | ) |
| Purchases of marketable securities | | | (175,892 | ) | | — | | — | | — | | | (175,892 | ) | | — | | — | | | (175,892 | ) | | | (175,892 | ) | | — | | — | | | (175,892 | ) | | — | | — | | | (175,892 | ) |
| Sales and maturities of marketable securities | | 230,281 | | — | | — | | — | | 230,281 | | — | | — | | 230,281 | | | 230,281 | | — | | — | | 230,281 | | — | | — | | 230,281 | |
| Acquisition of Tulsa Refinery — Holly Corporation | | 74,000 | | | (341,141 | ) | | — | | — | | | (267,141 | ) | | — | | — | | | (267,141 | ) | |
| Acquisition of Tulsa Refineries — Holly | | | 74,000 | | | (341,141 | ) | | — | | | (267,141 | ) | | — | | — | | | (267,141 | ) |
| Investment in SLC Pipeline | | — | | — | | — | | — | | — | | | (25,500 | ) | | — | | | (25,500 | ) | | — | | — | | — | | — | | | (25,500 | ) | | — | | | (25,500 | ) |
| Proceeds from the sale of assets | | — | | 83,280 | | — | | — | | 83,280 | | — | | | (83,280 | ) | | — | | | — | | 83,280 | | — | | 83,280 | | — | | | (83,280 | ) | | — | |
| Proceeds from sale of RGPC | | — | | — | | — | | — | | — | | 31,865 | | — | | 31,865 | | |
| Proceeds from sale of Rio Grande | | | — | | — | | — | | — | | 31,865 | | — | | 31,865 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| Net cash provided by (used for) investing activities | | 125,485 | | | (473,204 | ) | | | (51,305 | ) | | — | | | (399,024 | ) | | | (147,379 | ) | | 11,800 | | | (534,603 | ) | | 125,485 | | | (473,204 | ) | | | (51,305 | ) | | | (399,024 | ) | | | (147,379 | ) | | 11,800 | | | (534,603 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| Cash flows from financing activities | | |
| Net borrowings under credit agreement | | — | | — | | — | | — | | — | | 6,000 | | — | | 6,000 | | | — | | — | | — | | — | | 6,000 | | — | | 6,000 | |
| Issuance of common units net of underwriter’s discount | | — | | — | | — | | — | | — | | 133,035 | | — | | 133,035 | | |
| Proceeds from issuance of common units — HEP | | | — | | — | | — | | — | | 133,035 | | — | | 133,035 | |
| Dividends | | | (30,123 | ) | | — | | — | | — | | | (30,123 | ) | | — | | — | | | (30,123 | ) | | | (30,123 | ) | | — | | — | | | (30,123 | ) | | — | | — | | | (30,123 | ) |
| Distributions to noncontrolling interest | | — | | — | | — | | — | | — | | | (62,688 | ) | | 29,488 | | | (33,200 | ) | | — | | — | | — | | — | | | (62,688 | ) | | 29,488 | | | (33,200 | ) |
| Purchase of treasury stock | | | (1,214 | ) | | — | | — | | — | | | (1,214 | ) | | — | | — | | | (1,214 | ) | | | (1,214 | ) | | — | | — | | | (1,214 | ) | | — | | — | | | (1,214 | ) |
| Contribution from joint venture partner | | — | | | (39,450 | ) | | 54,600 | | — | | 15,150 | | — | | — | | 15,150 | | | — | | | (39,450 | ) | | 54,600 | | 15,150 | | — | | — | | 15,150 | |
| Excess tax benefit from equity based compensation | | | (1,209 | ) | | — | | — | | — | | | (1,209 | ) | | — | | — | | | (1,209 | ) | | | (1,209 | ) | | — | | — | | | (1,209 | ) | | — | | — | | | (1,209 | ) |
| Deferred financing costs | | | (8,842 | ) | | — | | — | | — | | | (8,842 | ) | | — | | — | | | (8,842 | ) | | | (8,842 | ) | | — | | — | | | (8,842 | ) | | — | | — | | | (8,842 | ) |
| Proceeds from issuance of notes, net of underwriter discount — HOC | | 287,925 | | — | | — | | — | | 287,925 | | — | | — | | 287,925 | | |
| Proceeds from issuance of senior notes — Holly | | | 287,925 | | — | | — | | 287,925 | | — | | — | | 287,925 | |
| Proceeds from Plains financing transaction | | — | | 40,000 | | — | | — | | 40,000 | | — | | — | | 40,000 | | | — | | 40,000 | | — | | 40,000 | | — | | — | | 40,000 | |
| Other financing activities, net | | 134 | | 13,339 | | — | | — | | 13,473 | | 76 | | | (14,222 | ) | | | (673 | ) | | 134 | | 13,339 | | — | | 13,473 | | 76 | | | (14,222 | ) | | | (673 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| Net cash provided by financing activities | | 246,671 | | 13,889 | | 54,600 | | — | | 315,160 | | 76,423 | | 15,266 | | 406,849 | | | 246,671 | | 13,889 | | 54,600 | | 315,160 | | 76,423 | | 15,266 | | 406,849 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| Cash and cash equivalents | | |
| Increase (decrease) for the period | | 94,244 | | | (11,295 | ) | | 3,603 | | — | | 86,552 | | | (2,761 | ) | | — | | 83,791 | | | 94,244 | | | (11,295 | ) | | 3,603 | | 86,552 | | | (2,761 | ) | | — | | 83,791 | |
| Beginning of period | | 33,316 | | | (1,182 | ) | | 3,402 | | — | | 35,536 | | 5,269 | | — | | | 40,805 | (1) | | 33,316 | | | (1,182 | ) | | 3,402 | | 35,536 | | 5,269 | | — | | 40,805 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| End of period | | $ | 127,560 | | $ | (12,477 | ) | | $ | 7,005 | | $ | — | | $ | 122,088 | | $ | 2,508 | | $ | — | | $ | 124,596 | | | $ | 127,560 | | $ | (12,477 | ) | | $ | 7,005 | | $ | 122,088 | | $ | 2,508 | | $ | — | | $ | 124,596 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| | |
(1) | | Includes $1,561 in cash classified as current assets of discontinued operations at December 31, 2008. |
-111-
Condensed Consolidating Statement of Cash Flows
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Non- | | Holly Corp. | | Non-Guarantor | | | | | | | Non- | | Holly Corp. | | Non-Guarantor | | | | | |
| | | Guarantor | | Guarantor | | Before | | Non-Restricted | | | | | | | Guarantor | | Guarantor | | Before | | Non-Restricted | | | | | |
| | | Restricted | | Restricted | | Consolidation | | Subsidiaries | | | | | | | Restricted | | Restricted | | Consolidation | | Subsidiaries | | | | | |
| Year Ended December 31, 2008 | | Parent | | Subsidiaries | | Subsidiaries | | Eliminations | | of HEP(1) | | (HEP Segment) | | Eliminations | | Consolidated | | | Parent | | Subsidiaries | | Subsidiaries | | of HEP | | (HEP Segment) | | Eliminations | | Consolidated | |
| | | (In thousands) | | | (In thousands) | |
| Cash flows from operating activities | | $ | (63,480 | ) | | $ | 192,299 | | $ | 364 | | $ | — | | $ | 129,183 | | $ | 46,091 | | $ | (19,784 | ) | | $ | 155,490 | | | $ | (63,480 | ) | | $ | 192,299 | | $ | 364 | | $ | 129,183 | | $ | 46,091 | | $ | (19,784 | ) | | $ | 155,490 | |
| | | |
| Cash flows from investing activities | | |
| Additions to properties, plants and equipment — Holly | | | (2,515 | ) | | | (295,937 | ) | | | (85,290 | ) | | — | | | (383,742 | ) | | — | | — | | | (383,742 | ) | | | (2,515 | ) | | | (295,937 | ) | | | (85,290 | ) | | | (383,742 | ) | | — | | — | | | (383,742 | ) |
| Additions to properties, plants and equipment — HEP | | — | | — | | — | | — | | — | | | (34,317 | ) | | — | | | (34,317 | ) | | — | | — | | — | | — | | | (34,317 | ) | | — | | | (34,317 | ) |
| Purchases of marketable securities | | | (769,142 | ) | | — | | — | | — | | | (769,142 | ) | | — | | — | | | (769,142 | ) | | | (769,142 | ) | | — | | — | | | (769,142 | ) | | — | | — | | | (769,142 | ) |
| Sales and maturities of marketable securities | | 945,461 | | — | | — | | — | | 945,461 | | — | | — | | 945,461 | | | 945,461 | | — | | — | | 945,461 | | — | | — | | 945,461 | |
| Proceeds from sale of crude pipeline and tankage assets | | — | | 171,000 | | — | | — | | 171,000 | | — | | — | | 171,000 | | | — | | 171,000 | | — | | 171,000 | | — | | — | | 171,000 | |
| Proceeds from sale of HPI | | — | | 5,958 | | — | | — | | 5,958 | | — | | — | | 5,958 | | | — | | 5,958 | | — | | 5,958 | | — | | — | | 5,958 | |
| Increase in cash due to consolidation of HEP | | — | | — | | — | | — | | — | | — | | 7,295 | | 7,295 | | | — | | — | | — | | — | | — | | 7,295 | | 7,295 | |
| Investment in HEP | | — | | | (290 | ) | | — | | — | | | (290 | ) | | — | | — | | | (290 | ) | | — | | | (290 | ) | | — | | | (290 | ) | | — | | — | | | (290 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| Net cash provided by (used for) investing activities | | 173,804 | | | (119,269 | ) | | | (85,290 | ) | | — | | | (30,755 | ) | | | (34,317 | ) | | 7,295 | | | (57,777 | ) | | 173,804 | | | (119,269 | ) | | | (85,290 | ) | | | (30,755 | ) | | | (34,317 | ) | | 7,295 | | | (57,777 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| Cash flows from financing activities | | |
| Net borrowings under credit agreement | | — | | — | | — | | — | | — | | 29,000 | | — | | 29,000 | | | — | | — | | — | | — | | 29,000 | | — | | 29,000 | |
| Issuance of common stock upon exercise of options | | 1,005 | | — | | — | | — | | 1,005 | | — | | — | | 1,005 | | | 1,005 | | — | | — | | 1,005 | | — | | — | | 1,005 | |
| Dividends | | | (29,054 | ) | | — | | — | | — | | | (29,054 | ) | | — | | | (10 | ) | | | (29,064 | ) | | | (29,054 | ) | | — | | — | | | (29,054 | ) | | — | | | (10 | ) | | | (29,064 | ) |
| Distributions to noncontrolling interest | | — | | — | | — | | — | | — | | | (41,603 | ) | | 19,505 | | | (22,098 | ) | | — | | — | | — | | — | | | (41,603 | ) | | 19,505 | | | (22,098 | ) |
| Purchase of treasury stock | | | (151,106 | ) | | — | | — | | — | | | (151,106 | ) | | — | | — | | | (151,106 | ) | | | (151,106 | ) | | — | | — | | | (151,106 | ) | | — | | — | | | (151,106 | ) |
| Contribution from joint venture partner | | | (1,500 | ) | | | (55,500 | ) | | 74,000 | | — | | 17,000 | | — | | — | | 17,000 | | | | (1,500 | ) | | | (55,500 | ) | | 74,000 | | 17,000 | | — | | — | | 17,000 | |
| Excess tax benefit from equity based compensation | | 5,694 | | — | | — | | — | | 5,694 | | — | | — | | 5,694 | | | 5,694 | | — | | — | | 5,694 | | — | | — | | 5,694 | |
| Deferred financing costs | | | (800 | ) | | — | | — | | | (800 | ) | | | (113 | ) | | — | | | (913 | ) | | | (800 | ) | | — | | | (800 | ) | | | (113 | ) | | — | | | (913 | ) |
| Purchase of units for restricted grants | | — | | — | | — | | — | | — | | | (795 | ) | | — | | | (795 | ) | | — | | — | | — | | — | | | (795 | ) | | — | | | (795 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| Net cash provided by (used for) financing activities | | | (174,961 | ) | | | (56,300 | ) | | 74,000 | | — | | | (157,261 | ) | | | (13,511 | ) | | 19,495 | | | (151,277 | ) | | | (174,961 | ) | | | (56,300 | ) | | 74,000 | | | (157,261 | ) | | | (13,511 | ) | | 19,495 | | | (151,277 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| Cash and cash equivalents | | |
| Increase (decrease) for the period | | | (64,637 | ) | | 16,730 | | | (10,926 | ) | | — | | | (58,833 | ) | | | (1,737 | ) | | 7,006 | | | (53,564 | ) | | | (64,637 | ) | | 16,730 | | | (10,926 | ) | | | (58,833 | ) | | | (1,737 | ) | | 7,006 | | | (53,564 | ) |
| Beginning of period | | 97,953 | | | (17,912 | ) | | 14,328 | | — | | 94,369 | | 7,006 | | | (7,006 | ) | | 94,369 | | | 97,953 | | | (17,912 | ) | | 14,328 | | 94,369 | | 7,006 | | | (7,006 | ) | | 94,369 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| End of period | | $ | 33,316 | | $ | (1,182 | ) | | $ | 3,402 | | $ | — | | $ | 35,536 | | $ | 5,269 | | $ | — | | $ | 40,805 | (1) | | $ | 33,316 | | $ | (1,182 | ) | | $ | 3,402 | | $ | 35,536 | | $ | 5,269 | | $ | — | | $ | 40,805 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| | |
(1) | | Includes $1,561 in cash classified as current assets of discontinued operations at December 31, 2008. |
-112--108-
Condensed Consolidating Statement of Cash Flows
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Non- | | | | | | | Holly Corp. | | | Non-Guarantor | | | | | | | |
| | | | | | | Guarantor | | | Guarantor | | | | | | | Before | | | Non-Restricted | | | | | | | |
| | | | | | | Restricted | | | Restricted | | | | | | | Consolidation | | | Subsidiaries | | | | | | | |
| Year Ended December 31, 2007 | | Parent | | | Subsidiaries | | | Subsidiaries | | | Eliminations | | | of HEP(1) | | | (HEP Segment) | | | Eliminations | | | Consolidated | |
| | | (In thousands) | |
| Cash flows from operating activities | | $ | 283,276 | | | $ | 144,406 | | | $ | (4,945 | ) | | $ | — | | | $ | 422,737 | | | $ | — | | | $ | — | | | $ | 422,737 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Cash flows from investing activities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Additions to properties, plants and equipment — Holly | | | (9,810 | ) | | | (170,762 | ) | | | 19,314 | | | | — | | | | (161,258 | ) | | | — | | | | — | | | | (161,258 | ) |
| Purchases of marketable securities | | | (641,144 | ) | | | — | | | | — | | | | — | | | | (641,144 | ) | | | — | | | | — | | | | (641,144 | ) |
| Sales and maturities of marketable securities | | | 509,345 | | | | — | | | | — | | | | — | | | | 509,345 | | | | — | | | | — | | | | 509,345 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net cash provided by (used for) investing activities | | | (141,609 | ) | | | (170,762 | ) | | | 19,314 | | | | — | | | | (293,057 | ) | | | — | | | | — | | | | (293,057 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Cash flows from financing activities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Dividends | | | (23,208 | ) | | | — | | | | — | | | | — | | | | (23,208 | ) | | | — | | | | — | | | | (23,208 | ) |
| Purchase of treasury stock | | | (207,196 | ) | | | — | | | | — | | | | — | | | | (207,196 | ) | | | — | | | | — | | | | (207,196 | ) |
| Contribution from joint venture partner | | | — | | | | 8,333 | | | | — | | | | — | | | | 8,333 | | | | — | | | | — | | | | 8,333 | |
| Excess tax benefit from equity based compensation | | | 30,355 | | | | — | | | | — | | | | — | | | | 30,355 | | | | — | | | | — | | | | 30,355 | |
| Issuance of common stock upon exercise of options | | | 2,288 | | | | — | | | | — | | | | — | | | | 2,288 | | | | — | | | | — | | | | 2,288 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net cash provided by (used for) financing activities | | | (197,761 | ) | | | 8,333 | | | | — | | | | — | | | | (189,428 | ) | | | — | | | | — | | | | (189,428 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Increase (decrease) for the period | | | (56,094 | ) | | | (18,023 | ) | | | 14,369 | | | | — | | | | (59,748 | ) | | | — | | | | — | | | | (59,748 | ) |
| Beginning of period | | | 154,047 | | | | 111 | | | | (41 | ) | | | — | | | | 154,117 | | | | — | | | | — | | | | 154,117 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| End of period | | $ | 97,953 | | | $ | (17,912 | ) | | $ | 14,328 | | | $ | — | | | $ | 94,369 | | | $ | — | | | $ | — | | | $ | 94,369 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
(1) | | Includes Holly Corporation’s investment in HEP based on the equity method of accounting. |
NOTE 21:22: Significant Customers
All revenues wereare domestic revenues, except for sales of gasoline and diesel fuel for export into Mexico by the Refining segment. The export sales were to an affiliate of PEMEX and accounted for $114.6$323.2 million (2%(4%) of our revenues in 2010, $188.6 million (4%) of our revenues in 2009 and $325.4 million (6%) of our revenues in 2008 and $2002008. In 2010, Sinclair accounted for $1,616 million (5%)or 19% of revenues in 2007. In 2009, 2008 and 2007, we hadour revenues. We have several other significant customers, none of which accounted for more than 10% of our revenues.revenues in 2009 and 2008.
NOTE 22:23: Quarterly Information (Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | First | | Second | | Third | | Fourth | | | | | First | | Second | | Third | | Fourth | | |
| | | Quarter | | Quarter | | Quarter | | Quarter | | Year | | | Quarter | | Quarter | | Quarter | | Quarter | | Year |
| | | (In thousands, except per share data) | | | (In thousands, except per share data) |
Year Ended December 31, 2010 | | |
| Sales and other revenues | | | $ | 1,874,290 | | $ | 2,145,860 | | $ | 2,090,988 | | $ | 2,211,791 | | $ | 8,322,929 | |
| Operating costs and expenses | | | $ | 1,897,034 | | $ | 2,013,696 | | $ | 1,983,370 | | $ | 2,165,831 | | $ | 8,059,931 | |
| Income (loss) from operations | | | $ | (22,744 | ) | | $ | 132,164 | | $ | 107,618 | | $ | 45,960 | | $ | 262,998 | |
| Income (loss) from continuing operations before income taxes | | | $ | (39,926 | ) | | $ | 112,320 | | $ | 90,884 | | $ | 29,085 | | $ | 192,363 | |
| Net income (loss) attributable to Holly Corporation stockholders | | | $ | (28,094 | ) | | $ | 66,162 | | $ | 51,177 | | $ | 14,719 | | $ | 103,964 | |
| Net income (loss) per share attributable to Holly Corporation stockholders—basic | | | $ | (0.53 | ) | | $ | 1.24 | | $ | 0.96 | | $ | 0.28 | | $ | 1.95 | |
| Net income (loss) per share attributable to Holly Corporation stockholders—diluted | | | $ | (0.53 | ) | | $ | 1.24 | | $ | 0.96 | | $ | 0.27 | | $ | 1.94 | |
| Dividends per common share | | | $ | 0.15 | | $ | 0.15 | | $ | 0.15 | | $ | 0.15 | | $ | 0.60 | |
| Average number of shares of common stock outstanding | | |
| Basic | | | 53,094 | | 53,206 | | 53,210 | | 53,258 | | 53,218 | |
| Diluted | | | 53,232 | | 53,408 | | 53,567 | | 53,648 | | 53,609 | |
| | | |
Year Ended December 31, 2009 | | |
| Sales and other revenues | | $ | 648,031 | | $ | 1,035,778 | | $ | 1,488,490 | | $ | 1,661,969 | | $ | 4,834,268 | | | $ | 648,030 | | $ | 1,035,778 | | $ | 1,488,491 | | $ | 1,661,969 | | $ | 4,834,268 | |
| Operating costs and expenses | | $ | 610,240 | | $ | 998,327 | | $ | 1,432,908 | | $ | 1,712,482 | | $ | 4,753,957 | | | $ | 610,239 | | $ | 998,327 | | $ | 1,432,909 | | $ | 1,712,482 | | $ | 4,753,957 | |
| Income from operations | | $ | 37,791 | | $ | 37,451 | | $ | 55,582 | | $ | (50,513 | ) | | $ | 80,311 | | |
| Income from continuing operations before income taxes | | $ | 33,922 | | $ | 29,258 | | $ | 43,676 | | $ | (63,053 | ) | | $ | 43,803 | | |
| Net income attributable to Holly Corporation stockholders | | $ | 21,964 | | $ | 14,621 | | $ | 23,503 | | $ | (40,555 | ) | | $ | 19,533 | | |
| Net income per share attributable to Holly Corporation stockholders — basic | | $ | 0.44 | | $ | 0.29 | | $ | 0.47 | | $ | (0.79 | ) | | $ | 0.39 | | |
| Net income per share attributable to. Holly Corporation stockholders — diluted | | $ | 0.44 | | $ | 0.29 | | $ | 0.47 | | $ | (0.79 | ) | | $ | 0.39 | | |
| Income (loss) from operations | | | $ | 37,791 | | $ | 37,451 | | $ | 55,582 | | $ | (50,513 | ) | | $ | 80,311 | |
| Income (loss) from continuing operations before income taxes | | | $ | 33,923 | | $ | 29,260 | | $ | 43,674 | | $ | (63,054 | ) | | $ | 43,803 | |
| Net income (loss) attributable to Holly Corporation stockholders | | | $ | 21,945 | | $ | 14,605 | | $ | 23,484 | | $ | (40,501 | ) | | $ | 19,533 | |
| Net income (loss) per share attributable to Holly Corporation stockholders—basic | | | $ | 0.44 | | $ | 0.29 | | $ | 0.47 | | $ | (0.79 | ) | | $ | 0.39 | |
| Net income (loss) per share attributable to Holly Corporation stockholders — diluted | | | $ | 0.44 | | $ | 0.29 | | $ | 0.47 | | $ | (0.79 | ) | | $ | 0.39 | |
| Dividends per common share | | $ | 0.15 | | $ | 0.15 | | $ | 0.15 | | $ | 0.15 | | $ | 0.60 | | | $ | 0.15 | | $ | 0.15 | | $ | 0.15 | | $ | 0.15 | | $ | 0.60 | |
| Average number of shares of common stock outstanding | | |
| Basic | | 50,042 | | 50,170 | | 50,244 | | 51,200 | | 50,418 | | | 50,042 | | 50,170 | | 50,244 | | 51,200 | | 50,418 | |
| Diluted | | 50,171 | | 50,226 | | 50,327 | | 51,380 | | 50,603 | | | 50,171 | | 50,226 | | 50,327 | | 51,380 | | 50,603 | |
NOTE 24: Subsequent Events
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 Frontier’s board of directors, Frontier shareholders will receive 0.4811 shares of Holly 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 Frontier’s stockholders in connection with the merger, (ii) adoption of the merger agreement by Frontier’s 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.
-113-
| | | | | | | | | | | | | | | | | | | | | |
| | | First | | | Second | | | Third | | | Fourth | | | | |
| | | Quarter | | | Quarter | | | Quarter | | | Quarter | | | Year | |
| | | (In thousands, except per share data) | |
| | | | | | | | | | | | | | | | | | | | | |
Year Ended December 31, 2008 | | | | | | | | | | | | | | | | | | | | |
| Sales and other revenues | | $ | 1,479,194 | | | $ | 1,741,654 | | | $ | 1,718,276 | | | $ | 921,233 | | | $ | 5,860,357 | |
| Operating costs and expenses | | $ | 1,470,050 | | | $ | 1,722,733 | | | $ | 1,636,305 | | | $ | 835,589 | | | $ | 5,664,677 | |
| Income from operations | | $ | 9,144 | | | $ | 18,921 | | | $ | 81,971 | | | $ | 85,644 | | | $ | 195,680 | |
| Income from continuing operations before income taxes | | $ | 13,692 | | | $ | 16,482 | | | $ | 76,484 | | | $ | 81,088 | | | $ | 187,746 | |
| Net income attributable to Holly Corporation stockholders | | $ | 8,649 | | | $ | 11,452 | | | $ | 49,899 | | | $ | 50,558 | | | $ | 120,558 | |
| Net income per share attributable to Holly Corporation stockholders — basic | | $ | 0.17 | | | $ | 0.23 | | | $ | 1.00 | | | $ | 1.02 | | | $ | 2.40 | |
| Net income per share attributable to Holly Corporation stockholders — diluted | | $ | 0.17 | | | $ | 0.23 | | | $ | 1.00 | | | $ | 1.01 | | | $ | 2.38 | |
| Dividends per common share | | $ | 0.15 | | | $ | 0.15 | | | $ | 0.15 | | | $ | 0.15 | | | $ | 0.60 | |
| Average number of shares of common stock outstanding | | | | | | | | | | | | | | | | | | | | |
| Basic | | | 51,165 | | | | 50,158 | | | | 49,717 | | | | 49,794 | | | | 50,202 | |
| Diluted | | | 51,515 | | | | 50,515 | | | | 50,032 | | | | 49,997 | | | | 50,549 | |
-114--109-
| | |
Item 9. | | Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
We have had no change in, or disagreement with, our independent registered public accountants on matters involving accounting and financial disclosure.
| | |
Item 9A. | | Item 9A. 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 Rule 13a-15(e)) as of the end of the period covered by this annual report on Form 10-K. 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 Commission’s 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 December 31, 2009.2010.
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.
See Item 8 for “Management’s Report on its Assessment of the Company’s Internal Control Over Financial Reporting” and “Report of the Independent Registered Public Accounting Firm.”
| | |
Item 9B. | | Item 9B. Other Information |
There have been no events that occurred in the fourth quarter of 20092010 that would need to be reported on Form 8-K that have not previously been reported.
PART III
| | |
Item 10. | | Item 10. Directors, Executive Officers and Corporate Governance |
The information required by Items 401, 405, 406 and 407(c)(3), (d)(4) and d(5) of Regulation S-K in response to this item is set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 5, 201012, 2011 and is incorporated herein by reference.
New York Stock Exchange Certification
In 2009,2010, Matthew P. Clifton, as our Chief Executive Officer, provided to the New York Stock Exchange the annual CEO certification regarding our compliance with the New York Stock Exchange’s corporate governance listing standards.
| | |
Item 11. | | Item 11. Executive Compensation |
The information required by ItemItems 402 and 407(e)(4) and (e)(5) of Regulation S-K in response to this item is set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 5, 201012, 2011 and is incorporated herein by reference.
-115--110-
| | |
Item 12. | | Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
The equity compensation plan information required by Item 201(d) and the information required by Item 403 of Regulation S-K in response to this item is set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 5, 201012, 2011 and is incorporated herein by reference.
| | |
Item 13. | | Item 13. Certain Relationships, Related Transactions and Director Independence |
The information required by Item 404 of Regulation S-K in response to this item is set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 5, 201012, 2011 and is incorporated herein by reference.
| | |
Item 14. | | Item 14. Principal Accountant Fees and Services |
The information required by Item 9(e) of Schedule 14A in response to this item is set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 5, 201012, 2011 and is incorporated herein by reference.
-116--111-
PART IV
| | |
Item 15. | | Item 15. Exhibits and Financial Statement Schedules |
(a) Documents filed as part of this report
| (1) | | (1) Index to Consolidated Financial Statements |
| | | | | |
| | | Page in | |
| | | Form 10-K | |
| | | | |
| Report of Independent Registered Public Accounting Firm | | | 7574 | |
| | | | | |
Consolidated Balance Sheets at December 31, 20092010 and 20082009 | | | 7675 | |
| | | | | |
Consolidated Statements of Income for the years ended December 31, 2010, 2009 2008 and 20072008 | | | 7776 | |
| | | | | |
Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 2008 and 20072008 | | | 7877 | |
| | | | | |
Consolidated Statements of Equity for the years ended December 31, 2010, 2009 2008 and 20072008 | | | 7978 | |
| | | | | |
Consolidated Statements of Comprehensive Income for the years ended December 31, 2010, 2009 2008 and 20072008 | | | 8079 | |
| | | | | |
| Notes to Consolidated Financial Statements | | | 8180 | |
| (2) | | Index to Consolidated Financial Statement Schedules |
| |
| | | All schedules are omitted since the required information is not present or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements or notes thereto. |
| |
| (3) | | Exhibits |
| |
| | | | SeeThe Exhibit Index to Exhibits on pages 114 to 120 to 125.of this Annual Report on Form 10-K lists the exhibits that are filed or furnished, as applicable, as part of this Annual Report on Form 10-K. |
-117--112-
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| | | | | |
| | HOLLY CORPORATION
(Registrant)
| |
| | /s/ Matthew P. Clifton | |
| | Matthew P. Clifton | |
| | Chief Executive Officer | |
|
Date: February 26, 201025, 2011
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and as of the date indicated.
| | | | | |
| Signature | | Capacity | | Date |
| | | |
| |
/s/ Matthew P. Clifton Matthew P. Clifton | | Chief Executive Officer and
Chairman of the Board | | February 26, 201025, 2011 |
| | | | | |
/s/ Bruce R. Shaw Bruce R. Shaw | | Senior Vice President and Chief
Financial Officer
(Principal (Principal Financial Officer) | | February 26, 201025, 2011 |
| | | | | |
/s/ Scott C. Surplus Scott C. Surplus | | Vice President and Controller
(Principal Accounting Officer) | | February 26, 201025, 2011 |
| | | | | |
/s/ Denise C. McWatters Denise C. McWatters | | Vice President, General
Counsel and Secretary | | February 26, 201025, 2011 |
| | | | | |
/s/ Buford P. Berry Buford P. Berry | | Director | | February 26, 201025, 2011 |
| | | | | |
/s/ Leldon E. Echols Leldon E. Echols | | Director | | February 26, 201025, 2011 |
| | | | | |
/s/ Marcus R. HickersonRobert G. McKenzie Marcus R. Hickerson | | Director | | February 26, 201025, 2011 |
| | | | | |
/s/ Robert G. McKenzieRobert G. McKenzie | | Director | | February 26, 2010 |
| | | | |
/s/ Thomas K. Matthews, IIThomas K. Matthews, II | | Director | | February 26, 2010 |
| | | | |
/s/ Jack P. Reid Jack P. Reid | | Director | | February 26, 201025, 2011 |
| | | | | |
| /s/ Paul T. StoffelPaul T. Stoffel | | Director | | February 26, 201025, 2011 |
| | | | | |
Paul T. Stoffel/s/ Tommy A. ValentaTommy A. Valenta | | Director | | February 25, 2011 |
-118--113-
HOLLY CORPORATION
INDEX TO EXHIBITS
Exhibits are numbered to correspond to the exhibit table
in Item 601 of Regulation S-K
| | | | | |
| Exhibit | | |
| Number | | Description |
| | | | | |
| 2.1 | | | Asset Sale and Purchase Agreement, dated October 19, 2009, by and between Holly Refining & Marketing-Tulsa LLC, HEP Tulsa LLC and Sinclair Tulsa Refining Company (incorporated by reference to Exhibit 2.1 of Registrant’s Current Report on Form 8-K filed October 21, 2009, File No. 1-03876). |
| | | | | |
| 2.2 | | | Amendment No. 1 to Asset Sale and Purchase Agreement, dated December 1, 2009, by and between Holly Refining & Marketing-Tulsa LLC, HEP Tulsa LLC and Sinclair Tulsa Refining Company (incorporated by reference to Exhibit 2.1 of Registrant’s Current Report on Form 8-K filed December 7, 2009, File No. 1-03876). |
| | | | | |
| 2.3 | | | Asset Sale and Purchase Agreement, dated as of April 15, 2009, by and between Holly Refining & Marketing-Midcon, L.L.C. and Sunoco, Inc. (R&M) (incorporated by reference to Exhibit 2.1 of Registrant’s Current Report on Form 8-K filed April 16, 2009, File No. 1-03876). |
| | | | | |
| 3.1 | 3.1+ | | Restated Certificate of Incorporation of the Registrant, as amended (incorporated by reference to Exhibit 3(a), of Amendment No. 1Holly Corporation, dated December 13, 1988 to Registrant’s Annual Report on Form 10-K for its fiscal year ended July 31, 1988, File No. 1-3876).March 10, 2010. |
| | | | | |
| 3.2 | | | Certificate of Amendment to the Restated Certificate of Incorporation of Holly Corporation, adopted May 26, 2004 (incorporated by reference to Exhibit 3.2 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2008, File No. 1-3876). |
| | | | |
| 3.3 | | | Certificate of Amendment to the Restated Certificate of Incorporation of Holly Corporation, adopted May 29, 2007 (incorporated by reference to Exhibit 3.3 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2008, File No. 1-3876). |
| | | | |
| 3.4 | | | By-Laws of Holly Corporation, as amended and restateddated December 22, 2005 (incorporated by reference to Exhibit 3.2.2 of Registrant’s Current Report on Form 8-K filed December 22, 2005, File No. 1-3876). |
| |
| 4.1 | | | Registration Rights and Transfer Restrictions Agreement, dated October 19, 2009 by and between Holly Corporation and Sinclair Tulsa Refining Company (incorporated by reference to Exhibit 4.1 of Registrant’s Current Report on Form 8-K filed October 20, 2009, File No. 1-03876). |
| | | | | |
| 4.2 | 4.1 | | Indenture, dated as of June 10, 2009, among Holly Corporation, the subsidiary guarantors named therein and U.S. Bank Trust National Association, as trustee, relating to Holly Corporation’s 9.875% Senior Notes due 2017 (includes the form of certificate for the notes issued thereunder) (incorporated by reference to Exhibit 4.1 of Registrant’s Form 8-K Current Report dated June 11, 2009, File No. 1-03876). |
| | | | | |
| 4.3 | 4.2 | | Indenture, dated February 28, 2005, among Holly Energy Partners, L.P. and Holly Energy Finance Corp., the Guarantors and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 of Holly Energy Partners, L.P.’s Current Report on Form 8-K filed March 4, 2005, File No. 1-32225). |
-119-
| | | | |
Exhibit | | |
Number | | Description |
| | | | |
| 4.4 | 4.3 | | Form of 6.25% Senior Note Due 2015 (included as Exhibit A to the Indenture included as Exhibit 4.1 hereto) (incorporated by reference to Exhibit 4.2 of Holly Energy Partners, L.P.’s Current Report on Form 8-K filed March 4, 2005, File No. 1-32225). |
| | | | | |
| 4.5 | 4.4 | | Form of Notation of Guarantee (included as Exhibit E to the Indenture included as Exhibit 4.1 hereto) (incorporated by reference to Exhibit 4.3 of Holly Energy Partners, L.P.’s Current Report on Form 8-K filed March 4, 2005, File No. 1-32225). |
| | | | | |
| 4.6 | 4.5 | | First Supplemental Indenture, dated March 10, 2005, among Holly Energy Partners, L.P., Holly Energy Finance Corp., the Guarantors identified therein, and U.S. Bank National Association (incorporated by reference to Exhibit 4.5 of Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2005, File No. 1-32225). |
-114-
| | | | |
| 4.7Exhibit | | |
| Number | | Description |
|
| 4.6 | | Second Supplemental Indenture, dated April 27, 2005, among Holly Energy Partners, L.P., Holly Energy Finance Corp., the Guarantors identified therein, and U.S. Bank National Association (incorporated by reference to Exhibit 4.6 of Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2005, File No. 1-32225). |
| | | | | |
| 4.8 | + 4.7 | | Third Supplemental Indenture, dated as of June 11, 2009, among Lovington-Artesia, L.L.C., Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors identified therein, and U.S. Bank National Association.Association (incorporated by reference to Exhibit 4.8 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2009, File No. 1-03876). |
| | | | | |
| 4.9 | + 4.8 | | Fourth Supplemental Indenture, dated as of June 29, 2009, among HEP SLC, LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors named therein, and U.S. Bank National Association.Association (incorporated by reference to Exhibit 4.9 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2009, File No. 1-03876). |
| | | | | |
| 4.10 | + 4.9 | | Fifth Supplemental Indenture, dated as of July 13, 2009, among HEP Tulsa LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors named therein, and U.S. Bank National Association.Association (incorporated by reference to Exhibit 4.10 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2009, File No. 1-03876). |
| | | | | |
| 4.11 | + 4.10 | | Sixth Supplemental Indenture, dated as of December 15, 2009, among Roadrunner Pipeline, L.L.C., Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors named therein, and U.S. Bank National Association.Association (incorporated by reference to Exhibit 4.11 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2009, File No. 1-03876). |
| | | |
| 4.11 | | Seventh Supplemental Indenture, dated April 14, 2010, among Holly Energy Storage- Tulsa LLC, Holly Energy Storage-Lovington LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors, and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 of Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2010, File No. 1-32225). |
| | |
| 10.14.12 | | Eighth Supplemental Indenture, dated June 4, 2010, among HEP Operations LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors, and U.S. Bank National Association (incorporated by reference to Exhibit 4.2 of Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2010, File No. 1-32225). |
| | |
| 4.13 | | Indenture, dated March 10, 2010, among Holly Energy Partners, L.P., Holly Energy Finance Corp. and each of the guarantors party thereto and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 of Holly Energy Partners, L.P.’s Current Report on Form 8-K filed March 11, 2010, File No. 1-32225). |
| | |
| 4.14 | | First Supplemental Indenture, dated April 14, 2010, among Holly Energy Storage-Tulsa LLC, Holly Energy Storage-Lovington LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors, and U.S. Bank National Association (incorporated by reference to Exhibit 4.3 of Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2010, File No. 1-32225). |
| | |
| 4.15 | | Second Supplemental Indenture, dated June 4, 2010, among HEP Operations LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors, and U.S. Bank National Association (incorporated by reference to Exhibit 4.4 of Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2010, File No. 1-32225). |
-115-
| | |
| Exhibit | | |
| Number | | Description |
|
| 10.1 | | Option Agreement, dated January 31, 2008, by and among Holly Corporation, Holly UNEV Pipeline Company, Navajo Pipeline Co., L.P., Holly Logistic Services, L.L.C., HEP Logistics Holdings, L.P., Holly Energy Partners, L.P., HEP Logistics GP, L.L.C. and Holly Energy Partners — Operating, L.P. (incorporated by reference to Exhibit 10.1 of Registrant’s Current Report on Form 8-K filed February 5, 2008, File No. 1-03876). |
| | | |
| 10.2+ | | First Amendment to Option Agreement, dated February 11, 2010, by and among Holly Corporation, Holly UNEV Pipeline Company, Navajo Pipeline Co., L.P., Holly Logistic Services, L.L.C., HEP Logistics Holdings, L.P., Holly Energy Partners, L.P., HEP Logistics GP, L.L.C. and Holly Energy Partners — Operating, L.P. |
| | |
| 10.2 | 10.3 | | Amended and Restated Intermediate Pipelines Agreement, dated as of June 1, 2009, by and among Holly Corporation, Navajo Refining Company, L.L.C., Holly Energy Partners, L.P., Holly Energy Partners — Operating, L.P., HEP Pipeline, L.L.C., Lovington-Artesia, L.L.C., HEP Logistics Holdings, L.P., Holly Logistic Services, L.L.C. and HEP Logistics GP, L.L.C. (incorporated by reference to Exhibit 10.2 of Holly Energy Partners, L.P.’s Form 8-K Current Report dated June 5, 2009, File No. 1-32225). |
| | | |
| 10.4+ | | Amendment to Amended and Restated Intermediate Pipelines Agreement, dated December 9, 2010, among Navajo Refining Company, L.L.C., Holly Energy Partners, L.P., Holly Energy Partners — Operating, L.P., HEP Pipeline, L.L.C., Lovington-Artesia, L.L.C., HEP Logistics Holdings, L.P., Holly Logistic Services, L.L.C., and HEP Logistics GP, L.L.C. |
| | |
| | 10.310.5+ | | 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. |
| | |
| 10.6 | | Tulsa Equipment and Throughput Agreement, dated as of August 1, 2009, between Holly Refining & Marketing — Tulsa LLC and HEP Tulsa LLC (incorporated by reference to Exhibit 10.3 of Holly Energy Partners L.P.’s Form 8-K Current Report dated August 6, 2009, File No. 1-32225). |
-120-
| | | | |
Exhibit | | |
Number | | Description |
| | | | |
| | 10.410.7+ | | Amendment to Tulsa Equipment and Throughput Agreement, dated December 9, 2010, among Holly Refining & Marketing — Tulsa LLC and HEP Tulsa LLC. |
| | |
| 10.8+ | | 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. |
| | |
| 10.9 | | Tulsa Purchase Option agreement, dated as of August 1, 2009, between Holly Refining & Marketing — Tulsa LLC and HEP Tulsa LLC (incorporated by reference to Exhibit 10.4 of Holly Energy Partners L.P.’s Form 8-K Current Report dated August 6, 2009, File No. 1-32225). |
| | | | | |
| 10.5 | 10.10 | | Amended and Restated Crude Pipelines and Tankage Agreement, dated as of December 1, 2009, by and among Navajo Refining Company, L.L.C., Holly Refining & Marketing Company — Woods Cross, Holly Refining & Marketing Company, Holly Energy Partners-Operating, L.P., HEP Pipeline, L.L.C. and HEP Woods Cross, L.L.C. (incorporated by reference to Exhibit 10.8 of Holly Energy Partners, L.P.’s Current Report on Form 8-K dated December 7, 2009, File No. 1-32225). |
-116-
| | | | |
| 10.6Exhibit | | |
| Number | | Description |
|
| 10.11 | | Amended and Restated Refined Product Pipelines and Terminals Agreement, dated as of December 1, 2009, by and among Navajo Refining Company, L.L.C., Holly Refining & Marketing Company — Woods Cross, Holly Energy Partners-Operating, L.P., HEP Pipeline Assets, Limited Partnership, HEP Pipeline, L.L.C., HEP Refining Assets, L.P., HEP Refining, L.L.C., HEP Mountain Home, L.L.C. and HEP Woods Cross, L.L.C. (incorporated by reference to Exhibit 10.9 of Holly Energy Partners, L.P.’s Current Report on Form 8-K dated December 7, 2009, File No. 1-32225). |
| | | | | |
| 10.710.12+ | | | Third AmendedAssignment and Assumption Agreement (Amended and Restated Omnibus Agreement, dated as of DecemberRefined Product Pipelines and Terminals Agreement), effective January 1, 2009, by2011, among Navajo Refining Company, L.L.C., Holly Refining & Marketing-Woods Cross and among Holly Corporation, Holly Energy Partners, L.P., and certain of their respective subsidiaries (incorporated by reference to Exhibit 10.3 of Holly Energy Partners, L.P.’s Current Report on Form 8-K dated December 7, 2009, File No. 1-32225).Refining & Marketing Company LLC. |
| | | | | |
| 10.8 | 10.13 | | Pipeline Throughput Agreement, dated as of December 1, 2009, by and between Navajo Refining Company, L.L.C. and Holly Energy Partners-Operating, L.P. (incorporated by reference to Exhibit 10.4 of Holly Energy Partners, L.P.’s Current Report on Form 8-K dated December 7, 2009, File No. 1-32225). |
| | | |
| 10.14+ | | 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. |
| | |
| 10.910.15 | | | First Amended and Restated Pipelines, Tankage and Loading Rack Throughput Agreement (Tulsa East), dated December 1, 2009March 31,2010, by and betweenamong Holly Refining & Marketing-Tulsa, LLC, HEP Tulsa LLC and Holly Refining & Marketing-TulsaEnergy Storage-Tulsa LLC (incorporated by reference to Exhibit 10.1 of Registrant’s Current Report on Form 8-K Current Report dated December 7, 2009,filed April 6, 2010, File No. 1-03876). |
| | | |
| 10.16 | | Amendment to First Amended and Restated Pipelines, Tankage and Loading Rack Throughput Agreement (Tulsa East), dated June 11, 2010, by and between Holly Refining & Marketing-Tulsa LLC, HEP Tulsa LLC and Holly Energy Storage-Tulsa LLC (incorporated by reference to Exhibit 10.1 of Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2010, File No. 1-32225). |
| | |
| 10.1010.17+ | | 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. |
| | |
| 10.18 | | Indemnification Proceeds and Payments Allocation Agreement, dated December 1, 2009, by and between HEP Tulsa LLC and Holly Refining & Marketing-Tulsa LLC (incorporated by reference to Exhibit 10.2 of Registrant’s Form 8-K Current Report dated December 7, 2009, File No. 1-03876). |
| | | |
| 10.19 | | Pipeline Systems Operating Agreement, dated February 8, 2010, by and among Navajo Refining Company, L.L.C., Lea Refining Company, Woods Cross Refining Company, L.L.C., Holly Refining & Marketing — Tulsa LLC. and Holly Energy Partners-Operating, L.P. (incorporated by reference to Exhibit 10.1 of Holly Energy Partners, L.P.’s Current Report on Form 8-K filed February 9, 2010, File No. 1-32225). |
| | |
| 10.20 | 10.11 | First Amendment to Pipeline Systems Operating Agreement, dated March 31, 2010, by and among Navajo Refining Company, L.L.C, Lea Refining Company, Woods Cross Refining Company, L.L.C, Holly Refining & Marketing-Tulsa, LLC and Holly Energy Partners-Operating, L.P. (incorporated by reference to Exhibit 10.5 of Registrant’s Current Report on Form 8-K filed April 6, 2010, File No. 1-03876). |
-117-
| | |
Lease and AccessExhibit | | |
| Number | | Description |
|
| 10.21 | | Loading Rack Throughput Agreement (Lovington), dated December 1, 2009March 31, 2010, by and between HEP Tulsa LLCNavajo Refining Company, L.L.C. and Holly Refining & Marketing-TulsaEnergy Storage-Lovington LLC (incorporated by reference to Exhibit 10.310.2 of Registrant’s Current Report on Form 8-K Current Report dated December 7, 2009,filed April 6, 2010, File No. 1-03876). |
| | | |
| 10.22 | | Fourth Amended and Restated Omnibus Agreement, dated March 31, 2010, by and among Holly Corporation, Holly Energy Partners, L.P. and certain of their respective subsidiaries (incorporated by reference to Exhibit 10.3 of Registrant’s Current Report on Form 8-K filed April 6, 2010, File No. 1-03876). |
| | |
| 10.23 | 10.12 | * First Amended and Restated Lease and Access Agreement (East Tulsa), dated March 31, 2010, by and among Holly Refining & Marketing-Tulsa, LLC, HEP Tulsa LLC and Holly Energy Storage-Tulsa LLC (incorporated by reference to Exhibit 10.4 of Registrant’s Current Report on Form 8-K filed April 6, 2010, File No. 1-03876). |
| | |
| 10.24* | | Holly Corporation Stock Option Plan — Asas adopted at the Annual Meeting of Stockholders of Holly Corporation on December 13, 1990 (incorporated by reference to Exhibit 4(i) of Registrant’s Annual Report on Form 10-K for its fiscal year ended July 31, 1991, File No. 1-3876)1-03876). |
| | | | | |
| 10.13 | * 10.25* | | Holly Corporation Long-Term Incentive Compensation Plan as amended and restated on May 24, 2007 as approved at the annual meetingAnnual Meeting of stockholdersStockholders of Holly Corporation on May 24, 2007 (incorporated by reference to Exhibit 10.4 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2008, File No. 1-3876)1-03876). |
-121-
| | | | |
Exhibit | | |
Number | | Description |
| | | | |
| 10.14 | * 10.26* | | Amendment No. 1 to the Holly Corporation Long-Term Incentive Compensation Plan, as amended and restated on May 24, 2007 (incorporated by reference to Exhibit 10.5 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2008, File No. 1-3876)1-03876). |
| | | | | |
| 10.15 | * 10.27* | | Holly Corporation — Supplemental Payment Agreement for 2001 Service as Director (incorporated by reference to Exhibit 10.19 of Registrant’s Annual Report on Form 10-K for its fiscal year ended July 31, 2002, File No. 1-3876)1-03876). |
| | | | | |
| 10.16 | * 10.28* | | Holly Corporation — Supplemental Payment Agreement for 2002 Service as Director (incorporated by reference to Exhibit 10.20 of Registrant’s Annual Report on Form 10-K for its fiscal year ended July 31, 2002, File No. 1-3876)1-03876). |
| | | | | |
| 10.17 | * 10.29* | | Holly Corporation — Supplemental Payment Agreement for 2003 Service as Director (incorporated by reference to Exhibit 10.2 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended January 31, 2003, File No. 1-3876)1-03876). |
| | | | | |
| 10.18 | * | | Form of Executive Restricted Stock Agreement [five-year term vesting form] (incorporated by reference to Exhibit 10.4 of Registrant’s Current Report on Form 8-K filed November 4, 2004, File No. 1-3876). |
| | | | |
| 10.19 | * | | Form of Executive Restricted Stock Agreement [five-year term and performance vesting form] (incorporated by reference to Exhibit 10.5 of Registrant’s Current Report on Form 8-K filed November 4, 2004, File No. 1-3876). |
| | | | |
| 10.20 | * 10.30* | | Form of Performance Share Unit Agreement (incorporated by reference to Exhibit 10.1 of Registrant’s Current Report on
Form 8-K filed January 12, 2007, File No. 1-3876)1-03876). |
| | | | | |
| 10.21 | 10.31* | | First Amendment to Performance Share Unit Agreement (incorporated by reference to Exhibit 10.16 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2008, File No. 1-3876)1-03876). |
| | | | | |
| 10.22 | 10.32* | | Holly Corporation Change in Control Agreement Policy (incorporated by reference to Exhibit 10.1 of Registrant’s Current Report on Form 8-K filed February 20, 2008, File No. 1-3876)1-03876). |
| | | | | |
| 10.23 | 10.33* | | Holly Corporation Employee Form of Change in Control Agreement (incorporated by reference to Exhibit 10.2 of Registrant’s Current Report on Form 8-K filed February 20, 2008, File No. 1-3876)1-03876). |
-118-
| | | | |
| 10.24Exhibit | | |
| Number | | Description |
|
| 10.34* | | Holly Energy Partners, L.P. Employee Form of Change in Control Agreement (incorporated by reference to Exhibit 10.3 of Registrant’s Current Report on Form 8-K filed February 20, 2008, File No. 1-3876)1-03876). |
| | | | | |
| 10.25 | * 10.35* | | Form of Executive Restricted Stock Agreement (incorporated by reference to Exhibit 10.2 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2009)2009, File No. 1-03876). |
| | | | | |
| 10.26 | * 10.36* | | Form of Employee Restricted Stock Agreement (incorporated by reference to Exhibit 10.3 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2009)2009, File No. 1-03876). |
| | | | | |
| 10.27 | * 10.37* | | Form of Director Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.4 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2009)2009, File No. 1-03876). |
-122-
| | | | |
Exhibit | | |
Number | | Description |
| | | | |
| 10.28 | * 10.38* | | Form of Form of Performance Share Unit Agreement (incorporated by reference to Exhibit 10.5 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2009)2009, File No. 1-03876). |
| | | | | |
| 10.2910.39* | | | AmendedForm of Executive Restricted Stock Agreement [time and Restated Credit Agreement dated March 14, 2008, between Holly Corporation, Bank of America, N.A., as administrative agent and L/C issuer, PNC Bank, National Association and Guaranty Bank, as co-documentation agents, Union Bank of California, N.A. and Compass Bank, as co-syndication agents, and certain other lenders from time to time party theretoperformance based vesting] (incorporated by reference to Exhibit 10.1 of Registrant’s Current Report on Form 8-K filed March 20, 2008, File No. 1-3876). |
| | | | |
| 10.30 | | | Reaffirmation and Assumption Agreement dated March 14, 2008, among Holly Corporation, the subsidiaries identified therein, the additional grantors identified therein and Bank of America, N.A. (adding additional grantors under the Guaranty and Collateral Agreement included as Exhibit 10.31 below) (incorporated by reference to Exhibit 10.22 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2008, File No. 1-3876). |
| | | | |
| 10.31 | | | Guarantee and Collateral Agreement, dated July 1, 2004, among Holly Corporation and certain of its Subsidiaries in favor of Bank of America, N.A., as administrative agent (incorporated by reference to Exhibit 10.210.7 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004,March 31, 2010, File No. 1-3876)1-03876). |
| | | |
| 10.40* | | Executive Restricted Stock Agreement, dated March 12, 2010, by and between Holly Corporation and Matthew P. Clifton (incorporated by reference to Exhibit 10.8 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2010, File No. 1-03876). |
| | |
| 10.3210.41* | | Executive Restricted Stock Agreement, dated March 12, 2010, by and between Holly Corporation and David L. Lamp (incorporated by reference to Exhibit 10.9 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2010, File No. 1-03876). |
| | |
| 10.42* | | Form of Employee Restricted Stock Agreement [time based vesting] (incorporated by reference to Exhibit 10.10 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2010, File No. 1-03876). |
| | |
| 10.43 | | Second Amended and Restated Credit Agreement dated April 7, 2009, by and among Holly Corporation and Bank of America, N.A., as administrative agent, swing line lender, and L/C issuer, UBS Loan Finance LLC and U.S. Bank National Association, as co-documentation agents, Union Bank of California, N.A. and Compass Bank, as syndication agents, and certain other lenders from time to time party thereto (incorporated by reference to Exhibit 10.1 of Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009, File No. 1-03876). |
| | | | | |
| 10.33 | + 10.44 | | Confirmation of Commitments [reflects increases in commitments on November 3, 2009 and December 4, 2009 under the Second Amended and Restated Credit Agreement filed as(incorporated by reference to Exhibit 10.35 to this10.33 of Registrant’s Annual Report on Form 10-K]10-K for the fiscal year ended December 31, 2009, File No. 1-03876). |
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| | |
| Exhibit | | |
| Number | | Description |
|
| 10.45 | | First Amendment to Second Amended and Restated Credit Agreement, dated May 6, 2010, by and among Holly Corporation, as the borrower, the Guarantors party thereto, Bank of America, N.A., as administrative agent, and each of the financial institutions parties thereto as lenders (incorporated by reference to Exhibit 10.1 of Registrant’s Current Report on Form 8-K filed with May 11, 2010, File No. 1-03876). |
| | | |
| 10.46 | | Reaffirmation and Assumption Agreement, dated March 14, 2008, among Holly Corporation, the subsidiaries identified therein, the additional grantors identified therein and Bank of America, N.A. (adding additional grantors under the Guaranty and Collateral Agreement included as Exhibit 10.49 below) (incorporated by reference to Exhibit 10.22 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2008, File No. 1-03876). |
| | |
| 10.3410.47 | | Guarantee and Collateral Agreement, dated July 1, 2004, among Holly Corporation and certain of its Subsidiaries in favor of Bank of America, N.A., as administrative agent (incorporated by reference to Exhibit 10.2 of Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004, File No. 1-03876). |
| | |
| 10.48 | | First Amendment to Guarantee and Collateral Agreement and Reaffirmation and Assumption Agreement, dated April 7, 2009, by and among Holly Corporation and certain of its subsidiaries, in favor of Bank of America, N.A., as administrative agent, for certain other lenders from time to time party to the Second Amended and Restated Credit Agreement dated April 7, 2009 (incorporated by reference to Exhibit 10.5 of Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, File No. 1-03876). |
| | | |
| 10.49 | | Amendment No. 2 to the Guarantee and Collateral Agreement, dated as of May 6, 2010, among Holly Corporation, each Subsidiary of the Holly Corporation from time to time party thereto and Bank of America, N.A. as administrative agent (incorporated by reference to Exhibit 10.2 of Registrant’s Current Report on Form 8-K filed May 11, 2010, File No. 1-03876). |
| | |
| 10.35 | 10.50 | | Amended and Restated Credit Agreement, dated August 27, 2007, between Holly Energy Partners — Operating, L.P., Union Bank of California, N.A., as administrative agent, issuing bank and sole lead arranger, Bank of America, N.A., as syndication agent, Guaranty Bank, as documentation agent 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 October 31, 2007, File No. 1-32225). |
| | | | | |
| 10.36 | 10.51 | | Agreement and Amendment No. 1 to Amended and Restated Credit Agreement, dated February 25, 2008, between Holly Energy Partners — Operating, L.P., Union Bank of California, N.A., as administrative agent, issuing bank and sole lead arranger and certain other lenders (incorporated by reference to Exhibit 10.1 of Holly Energy Partners’ Current Report on Form 8-K filed February 27, 2008, File No. 1-32225). |
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| | | | |
Exhibit | | |
Number | | Description |
| | | | |
| 10.37 | 10.52 | | Amendment No. 2 to Amended and Restated Credit Agreement, dated September 8, 2008, between Holly Energy Partners — Operating, L.P., certain of its subsidiaries acting as guarantors, Union Bank of California, N.A., as administrative agent, issuing bank and sole lead arranger and certain other lenders (incorporated by reference to Exhibit 10.11 of Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q filed October 31, 2008, File No. 1-32225). |
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| | | | |
| 10.38Exhibit | | |
| Number | | Description |
|
| 10.53 | | Amended and Restated Pledge Agreement, dated August 27, 2007, between Holly Energy Partners — Operating, L.P., certain of its subsidiaries, and Union Bank of California, N.A., as administrative agent (entered into in connection with the Amended and Restated Credit Agreement) (incorporated by reference to Exhibit 10.12 of Holly Energy Partners, L.P.’s Annual Report on Form 10-K filed February 17, 2009, File No. 1-32225). |
| | | | | |
| 10.39 | 10.54 | | Amended and Restated Guaranty Agreement, dated August 27, 2007, between Holly Energy Partners — Operating, L.P., certain of its subsidiaries, and Union Bank of California, N.A., as administrative agent (entered into in connection with the Amended and Restated Credit Agreement) (incorporated by reference to Exhibit 10.13 of Holly Energy Partners, L.P.’s Annual Report on Form 10-K filed February 17, 2009, File No. 1-32225). |
| | | | | |
| 10.40 | 10.55 | | Amended and Restated Security Agreement, dated August 27, 2007, between Holly Energy Partners — Operating, L.P., certain of its subsidiaries, and Union Bank of California, N.A., as administrative agent (entered into in connection with the Amended and Restated Credit Agreement) (incorporated by reference to Exhibit 10.14 of Holly Energy Partners, L.P.’s Annual Report on Form 10-K filed February 17, 2009, File No. 1-32225). |
| | | | | |
| 10.41 | 10.56 | | Form of Mortgage, Deed of Trust, Security Agreement, Assignment of Rents and Leases, Fixture Filing and Financing Statement (for purposes of granting security interests in real property in connection with the Amended and Restated Credit Agreement) (incorporated by reference to Exhibit 10.15 of Holly Energy Partners, L.P.’s Annual Report on Form 10-K filed February 17, 2009, File No. 1-32225). |
| | | | | |
| 10.42 | * 10.57* | | Form of Indemnification Agreement entered into with directors and officers of Holly Corporation (incorporated by reference to Exhibit 10.1 of Registrant’s Current Report on Form 8-K filed December 13, 2006, File No. 1-3876)1-03876). |
| | | | | |
| 21.1 | + 21.1+ | | Subsidiaries of Registrant. |
| | | | | |
| 23.1 | + 23.1+ | | Consent of Independent Registered Public Accounting Firm. |
| | | | | |
| 31.1 | + 31.1+ | | Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
| 31.2 | + 31.2+ | | Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
| 32.1 | + 32.1+ | | Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
| 32.2 | + 32.2+ | | Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002. |
| | | |
| 101++ | | The following financial information from Registrant’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010, 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 Equity, (v) Consolidated Statements of Comprehensive Income, and (vi) Notes to the Consolidated Financial Statements (tagged as blocks of text). |
| | |
| + | | Filed herewith. |
|
| ++ | | Furnished electronically herewith. |
| |
| * | | Constitutes management contracts or compensatory plans or arrangements. |
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